Vol. 76 Monday, 

No. 152 August 8, 2011 

Book 2 of 2 Books 

Pages 48207–48712 

Part II 

Environmental Protection Agency 

40 CFR Parts 51, 52, 72 et al. 

Federal Implementation Plans: Interstate Transport of Fine Particulate 

Matter and Ozone and Correction of SIP Approvals; Final Rule 


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48208 Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

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

[EPA–HQ–OAR–2009–0491; FRL–9436–8] 

RIN 2060–AP50 

Federal Implementation Plans: 

Interstate Transport of Fine Particulate 

Matter and Ozone and Correction of 

SIP Approvals 

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 NAAQS by 

the deadlines established in the Clean 

Air Act (CAA or Act). The FIPs may not 

fully eliminate the prohibited emissions 

from certain states with respect to the 

1997 ozone NAAQS for two remaining 

downwind areas and EPA is committed 

to identifying any additional required 

upwind emission reductions and taking 

any necessary action in a future 

rulemaking. In this action, EPA is also 

modifying its prior approvals of certain 

State Implementation Plan (SIP) 

submissions to rescind any statements 

that the submissions in question satisfy 

the interstate transport requirements of 

the CAA or that EPA’s approval of the 

SIPs affects our authority to issue 

interstate transport FIPs with respect to 

the 1997 fine particulate and 1997 

ozone standards for 22 states. EPA is 

also issuing a supplemental proposal to 

request comment on its conclusion that 

six additional states significantly affect 

downwind states’ ability to attain and 

maintain compliance with the 1997 

ozone NAAQS. 

DATES: This final rule is effective on 

October 7, 2011. 

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 http://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 

http://www.regulations.gov or in hard 

copy at the EPA Docket Center, EPA 

West, Room B102, 1301 Constitution 

Avenue, NW., Washington, DC. The 

Public Reading Room is open from 

8:30 a.m. to 4:30 p.m., Monday through 

Friday, excluding legal holidays. The 

telephone number for the Public 

Reading Room is (202) 566–1744, and 

the telephone number for the Air Docket 

is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: For 

general questions concerning this 

action, please contact Ms. Meg Victor, 

Clean Air Markets Division, Office of 

Atmospheric Programs, Mail Code 

6204J, Environmental Protection 

Agency, 1200 Pennsylvania Avenue, 

NW., Washington, DC 20460; telephone 

number: (202) 343–9193; fax number: 

(202) 343–2359; 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. 

AQAT Air Quality Assessment Tool 

ARP Acid Rain Program 

BART Best Available Retrofit Technology 

BACT Best Available Control Technology 

CAA or Act Clean Air Act 

CAIR Clean Air Interstate Rule 

CAMx Comprehensive Air Quality Model 

with Extensions 

CBI Confidential Business Information 

CCR Coal Combustion Residuals 

CEM Continuous Emissions Monitoring 

CENRAP Central Regional Air Planning 

Association 

CFR Code of Federal Regulations 

DEQ Department of Environmental Quality 

DSI Dry Sorbent Injection 

EGU Electric Generating Unit 

FERC Federal Energy Regulatory 

Commission 

FGD Flue Gas Desulfurization 

FIP Federal Implementation Plan 

FR Federal Register 

EPA U.S. Environmental Protection Agency 

GHG Greenhouse Gas 

GW Gigawatts 

Hg Mercury 

ICR Information Collection Request 

IPM Integrated Planning Model 

km Kilometers 

lb/mmBtu Pounds Per Million British 

Thermal Unit 

LNB Low-NOX Burners 

MACT Maximum Achievable Control 

Technology 

MATS Modeled Attainment Test Software 

μg/m 3 Micrograms Per Cubic Meter 

MSAT Mobile Source Air Toxics 

MOVES Motor Vehicle Emission Simulator 

NAAQS National Ambient Air Quality 

Standards 

NBP NOX Budget Trading Program 

NEI National Emission Inventory 

NESHAP National Emissions Standards for 

Hazardous Air Pollutants 

NOX Nitrogen Oxides 

NODA Notices of Data Availability 

NSPS New Source Performance Standard 

NSR New Source Review 

OFA Overfire Air 

OSAT Ozone Source Apportionment 

Technique 

OTAG Ozone Transport Assessment Group 

ppb Parts Per Billion 

PM2.5 Fine Particulate Matter, Less Than 2.5 

Micrometers 

PM10 Fine and Coarse Particulate Matter, 

Less Than 10 Micrometers 

PM Particulate Matter 

ppm Parts Per Million 

PUC Public Utility Commission 

RIA Regulatory Impact Analysis 

SCR Selective Catalytic Reduction 

SIP State Implementation Plan 

SMOKE Sparse Matrix Operator Kernel 

Emissions 

SNCR Selective Non-catalytic Reduction 

SO2 Sulfur Dioxide 

SOX Sulfur Oxides, Including Sulfur 

Dioxide (SO2) and Sulfur Trioxide (SO3) 

TAF Terminal Area Forecast 

TCEQ Texas Commission on Environmental 

Quality 

TIP Tribal Implementation Plan 

TLN3 Tangential Low NOX

TPY Tons Per Year 

TSD Technical Support Document 

WRAP Western Regional Air Partnership 

II. General Information 

A. Does this action apply to me? 

This rule affects EGUs, and regulates 

the following groups: 

Industry group NAICSa

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 


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the types of entities that EPA is aware 

of that could potentially be regulated. 

Other types of entities not listed in the 

table could also be regulated. To 

determine whether your facility would 

be regulated by the proposed rule, you 

should carefully examine the 

applicability criteria in proposed 

§§ 97.404, 97.504, and 97,604. 

B. How is the preamble organized? 

I. Preamble Glossary of Terms and 

Abbreviations 

II. General Information 

A. Does this action apply to me? 

B. How is the preamble organized? 

III. Executive Summary 

IV. Legal Authority, Environmental Basis, 

and Correction of CAIR SIP Approvals 

A. EPA’s Authority for Transport Rule 

B. Rulemaking History 

C. Air Quality Problems and NAAQS 

Addressed 

1. Air Quality Problems and NAAQS 

Addressed 

2. FIP Authority for Each State and 

NAAQS Covered 

3. Additional Information Regarding CAA 

Section 110(a)(2)(D)(i)(I) SIPs for States 

in the Transport Rule Modeling Domain 

D. Correction of CAIR SIP Approvals 

V. Analysis of Downwind Air Quality and 

Upwind State Emissions 

A. Pollutants Regulated 

1. Background 

2. Which pollutants did EPA propose to 

control for purposes of PM2.5 and Ozone 

Transport? 

3. Comments and Responses 

B. Baseline for Pollution Transport 

Analysis 

C. Air Quality Modeling to Identify 

Downwind Nonattainment and 

Maintenance Receptors 

1. Emission Inventories 

2. Air Quality Basis for Identifying 

Receptors 

3. How did EPA project future 

nonattainment and maintenance for 

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

ozone? 

D. Pollution Transport From Upwind 

States 

1. Choice of Air Quality Thresholds 

2. Approach for Identifying Contributing 

Upwind States 

VI. Quantification of State Emission 

Reductions Required 

A. Cost and Air Quality Structure for 

Defining Reductions 

1. Summary 

2. Background 

B. Cost of Available Emission Reductions 

(Step 1) 

1. Development of Annual NOX and 

Ozone-Season NOX Cost Curves 

2. Development of SO2 Cost Curves 

3. Amount of Reductions That Could Be 

Achieved by 2012 and 2014 

C. Estimates of Air Quality Impacts (Step 

2) 

1. Development of the Air Quality 

Assessment Tool and Air Quality 

Modeling Strategy 

2. Utilization of AQAT to Evaluate Control 

Scenarios 

3. Air Quality Assessment Results 

D. Multi-Factor Analysis and 

Determination of State Emission Budgets 

1. Multi-Factor Analysis (Step 3) 

2. State Emission Budgets (Step 4) 

E. Approach to Power Sector Emission 

Variability 

1. Introduction to Power Sector Variability 

2. Transport Rule Variability Limits 

F. Variability Limits and State Emission 

Budgets: State Assurance Levels 

G. How the State Emission Reduction 

Requirements Are Consistent With 

Judicial Opinions Interpreting the Clean 

Air Act 

VII. FIP Program Structure to Achieve 

Reductions 

A. Overview of Air Quality-Assured 

Trading Programs 

B. Applicability 

C. Compliance Deadlines 

1. Alignment With NAAQS Attainment 

Deadlines 

2. Compliance and Deployment of 

Pollution Control Technologies 

D. Allocation of Emission Allowances 

1. Allocations to Existing Units 

2. Allocations to New Units 

E. Assurance Provisions 

F. Penalties 

G. Allowance Management System 

H. Emissions Monitoring and Reporting 

I. Permitting 

1. Title V Permitting 

2. New Source Review 

J. How the Program Structure Is Consistent 

With Judicial Opinions Interpreting the 

Clean Air Act 

VIII. Economic Impacts of the Transport Rule 

A. Emission Reductions 

B. The Impacts on PM2.5 and Ozone of the 

Final SO2 and NOX Strategy 

C. Benefits 

1. Human Health Benefit Analysis 

2. Quantified and Monetized Visibility 

Benefits 

3. Benefits of Reducing GHG Emissions 

4. Total Monetized Benefits 

5. How do the benefits in 2012 compare to 

2014? 

6. How do the benefits compare to the costs 

of this final rule? 

7. What are the unquantified and nonmonetized benefits of the Transport Rule 

emission reductions? 

D. Costs and Employment Impacts 

1. Transport Rule Costs and Employment 

Impacts 

2. End-Use Energy Efficiency 

IX. Related Programs and the Transport Rule 

A. Transition From the Clean Air Interstate 

Rule 

1. Key Differences Between the Transport 

Rule and CAIR 

2. Transition From the Clean Air Interstate 

Rule to the Transport Rule 

B. Interactions With NOX SIP Call 

C. Interactions With Title IV Acid Rain 

Program 

D. Other State Implementation Plan 

Requirements 

X. Transport Rule State Implementation 

Plans 

XI. Structure and Key Elements of Transport 

Rule Air Quality-Assured Trading 

Program Rules 

XII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

1. Consideration of Environmental Justice 

in the Transport Rule Development 

Process and Response to Comments 

2. Potential Environmental and Public 

Health Impacts Among Populations 

Susceptible or Vulnerable to Air 

Pollution 

3. Meaningful Public Participation 

4. Summary 

K. Congressional Review Act 

L. Judicial Review 

III. Executive Summary 

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

requires states to prohibit emissions that 

contribute significantly to 

nonattainment in, or interfere with 

maintenance by, any other state with 

respect to any primary or secondary 

NAAQS. In this final rule, EPA finds 

that emissions of SO2 and NOX in 27 

eastern, midwestern, and southern 

states contribute significantly to 

nonattainment or interfere with 

maintenance in one or more downwind 

states with respect to one or more of 

three air quality standards—the annual 

PM2.5 NAAQS promulgated in 1997, the 

24-hour PM2.5 NAAQS promulgated in 

2006, and the ozone NAAQS 

promulgated in 1997 (EPA uses the term 

‘‘states’’ to include the District of 

Columbia in this preamble). 

These emissions are transported 

downwind either as SO2 and NOX or, 

after transformation in the atmosphere, 

as fine particles or ozone. This final rule 

identifies emission reduction 

responsibilities of upwind states, and 

also promulgates enforceable FIPs to 

achieve the required emission 

reductions in each state through 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. 


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1This area is not currently designated as 

nonattainment for the 24-hour PM2.5 standard. EPA 

is portraying the receptors and counties in this area 

as a single 24-hour maintenance area based on the 

annual PM2.5 nonattainment designation of 

Chicago-Gary-Lake County, IL-IN. 

2The 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. 

3The 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. 

4This 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. 

5The five states addressed in the supplemental 

proposal for which EPA’s analysis identifies the 

state’s full reduction responsibility under section 

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

NAAQS are Iowa, Kansas, Michigan, Oklahoma, 

and Wisconsin. The one state addressed in the 

supplemental proposal for which EPA’s analysis 

identifies reductions that are necessary but may not 

be sufficient to satisfy section 110(a)(2)(D)(i)(I) with 

respect to the 1997 ozone NAAQS is Missouri. 

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

requires the elimination of upwind state 

emissions that significantly contribute 

to nonattainment or interfere with 

maintenance of a NAAQS in another 

state. Elimination of these upwind state 

emissions may not necessarily, in itself, 

fully resolve nonattainment or 

maintenance problems at downwind 

state receptors. Downwind states also 

have control responsibilities because, 

among other things, the Act requires 

each state to adopt enforceable plans to 

attain and maintain air quality 

standards. Indeed, states have put in 

place measures to reduce local 

emissions that contribute to 

nonattainment within their borders. 

Section 110(a)(2)(D)(i)(I) only requires 

the elimination of emissions that 

significantly contribute to 

nonattainment or interfere with 

maintenance of the NAAQS in other 

states; it does not shift to upwind states 

the responsibility for ensuring that all 

areas in other states attain the NAAQS. 

The reductions obtained through the 

Transport Rule will help all but a few 

downwind areas come into attainment 

with and maintain the 1997 annual 

PM2.5 NAAQS, the 2006 24-hour PM2.5

NAAQS, and the 1997 ozone NAAQS. 

With respect to the annual PM2.5

NAAQS, this rule finds that 18 states 

have SO2 and annual NOX emission 

reduction responsibilities, and this rule 

quantifies each state’s full emission 

reduction responsibility under section 

110(a)(2)(D)(i)(I). See Table III–1 for the 

list of these states. With these 

reductions, EPA projects that no areas 

will have nonattainment or maintenance 

concerns with respect to the annual 

PM2.5 NAAQS. 

With respect to the 24-hour PM2.5

NAAQS, this rule finds that 21 states 

have SO2 and annual NOX emission 

reduction responsibilities, and this rule 

quantifies each state’s full emission 

reduction responsibility under 

110(a)(2)(D)(i)(I). See Table III–1 for the 

list of these states. In all, this rule 

requires emission reductions related to 

interstate transport of fine particles in 

23 states. With these reductions, as 

discussed in section VI.D of this 

preamble, only one area (LibertyClairton) is projected to remain in 

nonattainment, and three other areas 

(Chicago,1 Detroit, and Lancaster) are 

projected to have remaining 

maintenance concerns for the 24-hour 

PM2.5 NAAQS. 

With respect to the 1997 ozone 

NAAQS, this rule finds that 20 states 

have ozone-season NOX emission 

reduction responsibilities. For 10 of 

these states this rule quantifies the 

state’s full emission reduction 

responsibility under section 

110(a)(2)(D)(i)(I).2 For 10 additional 

states, EPA quantifies in this rule the 

ozone-season NOX emission reductions 

that are necessary but may not be 

sufficient to eliminate all significant 

contribution to nonattainment and 

interference with maintenance in other 

states.3 See Table III–1 for the complete 

list of 20 states required to reduce 

ozone-season NOX emissions in this 

rule. With the Transport Rule 

reductions, only one area (Houston) is 

projected to remain in nonattainment, 

and one area (Baton Rouge) to have a 

remaining maintenance concern with 

respect to the 1997 ozone NAAQS. The 

10 states upwind of either of these two 

areas are the states for which additional 

reductions may be necessary to fully 

eliminate each state’s significant 

contribution to nonattainment and 

interference with maintenance, as 

discussed in section VI of this 

preamble.4

As discussed further below, EPA’s 

analysis also demonstrates that six 

additional states should be required to 

reduce ozone-season NOX emissions. 

EPA is issuing a supplemental proposal 

to request comment on requiring ozoneseason 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

On January 19, 2010, EPA proposed 

revisions to the 8-hour ozone NAAQS 

that the Agency had issued March 12, 

2008 (75 FR 2938); the Agency intends 

to finalize its reconsideration in the 

summer of 2011. EPA intends to 

propose a rule to address transport with 

respect to the reconsidered 2008 ozone 

NAAQS as expeditiously as possible 

after reconsideration is completed. EPA 

intends to include in that proposed rule 

requirements to address any remaining 

significant contribution to 

nonattainment and interference with 

maintenance with respect to the 1997 

ozone NAAQS for the states identified 

in this final rule, or the associated 

supplemental notice of proposed 

rulemaking, for which EPA was unable 

to fully quantify the emissions that must 

be prohibited to satisfy the requirements 

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

1997 ozone NAAQS. 

The Act requires EPA to conduct 

periodic reviews of each of the NAAQS. 

When NAAQS are set or revised, the 

CAA requires revision of SIPs to ensure 

the standards are met expeditiously and 

within relevant timetables in the Act. If 

more protective NAAQS are 

promulgated, in the case of pollutants 

for which interstate transport is 

important, additional emission 

reductions to address transported 

pollution may be required from the 

power sector, from other sectors, and 

from sources in additional states. EPA 

will act promptly to promulgate any 

future rules addressing transport with 

respect to revised NAAQS. 

The Transport Rule requires 

substantial near-term emission 

reductions in every covered state to 

address each state’s significant 

contribution to nonattainment and 

interference with maintenance 

downwind. This rule achieves these 

reductions through FIPs that regulate 

the power sector using air qualityassured trading programs whose 

assurance provisions ensure that 

necessary reductions will occur within 

every covered state. This remedy 

structure is substantially similar to the 

preferred trading remedy structure 

presented in the proposal. The 

Transport Rule’s air quality-assured 

trading approach will assure 


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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. 

environmental results in each state 

while providing market-based flexibility 

to covered sources through interstate 

trading. The final rule includes four air 

quality-assured trading programs: An 

annual NOX trading program, an ozoneseason 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, which 

commences January 1, 2014, increases 

the stringency of SO2 reductions in a 

number of states as discussed further 

below. 

EPA projects that with the Transport 

Rule, covered EGU will substantially 

reduce SO2, annual NOX and ozoneseason NOX emissions, as shown in 

Tables III–2 and III–3, below. This rule 

generally covers electric generating 

units that are fossil fuel-fired boilers 

and turbines producing electricity for 

sale, as detailed in section VII.B. 

EPA is promulgating the Transport 

Rule in response to the remand of the 

Clean Air Interstate Rule (CAIR) by the 

U.S. Court of Appeals for the District of 

Columbia Circuit (‘‘Court’’) in 2008. 

CAIR, promulgated May 12, 2005 (70 FR 

25162), required 29 states to adopt and 

submit revisions to their State 

Implementation Plans (SIPs) to 

eliminate SO2 and NOX emissions that 

contribute significantly to downwind 

nonattainment of the PM2.5 and ozone 

NAAQS promulgated in July 1997. CAIR 

covered a similar but not identical set of 

states as the Transport Rule. CAIR FIPs 

were promulgated April 26, 2006 (71 FR 

25328) to regulate electric generating 

units in the covered states and achieve 

the emission reduction requirements 

established by CAIR until states could 

submit and obtain approval of SIPs to 

achieve the reductions. 

In July 2008, the Court found CAIR 

and the CAIR FIPs unlawful. North 

Carolina v. EPA, 531 F.3d 896 (D.C. Cir. 

2008), modified on rehearing, North 

Carolina v. EPA, 550 F.3d 1176, 1178 

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

decision vacated CAIR. North Carolina, 

531 F.3d at 929–30. However, the Court 

subsequently remanded CAIR to EPA 

without vacatur because it found that 

‘‘allowing CAIR to remain in effect until 

it is replaced by a rule consistent with 

our opinion would at least temporarily 

preserve the environmental values 

covered by CAIR.’’ North Carolina, 550 

F.3d at 1178. The CAIR requirements 

have remained in place while EPA has 

developed the Transport Rule to replace 

them. 

EPA’s approach in the Transport Rule 

to measure and address each state’s 

significant contribution to downwind 

nonattainment and interference with 

maintenance is guided by and 

consistent with the Court’s opinion in 

North Carolina and addresses the flaws 

in CAIR identified by the Court therein. 

This final rule also responds to 

extensive public comments and 

stakeholder input received during the 

public comment periods in response to 

the proposal and subsequent Notices of 

Data Availability (NODAs). 

In this action, EPA both identifies and 

addresses emissions within states that 

significantly contribute to 

nonattainment or interfere with 

maintenance in other downwind states. 

In developing this rule, EPA used a 

state-specific methodology to identify 

emission reductions that must be made 

in covered states to address the CAA 

section 110(a)(2)(D)(i)(I) prohibition on 

emissions that significantly contribute 

to nonattainment or interfere with 

maintenance in a downwind state. EPA 

believes this methodology addresses the 

Court’s concern that the approach used 

in CAIR was insufficiently statespecific. EPA used detailed air quality 

analysis to determine whether a state’s 

contribution to downwind air quality 

problems is at or above specific 

thresholds. A state is covered by the 

Transport Rule if its contribution meets 

or exceeds one of those air quality 

thresholds and the Agency identifies, 

using a multi-factor analysis that takes 

into account both air quality and cost 

considerations, emissions within the 

state that constitute the state’s 

significant contribution to 

nonattainment and interference with 

maintenance with respect to the 1997 

ozone or the 1997 annual or 2006 

24-hour PM2.5 NAAQS. Section 

110(a)(2)(D)(i)(I) requires states to 

eliminate the emissions that constitute 

this ‘‘significant contribution’’ and 

‘‘interference with maintenance.’’ 6

In this final rule, EPA determined the 

emission reductions required from all 

upwind states to eliminate significant 

contribution to nonattainment and 

interference with maintenance with 

respect to the 1997 ozone, 1997 annual 

PM2.5, and 2006 24-hour PM2.5 NAAQS, 

using, in part, an assessment of modeled 

air quality in 2012 and 2014. EPA first 

identified the following two sets of 

downwind receptors: (1) Receptors that 

EPA projects will have nonattainment 

problems; and, (2) receptors that EPA 

projects may have difficulty maintaining 

the NAAQS based on historic variation 

in air quality. To identify areas that may 

have problems attaining or maintaining 

these air quality standards, EPA 

projected a suite of future air quality 

design values, based on measured data 

during the period 2003 through 2007. 

EPA used the average of these future 

design values to assess whether an area 

will be in nonattainment. EPA used the 

maximum projected future design value 

to assess whether an area may have 

difficulty maintaining the relevant 

NAAQS (i.e., whether an area has a 

reasonable possibility of being in 

nonattainment under adverse emission 

and weather conditions). Section V.C of 

this preamble details the Transport 

Rule’s approach to identify downwind 

nonattainment and maintenance areas. 

After identifying downwind 

nonattainment and/or maintenance 

areas, EPA next used air quality 

modeling to determine which upwind 

states are projected to contribute at or 

above threshold levels to the air quality 

problems in those areas. Section V.D 

details the choice of air quality 

thresholds and the approach to 

determine how much each upwind state 

contributes. States whose contributions 

meet or exceed the threshold levels 

were analyzed further, as detailed in 

section VI, to determine whether they 

significantly contribute to 

nonattainment or interfere with 

maintenance of a relevant NAAQS, and 

if so, the quantity of emissions that 

constitute their significant contribution 

and interference with maintenance. 

When EPA proposed this air-quality 

and cost-based multi-factor approach to 

identify emissions that constitute 

significant contribution to 

nonattainment and interference with 

maintenance from upwind states with 

respect to the 1997 ozone, annual PM2.5, 

and 2006 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-downwindstate linkages and using the air-quality 

and cost-based multi-factor approach to 

determine the quantity of emissions that 

each upwind state must eliminate, i.e., 

the state’s significant contribution to 

nonattainment and interference with 

maintenance, could serve as a precedent 

for quantifying upwind state emission 

reduction responsibilities with respect 


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7For 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. 

8This 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. 

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-bystate analysis of each upwind state’s 

significant contribution to 

nonattainment and interference with 

maintenance. Because each state’s 

budget is directly linked to this statespecific 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. 

In this rule, EPA is finalizing SO2 and 

annual NOX budgets for each state 

covered for the 24-hour and/or annual 

PM2.5 NAAQS and an ozone-season 

NOX budget for each state covered for 

the ozone NAAQS. A state’s emission 

budget is the quantity of emissions that 

will remain from covered units under 

the Transport Rule after elimination of 

significant contribution to 

nonattainment and interference with 

maintenance in an average year (i.e., 

before accounting for the inherent 

variability in power system 

operations).7

Baseline power sector emissions from 

a state can be affected by changing 

weather patterns, demand growth, or 

disruptions in electricity supply from 

other units or from the transmission 

grid. As a consequence, emissions could 

vary from year to year even in a state 

where covered sources have installed all 

controls and taken all measures 

necessary to eliminate the state’s 

significant contribution to 

nonattainment and interference with 

maintenance. As described in detail in 

sections VI and VII of this preamble, the 

Transport Rule accounts for the inherent 

variability in power system operations 

through ‘‘assurance provisions’’ based 

on state-specific variability limits which 

extend above the state budgets to form 

each state’s ‘‘assurance level.’’ The state 

assurance levels take into account the 

inherent variability in baseline 

emissions from year to year. The final 

Transport Rule FIPs will implement 

assurance provisions starting in 2012 as 

discussed in section VII, below. 

The emission reduction requirements 

(i.e., the ‘‘remedy’’) EPA is promulgating 

in this rule respond to the Court’s 

concerns that in CAIR, EPA had not 

shown that the emission reduction 

requirements would get all necessary 

reductions within the state as required 

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

Transport Rule FIPs include assurance 

provisions specifically designed to 

ensure that no state’s emissions are 

allowed to exceed that specific state’s 

budget plus the variability limit (i.e., the 

state’s assurance level). 

Each state’s Transport Rule SO2, 

annual NOX, or ozone-season NOX

emission budget is composed of a 

number of emission allowances 

(‘‘allowances’’) equivalent to the 

tonnage of that specific state budget. 

Under the Transport Rule FIPs, EPA is 

distributing (‘‘allocating’’) allowances 

under each state’s budget to covered 

units in that state. In this rule, EPA 

analyzed each individual state’s 

significant contribution to 

nonattainment and interference with 

maintenance and calculated budgets 

that represent each state’s emissions 

after the elimination of those prohibited 

emissions in an average year. The 

methodology used to allocate 

allowances to individual units in a 

particular state has no impact on that 

state’s budget or on the requirement that 

the state’s emissions not exceed that 

budget plus the variability limit; the 

allocation methodology therefore has no 

impact on the rule’s ability to satisfy the 

statutory mandate of CAA section 

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

The Transport Rule’s approach to 

allocate emission allowances to existing 

units is based on historic heat-input 

data, as detailed in section VII.D of this 

preamble. The Transport Rule SO2, 

annual NOX, and ozone-season NOX

emission allowances each authorize the 

emission of one ton of SO2, annual NOX, 

or ozone-season NOX emissions, 

respectively, during a Transport Rule 

control period, and are the currency in 

the Transport Rule’s air quality-assured 

trading programs. As discussed in 

section IX.A.2 below, EPA is creating 

these Transport Rule allowances as 

distinct compliance instruments with 

no relation to allowances from the CAIR 

trading programs. EPA agrees with the 

general principle that it is desirable, 

where possible, to provide continuity 

under successive regulatory trading 

programs, for example through the 

carryover of allowances from one 

program into a subsequent one. 

However, EPA is promulgating the 

Transport Rule as a court-ordered 

replacement for (not a successor to) 

CAIR’s trading programs. In light of the 

specific circumstances of this case, 

including legal and technical issues 

discussed in Section IX.A.2 below, the 

final rule will not allow any carryover 

of banked SO2 or NOX allowances from 

the Title IV or CAIR trading programs. 

EPA will strongly consider 

administrative continuity of this rule’s 

trading programs under any future 

actions designed to address related 

problems of interstate transport of air 

pollution. A state may submit a SIP 

revision under which the state (rather 

than EPA) would determine allocations 

for one or more of the Transport Rule 

trading programs beginning with vintage 

year 2013 or later allowances.8 Section 

X of this preamble discusses the final 

rule’s provisions for SIP submissions in 

detail. 

Table III–1 lists states covered by the 

Transport Rule for PM2.5 and ozone. It 

also, with respect to PM2.5, identifies 

whether EPA determined the state was 

significantly contributing to 

nonattainment or interfering with 

maintenance of the 1997 annual PM2.5

NAAQS, the 2006 24-hour PM2.5

NAAQS, or both. As discussed below, 

the Transport Rule sorts the states 

required to reduce SO2 emissions due to 

their contribution to PM2.5 downwind 

into two groups of varying reduction 

stringency, with ‘‘Group 1’’ states 

subject to greater SO2 reduction 

stringency than ‘‘Group 2’’ states 

starting in 2014. Table III–1 also lists 

which SO2 Group each of the states is 

in. 


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9EPA updated its modeling platforms and 

modeling inputs in response to public comments 

received on the proposed Transport Rule and 

subsequent NODAs and performed other standard 

updates. 

TABLE III–1—STATES THAT SIGNIFICANTLY CONTRIBUTE TO NONATTAINMENT OR INTERFERE WITH MAINTENANCE OF A

NAAQS DOWNWIND IN THE FINAL TRANSPORT RULE

State 1997 Ozone 

NAAQS 

1997 Annual 

PM2.5 NAAQS 

2006 24-Hour 

PM2.5 NAAQS SO2 group 

Alabama ........................................................................................... X X X 2 

Arkansas .......................................................................................... X ............................ ............................ ............................

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

Georgia ............................................................................................ X X X 2 

Illinois ............................................................................................... X X X 1 

Indiana ............................................................................................. X X X 1 

Iowa ................................................................................................. ............................ X X 1 

Kansas ............................................................................................. ............................ ............................ X 2 

Kentucky .......................................................................................... X X X 1 

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

Maryland .......................................................................................... X X X 1 

Michigan ........................................................................................... ............................ X X 1 

Minnesota ........................................................................................ ............................ ............................ X 2 

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

Missouri ............................................................................................ ............................ X X 1 

Nebraska .......................................................................................... ............................ ............................ X 2 

New Jersey ...................................................................................... X ............................ X 1 

New York ......................................................................................... X X X 1 

North Carolina .................................................................................. X X X 1 

Ohio ................................................................................................. X X X 1 

Pennsylvania .................................................................................... X X X 1 

South Carolina ................................................................................. X X ............................ 2 

Tennessee ....................................................................................... X X X 1 

Texas ............................................................................................... X X ............................ 2 

Virginia ............................................................................................. X ............................ X 1 

West Virginia .................................................................................... X X X 1 

Wisconsin ......................................................................................... ............................ X X 1 

Number of States ............................................................................. 20 18 21 ............................

As explained in this preamble, EPA 

has improved and updated both steps of 

its significant contribution analysis. It 

updated and improved the modeling 

platforms and modeling inputs used to 

identify states with contributions to 

certain downwind receptors that meet 

or exceed specified thresholds. It also 

updated and improved its analysis for 

identifying any emissions within such 

states that constitute the state’s 

significant contribution to 

nonattainment or interference with 

maintenance. Therefore, the results of 

the analysis conducted for the final rule 

differ somewhat from the results of the 

analysis conducted for the proposal.9

With respect to the 1997 ozone 

NAAQS, the analysis EPA conducted for 

the proposal did not identify Wisconsin, 

Iowa and Missouri as states that 

significantly contribute to 

nonattainment or interfere with 

maintenance of the ozone NAAQS in 

another state. However, the analysis 

conducted for the final rule shows that 

emissions from these states do 

significantly contribute to 

nonattainment or interfere with 

maintenance of the ozone NAAQS in 

another state. EPA is not issuing FIPs 

with respect to the 1997 ozone NAAQS 

or finalizing ozone season NOX budgets 

for these states in this rule. EPA is 

publishing a supplemental notice of 

proposed rulemaking that will provide 

an opportunity for public comment on 

our conclusion that these states 

significantly contribute to 

nonattainment or interfere with 

maintenance of the 1997 ozone NAAQS. 

In the other direction, the analysis 

conducted for the proposal supported 

EPA’s conclusion at the time that 

Connecticut, Delaware, and the District 

of Columbia significantly contributed to 

nonattainment or interfered with 

maintenance with respect to the 1997 

ozone NAAQS, whereas the modeling 

for the final rule no longer supports that 

conclusion for those states. 

Additionally, the modeling conducted 

for the final rule identified two ozone 

maintenance receptors that were not 

identified in the modeling conducted 

for the proposal—Allegan County (MI) 

and Harford County (MD). Five states 

that EPA identified as significantly 

contributing to maintenance problems at 

the Allegan and/or Harford County 

receptors in the modeling for the final 

rule uniquely contribute to these 

receptors, i.e., absent these receptors the 

states would not be covered by the 

Transport Rule ozone-season program. 

The five states that uniquely contribute 

to these receptors are Iowa, Kansas, 

Michigan, Oklahoma, and Wisconsin. 

EPA is not issuing FIPs with respect to 

the 1997 ozone NAAQS or finalizing 

ozone-season NOX budgets for these 

states in this rule. EPA is publishing a 

supplemental notice of proposed 

rulemaking that will provide an 

opportunity for public comment on our 

conclusion that these states significantly 

contribute to nonattainment or interfere 

with maintenance of the 1997 ozone 

NAAQS. 

EPA did not change its methodology 

between the proposed Transport Rule 

and the final Transport Rule for 

identifying upwind states that 

significantly contribute to 

nonattainment or interfere with 

maintenance in other states; nor did 

EPA change its methodology for 

identifying receptors of concern with 

respect to maintenance of 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 


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to identify contributing states and 

receptors of concern. 

With respect to the annual PM2.5

NAAQS, the analysis EPA conducted for 

the proposal supported EPA’s 

conclusion that the states of Delaware, 

the District of Columbia, Florida, 

Louisiana, Minnesota, New Jersey, and 

Virginia were significantly contributing 

to nonattainment and interfering with 

maintenance of the annual PM2.5

NAAQS while the final rule’s analysis 

does not. Also, with respect to the 

24-hour PM2.5 NAAQS, the analysis 

conducted for the proposal supported 

EPA’s conclusion that the states of 

Connecticut, Delaware, the District of 

Columbia, and Massachusetts were 

significantly contributing to 

nonattainment or interfering with 

maintenance in other states while the 

analysis conducted for the final rule did 

not. 

In the proposal EPA also requested 

comment on whether Texas should be 

included in the Transport Rule for 

annual PM2.5. EPA’s analysis for the 

proposal showed that emissions in 

Texas would significantly contribute to 

nonattainment or interfere with 

maintenance of the annual PM2.5

NAAQS if Texas were not included in 

the rule for PM2.5. The proposal did not 

include an illustrative budget for Texas 

or illustrative allowance allocations. 

However, the budgets and allowance 

allocations provided for other states in 

the proposal were included solely to 

illustrate the result of applying EPA’s 

proposed methodology for quantifying 

significant contribution to the data EPA 

proposed to use. EPA provided an 

ample opportunity for comment on this 

methodology and on the data, including 

data regarding emissions from Texas 

sources, used in the significant 

contribution analysis. EPA received 

numerous comments on and corrections 

to Texas-specific data. The modeling 

conducted for the final rule 

demonstrates that Texas significantly 

contributes to nonattainment or 

interferes with maintenance of the 

annual PM2.5 NAAQS in another state. 

EPA provided a full opportunity for 

comment on whether Texas should be 

included in the rule for annual PM2.5, as 

well as on the methodology and data 

used for the significant contribution 

analysis for the final rule. EPA therefore 

believes its determination that Texas 

must be included in the rule for annual 

PM2.5 is a logical outgrowth of its 

proposal. 

With respect to the 24-hour PM2.5

NAAQS, the analysis EPA conducted for 

the proposal did not identify Texas as 

a state that significantly contributes to 

nonattainment or interferes with 

maintenance of 24-hour PM2.5 in 

another state. However, the analysis 

conducted for the final rule shows that 

emissions from Texas do significantly 

contribute to nonattainment of the 24- 

hour PM2.5 NAAQS in another state. 

EPA is not issuing a FIP for Texas with 

respect to the 24-hour PM2.5 NAAQS in 

this rule. However, EPA believes that 

the FIP for Texas with respect to the 

1997 annual PM2.5 NAAQS also 

addresses the emissions in Texas that 

significantly contribute to 

nonattainment and interference with 

maintenance of the 2006 24-hour PM2.5

NAAQS in another state. 

The final rule, however, does not 

cover the states of Connecticut, 

Delaware, the District of Columbia, 

Florida, Louisiana, or Massachusetts for 

annual or 24-hour PM2.5 as the analysis 

for the final rule does not support their 

inclusion. 

The Transport Rule FIPs require the 

23 states covered for purposes of the 24- 

hour and/or annual PM2.5 NAAQS to 

reduce SO2 and annual NOX emissions 

by specified amounts. The FIPs require 

the 20 states covered for purposes of the 

ozone NAAQS to reduce ozone-season 

NOX emissions by specified amounts. 

As discussed in detail in section VI, 

below, the 23 states covered for the 24- 

hour and/or annual PM2.5 NAAQS are 

grouped in two tiers reflecting the 

stringency of SO2 reductions required to 

eliminate that state’s significant 

contribution to nonattainment and 

interference with maintenance 

downwind. The more-stringent SO2 tier 

(‘‘Group 1’’) is comprised of the 16 

states indicated in Table III–1, above, 

and the less-stringent SO2 tier (‘‘Group 

2’’) is comprised of the 7 states 

identified in the table. The two SO2

trading programs are exclusive, i.e., a 

covered source in a Group 1 state may 

use only a Group 1 allowance for 

compliance, and likewise a source in a 

Group 2 state may use only a Group 2 

allowance for compliance. In Group 1 

states, the SO2 reduction requirements 

become more stringent in the second 

phase, which starts in 2014. 

In response to the Court’s opinion in 

North Carolina, EPA has coordinated 

the Transport Rule’s compliance 

deadlines with the NAAQS attainment 

deadlines that apply to the downwind 

nonattainment and maintenance areas. 

The Transport Rule requires that all 

significant contribution to 

nonattainment and interference with 

maintenance identified in this action 

with respect to the 1997 annual PM2.5

NAAQS and the 2006 24-hour PM2.5

NAAQS be eliminated by no later than 

2014, with an initial phase of reductions 

starting in 2012 to ensure that 

reductions are made as expeditiously as 

practicable and, consistent with the 

Court’s remand, to ‘‘preserve the 

environmental values covered by 

CAIR.’’ Sources must comply by January 

1, 2012 and January 1, 2014 for the first 

and second phases, respectively. 

With respect to the 1997 ozone 

NAAQS, the Transport Rule requires 

NOX reductions starting in 2012 to 

ensure that reductions are made as 

expeditiously as practicable to assist 

downwind state attainment and 

maintenance of the standard. Sources 

must comply by May 1, 2012. The 

Transport Rule’s compliance schedule 

and alignment with downwind NAAQS 

attainment deadlines are discussed in 

detail in section VII below. 

Table III–2 shows projected Transport 

Rule emissions compared to projected 

base case emissions, and Table III–3 

shows projected Transport Rule 

emissions compared to historical 

emissions (i.e., 2005 emissions), for the 

power sector in all Transport Rule 

states. The ozone-season NOX results 

shown in Tables III–2 and III–3 are 

based on analysis of the group of 26 

states that would be covered for the 

ozone-season program if EPA finalizes 

the supplemental proposal regarding 

ozone-season requirements for Iowa, 

Kansas, Michigan, Missouri, Oklahoma, 

and Wisconsin. 

TABLE III–2—PROJECTED SO2 AND NOX ELECTRIC GENERATING UNIT EMISSION REDUCTIONS IN COVERED STATES WITH

THE TRANSPORT RULE COMPARED TO BASE CASE WITHOUT TRANSPORT RULE OR CAIR ** 

[Million tons] 

2012 

Base case 

emissions 

2012 

Transport rule 

emissions 

2012 

Emission 

reductions 

2014 

Base case 

emissions 

2014 

Transport rule 

emissions 

2014 

Emission 

reductions 

SO2 ........................................................... 7.0 3.0 4.0 6.2 2.4 3.9 

Annual NOX ............................................. 1.4 1.3 0.1 1.4 1.2 0.2 


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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 **—Continued 

[Million tons] 

2012 

Base case 

emissions 

2012 

Transport rule 

emissions 

2012 

Emission 

reductions 

2014 

Base case 

emissions 

2014 

Transport rule 

emissions 

2014 

Emission 

reductions 

Ozone-Season NOX ................................. 0.7 0.6 0.1 0.7 0.6 0.1 

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

** As explained in section V.B, EPA’s base case projections for the Transport Rule assume that CAIR is not in place. 

Notes: The SO2 and annual NOX emissions 

in this table reflect EGUs in the 23 states 

covered by this rule for purposes of the 24- 

hour and/or annual PM2.5 NAAQS (Alabama, 

Georgia, Illinois, Indiana, Iowa, Kansas, 

Kentucky, Maryland, Michigan, Minnesota, 

Missouri, Nebraska, New Jersey, New York, 

North Carolina, Ohio, Pennsylvania, South 

Carolina, Tennessee, Texas, Virginia, West 

Virginia, and Wisconsin). The ozone-season 

NOX emissions reflect EGUs in the 20 states 

covered by this rule for purposes of the ozone 

NAAQS (Alabama, Arkansas, Florida, 

Georgia, Illinois, Indiana, Kentucky, 

Louisiana, Maryland, Mississippi, New 

Jersey, New York, North Carolina, Ohio, 

Pennsylvania, South Carolina, Tennessee, 

Texas, Virginia, and West Virginia) and the 

six states that would be covered for the ozone 

NAAQS if EPA finalizes its supplemental 

proposal (Iowa, Kansas, Michigan, Missouri, 

Oklahoma, and Wisconsin). 

TABLE III–3—PROJECTED SO2 AND NOX ELECTRIC GENERATING UNIT EMISSION REDUCTIONS IN COVERED STATES WITH

THE TRANSPORT RULE COMPARED TO 2005 ACTUAL EMISSIONS

[Million tons] 

2005 

Actual 

emissions 

2012 

Transport rule 

emissions 

2012 

Emission 

reductions 

from 2005 

2014 

Transport rule 

emissions 

2014 

Emission 

reductions 

from 2005 

SO2 ....................................................................................... 8.8 3.0 5.8 2.4 6.4 

Annual NOX ......................................................................... 2.6 1.3 1.3 1.2 1.4 

Ozone-Season 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. 

For annual PM2.5, the average 

reduction across all monitoring sites in 

covered states in 2014 is 1.41 microgram 

per meter cubed (μg/m3) and the greatest 

reduction at a single site is 3.60 μg/m3. 

For 24-hour PM2.5, the average reduction 

across all monitoring sites in covered 

states in 2014 is 4.3 μg/m3 and the 

greatest reduction at a single site is 11.6 

μg/m3. And finally, for 8-hour ozone, 

the average reduction across all 

monitoring sites in covered states in 

2014 is 0.3 parts per billion (ppb) and 

the greatest is 3.9 ppb. See section VIII 

for further information on air quality 

improvements. 

EPA estimated the Transport Rule’s 

costs and benefits, including effects on 

sensitive and vulnerable and 

environmental justice communities. 

Table III–4, below, summarizes some of 

these results. Further discussion of the 

results is provided in preamble section 

VIII, below, and in the Regulatory 

Impact Analysis (RIA). Estimates here 

are subject to uncertainties discussed 

further in the RIA. 

TABLE III–4.—SUMMARY OF ANNUAL BENEFITS, COSTS, AND NET BENEFITS OF THE FINAL TRANSPORT RULE IN 2014 

[Billions of 2007$] a

Description 

Transport rule remedy (billions of 2007 $) 

3% discount rate 7% discount rate 

Social costs ...................................................................................................................................... $0.81 ......................... $0.81. 

Total monetized benefits b ............................................................................................................... $120 to $280 ............. $110 to $250. 

Net benefits (benefits-costs) ............................................................................................................ $120 to $280 ............. $110 to $250. 

aAll estimates are for 2014, and are rounded to two significant figures. 


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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. 

As a result of updated analyses and in 

response to public comments, the final 

Transport Rule differs from the proposal 

in a number of ways. The differences 

between proposal and final rule are 

discussed throughout this preamble. 

Some key changes between proposal 

and final rule are that EPA: 

• Updated emission inventories 

(resulting in generally lower base case 

emissions). See section V.C. 

• Updated modeling and analysis 

tools (including improved alignment 

between air quality estimates and air 

quality modeling results). See sections V 

and VI. 

• Updated conclusions regarding 

which states significantly contribute to 

nonattainment or interfere with 

maintenance of the NAAQS in other 

states. See Table III–1 and sections V.D 

and VI. 

• Recalculated state budgets and 

variability limits, i.e., state assurance 

levels, based on updated modeling. See 

section VI. 

• Simplified variability limits for oneyear application only. See section VI.E. 

• Revised allocation methodology for 

existing and new units and revised new 

unit set-asides for new units in 

Transport Rule states and new units 

potentially locating in Indian country. 

See section VII.D. 

• Changed start of assurance 

provisions to 2012 and increased 

assurance provision penalties. See 

section VII.E. 

• Removed opt-in provisions. See 

section VII.B 

• Added provisions for full and 

abbreviated Transport Rule SIP 

revisions. See section X. 

EPA conducted substantial 

stakeholder outreach in developing the 

Transport Rule, starting with a series of 

‘‘listening sessions’’ in the spring of 

2009 with states, nongovernmental 

organizations, and industry. EPA 

docketed stakeholder-related materials 

in the Transport Rule docket (Docket ID 

No. EPA–HQ–OAR–2009–0491). The 

Agency conducted general 

teleconferences on the rule with tribal 

environmental professionals, conducted 

consultation with tribal governments, 

and hosted a webinar for communities 

and tribal governments. EPA continued 

to provide updates to regulatory 

partners and stakeholders through 

several conference calls with states as 

well as at conferences where EPA 

officials often made presentations. The 

Agency conducted additional 

stakeholder outreach during the public 

comment period. EPA responded to 

extensive public comments received 

during the public comment periods on 

the proposed rule and associated 

NODAs. 

This Transport Rule is one of a series 

of regulatory actions to reduce the 

adverse health and environmental 

impacts of the power sector. EPA is 

developing these rules to address 

judicial review of previous rulemakings 

and to issue rules required by 

environmental laws. Finalizing these 

rules will effectuate health and 

environmental protection mandated by 

Congress while substantially reducing 

uncertainty over the future regulatory 

obligations of power plants, which will 

assist the power sector in planning for 

compliance more cost effectively. The 

Agency is providing full opportunity for 

notice and comment for each rule. 

As discussed above, rules to address 

transport under revised NAAQS, 

including the reconsidered 2008 ozone 

NAAQS, may result in additional 

emission reduction requirements for the 

power sector. In addition, existing Clean 

Air Act rules establishing best available 

retrofit technology (BART) requirements 

and other requirements for addressing 

visibility and regional haze may also 

result in future state requirements for 

certain power plant emission reductions 

where needed. 

On May 3, 2011 (76 FR 24976), EPA 

proposed national emission standards 

for hazardous air pollutants from coaland 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 fuelfired EGUs under section 111(b). As 

discussed in the EPA-led public 

listening sessions during February and 

March 2011, EPA is preparing to 

propose innovative, cost-effective and 

flexible greenhouse gas (GHG) emissions 

performance standards under section 

111 for steam electric generating units, 

the largest U.S. source of greenhouse gas 

emissions. On April 20, 2011 (76 FR 

22174), EPA proposed requirements 

under section 316(b) of the Clean Water 

Act for existing power generating 

facilities, manufacturing and industrial 

facilities that withdraw more than two 

million gallons per day of water from 

waters of the U.S. and use at least 

twenty-five percent of that water 

exclusively for cooling purposes. On 

June 21, 2010 (75 FR 35128), the Agency 

proposed to regulate coal combustion 

residuals (CCRs) under the Resource 

Conservation and Recovery Act to 

address the risks from the disposal of 

CCRs generated from the combustion of 

coal at electric utilities and independent 

power producers. 

EPA will coordinate utility-related air 

pollution rules with each other and with 

other actions affecting the power sector 

including these rules from EPA’s Office 

of Water and its Office of Resource 

Conservation and Recovery to the extent 

consistent with legal authority in order 

to provide timely information needed to 

support regulated sources in making 

informed decisions. Use of a small 

number of air pollution control 

technologies, widely deployed, can 

assist with compliance for multiple 

rules. EPA also notes that the flexibility 

inherent in the allowance-trading 

mechanism included in the Transport 

Rule affords utilities themselves a 

degree of latitude to determine how best 

to integrate compliance with the 

emission reduction requirements of this 

rule and those of the other rules. EPA 

will pursue energy efficiency 

improvements in the use of electricity 

throughout the economy, along with 

other federal agencies, states and other 

groups, which will contribute to 

additional environmental and public 

health improvements while lowering 

the costs of realizing those 

improvements. 

IV. Legal Authority, Environmental 

Basis, and Correction of CAIR SIP 

Approvals 

A. EPA’s Authority for Transport Rule 

The statutory authority for this action 

is provided by the CAA, as amended, 42 

U.S.C. 7401 et seq. Section 110(a)(2)(D) 

of the CAA, often referred to as the 

‘‘good neighbor’’ provision of the Act, 

and requires states to prohibit certain 

emissions because of their impact on air 

quality in downwind states. 

Specifically, it requires all states, within 

3 years of promulgation of a new or 

revised NAAQS, to submit SIPs that 

prohibit certain emissions of air 

pollutants because of the impact they 

would have on air quality in other 

states. 42 U.S.C. 7410(a)(2)(D). This 

action addresses the requirement in 

section 110(a)(2)(D)(i)(I) regarding the 

prohibition of emissions within a state 

that will significantly contribute to 

nonattainment or interfere with 

maintenance of the NAAQS in any other 


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10As discussed in section III of this preamble, 

EPA is proposing to apply ozone-season NOX

requirements to additional states. If EPA finalizes 

that action as proposed, the total number of states 

covered by the Transport Rule FIPs would be 28. 

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 DC Circuit in Michigan, 213 F.3d 

663. CAIR, promulgated in 2005, was 

remanded by the DC 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 this section, EPA 

has authority to clarify the applicability 

of CAA requirements. In this action, 

among other things, EPA is clarifying 

the applicability of section 

110(a)(2)(D)(i)(I) by identifying SO2 and 

NOX emissions that must be prohibited 

pursuant to this section with respect to 

the PM2.5 NAAQS promulgated in 1997 

and 2006 and the 8-hour ozone NAAQS 

promulgated in 1997. 

Section 110(c)(1) requires the 

Administrator to promulgate a FIP at 

any time within 2 years after the 

Administrator finds that a state has 

failed to make a required SIP 

submission, finds a SIP submission to 

be incomplete or disapproves a SIP 

submission unless the state corrects the 

deficiency, and the Administrator 

approves the SIP revision, before the 

Administrator promulgates a FIP. 42 

U.S.C. 7410(c)(1). 

Tribes are not required to submit state 

implementation plans. However, as 

explained in EPA’s regulations outlining 

Tribal Clean Air Act authority, EPA is 

authorized to promulgate FIPs for 

Indian country as necessary or 

appropriate to protect air quality if a 

tribe does not submit and get EPA 

approval of an implementation plan. 

See 40 CFR 49.11(a); see also 42 U.S.C. 

section 7601(d)(4). 

Section 110(k)(6) of the CAA gives the 

Administrator authority, without any 

further submission from a state, to 

revise certain prior actions, including 

actions to approve SIPs, upon 

determining that those actions were in 

error. 

B. Rulemaking History 

The Transport Rule FIPs will limit the 

interstate transport of emissions of NOX

and SO2 within 27 states in the eastern, 

midwestern, and southern United States 

that affect the ability of downwind 

states to attain and maintain compliance 

with the 1997 and 2006 PM2.5 NAAQS 

and the 1997 ozone NAAQS.10 Prior to 

this Transport Rule, CAIR was EPA’s 

most recent regulatory action in a 

longstanding series of regulatory 

initiatives to address interstate transport 

of air pollution. The proposed Transport 

Rule preamble provides more 

information on EPA actions prior to 

CAIR (75 FR 45221–45225). 

CAIR, promulgated May 12, 2005 (70 

FR 25162), required 29 states to adopt 

and submit revisions to their SIPs to 

eliminate SO2 and NOX emissions that 

contribute significantly to downwind 

nonattainment of the PM2.5 and ozone 

NAAQS promulgated in 1997. The 

states covered by CAIR were similar but 

not identical to the states covered by the 

Transport Rule. The CAIR FIPs, 

promulgated April 26, 2006 (71 FR 

25328), regulated electric generating 

units in the covered states and achieved 

CAIR’s emission reduction requirements 

unless or until states had approved SIPs 

to achieve the required reductions. 

In July 2008, the DC Circuit Court 

found CAIR and the CAIR FIPs unlawful 

and vacated CAIR. North Carolina, 531 

F.3d at 929–30. However, the Court 

subsequently remanded CAIR to EPA 

without vacatur in order to ‘‘at least 

temporarily preserve the environmental 

values covered by CAIR.’’ North 

Carolina, 550 F.3d at 1178. CAIR 

requirements have remained in place 

and CAIR’s emission trading programs 

have operated while EPA developed 

replacement rules in response to the 

remand. 

By promulgating the Transport Rule 

FIPs, EPA is responding to the Court’s 

remand of CAIR and the CAIR FIPs and 

replacing those rules. The approaches 

EPA used in the Transport Rule to 

measure and address each state’s 

significant contribution to downwind 

nonattainment and interference with 

maintenance are guided by and 

consistent with the Court’s opinion in 

North Carolina and address the flaws in 

CAIR identified by the Court therein. 

By notice of proposed rulemaking 

(Federal Implementation Plans To 

Reduce Interstate Transport of Fine 

Particulate Matter and Ozone, 75 FR 

45210; August 2, 2010), EPA proposed 

the Transport Rule to identify and limit 

NOX and SO2 emissions within 32 states 

in the eastern, midwestern, and 

southern United States that affect the 

ability of downwind states to attain and 

maintain compliance with the 1997 and 

2006 PM2.5 NAAQS and the 1997 ozone 

NAAQS. EPA proposed to achieve the 

emission reductions under FIPs, which 

states may choose to replace by 

submitting SIPs for EPA approval. EPA 

proposed to limit emissions by 

regulating electric generating units in 

the 32 states with interstate emission 

trading programs and assurance 

provisions to ensure the required 

reductions occur in each covered state. 

EPA also requested comment on two 

alternative FIP remedies. 

EPA supplemented the Transport 

Rule record with additional information 

relevant to the rulemaking in three 

NODAs for which EPA requested 

comments: 

• Notice of Data Availability 

Supporting Federal Implementation 

Plans to Reduce Interstate Transport of 

Fine Particulate Matter and Ozone (75 

FR 53613; September 1, 2010). This 

NODA provided an updated database of 

unit-level characteristics of EGUs 

included in EPA modeling, an updated 

version of the power sector modeling 

platform EPA used to support the final 

rule, and other input assumptions and 

data EPA provided for public review 

and comment. 

• Notice of Data Availability 

Supporting Federal Implementation 

Plans To Reduce Interstate Transport of 

Fine Particulate Matter and Ozone: 

Revisions to Emission Inventories (75 

FR 66055; October 27, 2010). This 

NODA provided additional information 

relevant to the rulemaking, including 

updated emission inventory data for 

2005, 2012 and 2014 for several 

stationary and mobile source inventory 

components. 

• 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. 


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48218 Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations 

C. Air Quality Problems and NAAQS 

Addressed 

1. Air Quality Problems and NAAQS 

Addressed 

a. Fine Particles 

Fine particles are associated with a 

number of serious health effects 

including premature mortality, 

aggravation of respiratory and 

cardiovascular disease (as indicated by 

increased hospital admissions, 

emergency room visits, health-related 

absences from school or work, and 

restricted activity days), lung disease, 

decreased lung function, asthma attacks, 

and certain cardiovascular problems. In 

addition to effects on public health, fine 

particles are linked to a number of 

public welfare effects, including (1) 

Reduced visibility (haze) in scenic 

areas, (2) effects caused by particles 

settling on ground or water, such as: 

making lakes and streams acidic, 

changing the nutrient balance in coastal 

waters and large river basins, depleting 

the nutrients in soil, damaging sensitive 

forests and farm crops, and affecting the 

diversity of ecosystems, and (3) staining 

and damaging of stone and other 

materials, including culturally 

important objects such as statues and 

monuments. 

In 1997, EPA revised the NAAQS for 

PM to add new annual and 24-hour 

standards for fine particles, using PM2.5

as the indicator (62 FR 38652). These 

revisions established an annual 

standard of 15 μg/m3 and a 24-hour 

standard of 65 μg/m3. During 2006, EPA 

revised the air quality standards for 

PM2.5. The 2006 standards decreased the 

level of the 24-hour fine particle 

standard from 65 μg/m3 to 35 μg/m3, 

and retained the annual fine particle 

standard at 15 μg/m3. 

b. Ozone 

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

prolonged (6- to 8-hour) exposures to 

ambient ozone have been linked to a 

number of adverse health effects. At 

sufficient concentrations, short-term 

exposure to ozone can irritate the 

respiratory system, causing coughing, 

throat irritation, and chest pain. Ozone 

can reduce lung function and make it 

more difficult to breathe deeply. 

Breathing may become more rapid and 

shallow than normal, thereby limiting a 

person’s normal activity. Ozone also can 

aggravate asthma, leading to more 

asthma attacks that may require a 

doctor’s attention and the use of 

additional medication. Increased 

hospital admissions and emergency 

room visits for respiratory problems 

have been associated with ambient 

ozone exposures. Longer-term ozone 

exposure can inflame and damage the 

lining of the lungs, which may lead to 

permanent changes in lung tissue and 

irreversible reductions in lung function. 

A lower quality of life may result if the 

inflammation occurs repeatedly over a 

long time period (such as months, years, 

or a lifetime). There is also 

epidemiological evidence indicating a 

correlation between short-term ozone 

exposure and premature mortality. 

In addition to causing adverse health 

effects, ozone affects vegetation and 

ecosystems, leading to reductions in 

agricultural crop and commercial forest 

yields; reduced growth and survivability 

of tree seedlings; and increased plant 

susceptibility to disease, pests, and 

other environmental stresses (e.g., harsh 

weather). In 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 

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. 

In this action, EPA fully addresses, for 

the states covered by this rule, the 

requirements of CAA section 

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

standard of 15 μg/m3 and the 24-hour 

standard of 35 μg/m3. For the 1997 8- 

hour ozone standard of 0.08 ppm, EPA 

fully addresses the CAA section 

110(a)(2)(D)(i)(I) requirements for some 

states covered by this rule, but for the 

remaining states EPA is conducting 

further analysis to determine whether 

further requirements are needed, as 

discussed in section III of this preamble. 

This action does not address the CAA 

section 110(a)(2)(D)(i)(I) requirements 

for the revised ozone standards 

promulgated in 2008. These standards 

are currently under reconsideration. We 

are, however, actively conducting the 

technical analyses and other work 

needed to address interstate transport 

for the reconsidered ozone standard as 

soon as possible. We intend to issue as 

soon as possible a proposal to address 

the transport requirements with respect 

to the reconsidered standard. 

This action addresses these CAA 

transport requirements through 

reductions in annual emissions of SO2

and NOX, and through reductions in 

ozone-season NOX. The rationale for 

these reductions is discussed in detail 

later in the preamble. 

d. Public Comments 

EPA received comments on two issues 

related to the NAAQS regulated under 

the proposed FIPs. 

A number of commenters believed 

that EPA’s approach to ozone was 

inadequate, and that EPA should not 

have based the proposed requirements 

on the 1997 ozone NAAQS. These 

commenters cited EPA’s 2008 revision 

to the standard which lowered the 

standard to 75 ppb, and noted that 

EPA’s January 2010 proposal for 

reconsidered ozone NAAQS would, if 

finalized, further lower the primary 

NAAQS from 75 ppb to a value between 

60 and 70 ppb. Accordingly, many of 

the commenters believed that EPA 

should have considered the 75 ppb level 

to be the maximum possible value 

moving forward, and that EPA should 

have used a value no greater than 75 

ppb in its analysis. 

EPA agrees with commenters that 

EPA and states should address interstate 

transport with respect to the tighter 


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11The CAA provides that EPA is not relieved of 

its obligation to promulgate FIPs unless the state 

submits a SIP that corrects the deficiency and EPA 

approves the SIP. Nonetheless, in the preamble to 

the proposed rule, EPA indicated that for states not 

covered by CAIR which had 110(a)(2)(D)(i)(I) SIPs 

pending at the time of proposal, EPA would finalize 

the FIP only if EPA determined the submission was 

incomplete or disapproved the SIP submission. The 

only two states covered by this rule but not covered 

by CAIR are Kansas and Nebraska. Both Kansas and 

Nebraska are covered by this rule based only on 

their significant contribution to nonattainment or 

interference with maintenance of the 2006 PM2.5

NAAQS. EPA has not received a 110(a)(2)(D)(i)(I) 

submission from Nebraska with respect to the 

requirements of the 2006 PM2.5 NAAQS. EPA 

disapproved a SIP submission from Kansas with 

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

the 2006 PM2.5 NAAQS. 

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

issuing 20 FIPs to remedy SIP deficiencies relating 

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

ozone NAAQS. EPA is also issuing 18 FIPs to 

remedy SIP deficiencies relating to the 1997 PM2.5

NAAQS. Finally, EPA is issuing 21 FIPs to remedy 

SIP deficiencies relating to the 2006 PM2.5 NAAQS. 13The specific findings made and actions taken 

by EPA are described in greater detail in the TSD 

entitled ‘‘Status of CAA 110(a)(2)(D)(i)(I) SIPs.’’ 14States may also have received approval to 

expand the applicability of the CAIR NOX ozone 

season program to include all units subject to the 

NOX Budget Program, allow opt-ins, or provide for 

distribution of a Compliance Supplement Pool 

under the CAIR NOX (annual) program. 

15 ‘‘FIP clock’’ is a term used to describe EPA’s 

responsibility found in CAA Section 110(c)(1) to 

promulgate a FIP within 2 years after either: 

Finding that a state has not submitted a required 

SIP revision or that a submitted SIP revision is 

incomplete; or disapproving a SIP revision. 

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 

The CAA requires and authorizes EPA 

to promulgate each of the Federal 

Implementation Plans in this final rule. 

Section 110(c)(1) of the CAA requires 

the Administrator to promulgate a FIP at 

any time within 2 years after the 

Administrator takes one of three distinct 

actions: (1) She finds that a state has 

failed to make a required SIP 

submission; (2) she finds a SIP 

submission to be incomplete; or (3) she 

disapproves a SIP submission. Once the 

Administrator has taken one of these 

actions with respect to a specific state’s 

110(a)(2)(D)(i)(I) obligation for a specific 

NAAQS, she has a legal obligation to 

promulgate a FIP to correct the SIP 

deficiency within 2 years. EPA is 

relieved of the obligation to promulgate 

a FIP only if two events occur before the 

FIP is promulgated: (1) The state 

submits a SIP correcting the deficiency; 

and (2) the Administrator approves the 

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

For each FIP in this rule,12 EPA either 

has found that the state has failed to 

make a required 110(a)(2)(D)(i)(I) SIP 

submission, or has disapproved a SIP 

submission.13 In addition, EPA has 

determined, in each case, that there has 

been no approval by the Administrator 

of a SIP submission correcting the 

deficiency prior to promulgation of the 

FIP. EPA’s obligation to promulgate a 

FIP arose when the finding of failure to 

submit or disapproval was made, and in 

no case has it been relieved of that 

obligation. 

Some commenters argued that EPA 

was relieved of its obligation to 

promulgate FIPs when it approved the 

CAIR SIPs for certain states. As an 

initial matter, EPA notes that this 

argument applies only to EPA’s 

authority to promulgate FIPs with 

respect to the 1997 PM2.5 and/or 1997 

ozone NAAQS for a subset of states 

covered by the CAIR. It does not apply 

to EPA’s authority to promulgate FIPs 

for the 2006 PM2.5 NAAQS which was 

not addressed in CAIR. It also does not 

apply to EPA’s authority to promulgate 

FIPs for the 1997 ozone and 1997 PM2.5

NAAQS for states that remain subject to 

the CAIR FIPs, including the states that 

received EPA approval of abbreviated 

CAIR SIPs which allowed the states to 

allocate allowances while remaining 

subject to the CAIR FIPs.14

Further, the CAIR SIP approvals do 

not eliminate EPA’s obligation and 

authority to promulgate a FIP to address 

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

because the Court in North Carolina v. 

EPA, 531 F.3d 896 (D.C. Cir. 2008) 

found that compliance with CAIR does 

not satisfy the requirement that each 

state prohibit all emissions within the 

state that significantly contribute to 

nonattainment or interfere with 

maintenance in another state. The 

Court’s finding that CAIR was unlawful 

because it did not make measureable 

progress towards the statutory mandate 

of section 110(a)(2)(D)(i)(I) meant that 

the CAIR SIPs were not adequate to 

satisfy that mandate. The CAIR SIPs 

thus do not correct the SIP deficiencies 

identified in the 2005 findings of failure 

to submit. The SIPs remained in force 

for the limited purpose allowed by the 

Court—that is, to achieve interim 

reductions until EPA promulgated a rule 

to replace CAIR. Given the flaws the 

court identified with CAIR, EPA’s 

approval of a CAIR SIP does not relieve 

it of the obligation to promulgate FIPs 

created under section 110(c)(1) of the 

CAA. 

Further, to avoid any confusion, EPA 

has decided to correct, in this notice, 

the full CAIR SIP approvals for states 

covered by this rule and the CAA 

110(a)(2)(D)(i) SIP approvals for states 

covered by CAIR to rescind any 

statements suggesting that the SIP 

submissions satisfied or relieved states 

of the obligation to submit SIPs to 

satisfy the requirements of section 

110(a)(2)(D)(i)(I) or that EPA was 

relieved of its obligation and authority 

to promulgate FIPs under 

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

Some commenters further argued that 

states should be given additional time, 

following promulgation of the Transport 

Rule, to submit a SIP to meet the 

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

and that CAIR should remain in place 

in the meantime. Some commenters 

specifically suggested that EPA restart 

the ‘‘FIP clock’’ 15 to give states this 

additional time. EPA does not interpret 

the CAA as giving it authority to extend 

the deadline for SIP submissions or 

restart the FIP clock. And nothing in the 

Act requires EPA to give the states 

another opportunity, following 

promulgation of the Transport Rule, to 

promulgate a SIP before EPA 

promulgates a FIP. The plain language 

of section 110(a)(1) of the Act requires 

the submission of SIPs that meet the 

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

3 years after the promulgation of or 

revision of a primary NAAQS. See 42 

U.S.C. 7410(a)(1). Section 

110(a)(2)(D)(i)(I) SIPs for the 1997 ozone 

and PM2.5 NAAQS were due in 2000 

and 110(a)(2)(D)(i)(I) SIPs for the 2006 

PM2.5 NAAQS were due in 2009. While 

the statute gives EPA authority to 

prescribe a shorter period of time for 

states to make these SIP submissions, it 

does not give EPA authority to extend 

the 3-year deadline established by the 

Act. See 42 U.S.C. 7410(a)(1). The plain 

language of section 110(c)(1) of the Act, 

in turn, provides that EPA shall 

promulgate a FIP at any time within 2 

years after the Administrator makes a 

finding of failure to make a required SIP 


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submission of disapproves, in whole or 

in part, a SIP submission. See 42 U.S.C. 

7410(c)(1). EPA does not have authority 

to set aside the specific deadlines 

established in the statute, and neither 

provision allows for the deadlines to be 

extended or to run from promulgation 

by EPA of a rule to quantify the state’s 

specific obligations pursuant to section 

110(a)(2)(D)(i)(I). The Act does not 

require EPA to promulgate a rule or 

issue guidance regarding the specific 

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

in advance of the SIP submittal 

deadline, much less require EPA to 

promulgate such a rule a specific 

amount of time before the SIP submittal 

deadline. For these reasons, EPA has 

neither authority to alter the SIP 

submittal deadline nor authority to alter 

the statute provision regarding when 

EPA’s obligation to promulgate a FIP is 

triggered. 

Finally, EPA does not believe it 

would be appropriate, in light of the 

Court’s decision in North Carolina, to 

establish a lengthy transition period to 

the rule that will replace CAIR. The 

Court decision remanding CAIR without 

vacatur stressed the court’s conclusion 

that CAIR was deeply flawed and 

emphasized EPA’s obligation to remedy 

those flaws expeditiously. North 

Carolina, 550 F.3d 1176. Although the 

Court did not set a specific deadline for 

corrective action, the Court took care to 

note that the effect of its opinion would 

not be delayed ‘‘indefinitely’’ and that 

petitioners could bring a mandamus 

petition if EPA were to fail to modify 

CAIR in a manner consistent with its 

prior opinion. Id. Given the Court’s 

emphasis on remedying CAIR’s flaws 

expeditiously, EPA does not believe it 

would be appropriate to establish a 

lengthy transition period to the rule 

which is to replace CAIR. 

3. Additional Information Regarding 

CAA Section 110(a)(2)(D)(i)(I) SIPs for 

States in the Transport Rule Modeling 

Domain 

This final rule quantifies out-of-state 

contributions for the 38 states that are 

fully contained within the 12 kilometers 

(km) eastern U.S. modeling domain. 

EPA is making no specific finding for 

states that are not fully contained within 

the eastern 12 km modeling domain. 

EPA did not conduct a contribution 

analysis or make any specific finding for 

New Mexico, Colorado, Wyoming, and 

Montana since they are only partially 

contained within the 12 km modeling 

domain. With regard to the 1997 PM2.5

NAAQS and 2006 PM2.5 NAAQS, EPA 

believes that states that are included in 

this 38 state modeling domain will meet 

their section 110(a)(2)(D)(i)(I) 

obligations to address the ‘‘significant 

contribution’’ and ‘‘interference with 

maintenance’’ requirements by 

complying with the requirements in this 

rule. With regard to the 1997 ozone 

NAAQS, EPA believes that states that 

are included in this 38 state modeling 

domain will meet their section 

110(a)(2)(D)(i)(I) obligations to address 

the ‘‘significant contribution’’ and 

‘‘interference with maintenance’’ 

requirements by complying with the 

requirements in this rule, except for the 

10 states found to significantly 

contribute to nonattainment or 

interference of maintenance in either 

Houston or Baton Rouge (i.e., Alabama, 

Arkansas, Georgia, Illinois, Indiana, 

Kentucky, Louisiana, Mississippi, 

Tennessee, and Texas). States that are in 

the 38 state modeling domain, and that 

are not found to be contributing 

significantly to nonattainment or 

interfering with maintenance for any 

NAAQS evaluated in the modeling for 

the final rule, could rely on this analysis 

as technical support that their existing 

or future interstate transport SIP 

submittals are adequate to address the 

transport requirements of 

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

finds that South Carolina significantly 

contributes to nonattainment and 

interferes with maintenance of the 1997 

ozone NAAQS and the 1997 PM2.5

NAAQS in downwind states. The 

technical support for the rule does not 

show that South Carolina significantly 

contributes to nonattainment or 

interferes with maintenance of the 2006 

PM2.5 NAAQS in downwind states. EPA 

believes that South Carolina can make a 

negative declaration concluding that the 

state does not significantly contribute to 

nonattainment or interfere with 

maintenance in other states with regard 

to the 2006 PM2.5 NAAQS. 

D. Correction of CAIR SIP Approvals 

In this action, EPA is also correcting 

its prior approvals of CAIR related SIP 

submissions and CAA 110(a)(2)(D)(i) 

SIP submissions from Alabama, 

Arkansas, Connecticut, Florida, Georgia, 

Illinois, Indiana, Iowa, Kentucky, 

Louisiana, Maryland, Massachusetts, 

Minnesota, Mississippi, Missouri, New 

York, North Carolina, Ohio, 

Pennsylvania, South Carolina, Virginia 

and West Virginia to rescind any 

statements that the SIP submissions 

either satisfy or relieve the state of the 

obligation to submit a SIP to satisfy the 

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

with respect to the 1997 ozone and/or 

1997 PM2.5 NAAQS or any statements 

that EPA’s approval of the SIP 

submissions either relieve EPA of the 

obligation to promulgate a FIP or 

remove EPA’s authority to promulgate a 

FIP. This action is based on EPA’s 

determination that those SIP approvals 

were in error to the extent they provided 

explicitly or implicitly that compliance 

with CAIR satisfies the requirements of 

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

1997 ozone and 1997 PM2.5 NAAQS. 

The July 2008 decision of the DC Circuit 

held, among other things, that the CAIR 

rule did not ‘‘achieve[] something 

measureable toward the goal of 

prohibiting sources ‘within the State’ 

from contributing to nonattainment or 

interfering with maintenance in ‘any 

other State.’’’ North Carolina, 531 F.3d 

908; see also, e.g., id. at 916 (EPA not 

exercising its authority to make 

measureable progress towards the goals 

of section 110(a)(2)(D)(i)(I) because the 

emission budgets were insufficiently 

related to the statutory mandate). EPA’s 

actions to approve CAIR SIP submittals 

as satisfying the requirements of section 

110(a)(2)(D)(i)(I), based on the flawed 

determination in CAIR that compliance 

with CAIR satisfied those statutory 

requirements, were thus in error as were 

the separate actions taken to approve 

section 110(a)(2)(D)(i)(I) submissions 

that relied wholly or in part on CAIR. 

The approval for Alabama titled 

‘‘Approval and Promulgation of 

Implementation Plans; Alabama; Clean 

Air Interstate Rule’’ which is hereby 

corrected was originally published in 

the Federal Register on October 1, 2007 

(72 FR 55659). 

The approval for Arkansas titled 

‘‘Approval and Promulgation of 

Implementation Plans; Arkansas; Clean 

Air Interstate Rule Nitrogen Oxides 

Ozone Season Trading Program’’ which 

is hereby corrected was originally 

published in the Federal Register on 

September 26, 2007 (72 FR 54556). 

The approval for Connecticut titled 

‘‘Approval and Promulgation of Air 

Quality Implementation Plans; 

Connecticut; State Implementation Plan 

Revision to Implement the Clean Air 

Interstate Rule’’ which is hereby 

corrected was originally published in 

the Federal Register on January 24, 

2008 (73 FR 4105) and the approval for 

Connecticut titled ‘‘Approval and 

Promulgation of Air Quality 

Implementation Plans; Connecticut; 

Interstate Transport of Pollution’’ which 

is hereby corrected was originally 

published in the Federal Register on 

May 7, 2008 (73 FR 25516). 

The approval for Florida titled 

‘‘Approval and Promulgation of 

Implementation Plans; Florida; Clean 

Air Interstate Rule’’ which is hereby 

corrected was originally published in 

the Federal Register on October 12, 

2007 (72 FR 58016). 


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The approval for Georgia titled 

‘‘Approval and Promulgation of 

Implementation Plans; Georgia; Clean 

Air Interstate Rule’’ which is hereby 

corrected was originally published in 

the Federal Register on October 9, 2007 

(72 FR 57202). 

The approval for Illinois titled 

‘‘Approval of Implementation Plans of 

Illinois: Clean Air Interstate Rule’’ 

which is hereby corrected was originally 

published in the Federal Register on 

October 16, 2007 (72 FR 58528). 

The approval for Indiana titled 

‘‘Limited Approval of Implementation 

Plans of Indiana: Clean Air Interstate 

Rule’’ which is hereby corrected was 

originally published in the Federal 

Register on October 22, 2007 (72 FR 

59480) and the approval for Indiana 

titled ‘‘Approval and Promulgation of 

Air Quality Implementation Plans; 

Indiana; Clean Air Interstate Rule’’ 

which is hereby corrected was originally 

published in the Federal Register on 

November 29, 2010 (75 FR 72956). 

The approval for Iowa titled 

‘‘Approval and Promulgation of 

Implementation Plans; Iowa; Clean Air 

Interstate Rule’’ which is hereby 

corrected was originally published in 

the Federal Register on August 6, 2007 

(72 FR 43539) and the approval for Iowa 

titled ‘‘Approval and Promulgation of 

Implementation Plans; Iowa; Interstate 

Transport of Pollution’’ which is hereby 

corrected was originally published in 

the Federal Register on March 8, 2007 

(72 FR 10380). 

The approval for Kentucky titled 

‘‘Approval of Implementation Plans of 

Kentucky: Clean Air Interstate Rule’’ 

which is hereby corrected was originally 

published in the Federal Register on 

October 4, 2007 (72 FR 56623). 

The approval for Louisiana titled 

‘‘Approval and Promulgation of 

Implementation Plans; Louisiana; Clean 

Air Interstate Rule Sulfur Dioxide 

Trading Program’’ which is hereby 

corrected was originally published in 

the Federal Register on July 20, 2007 

(72 FR 39741) and the approval for 

Louisiana titled ‘‘Approval and 

Promulgation of Implementation Plans; 

Louisiana; Clean Air Interstate Rule 

Nitrogen Oxides Trading Program’’ 

which is hereby corrected was originally 

published in the Federal Register on 

September 28, 2007 (72 FR 55064). 

The approval for Maryland titled 

‘‘Approval and Promulgation of Air 

Quality Implementation Plans; 

Maryland; Clean Air Interstate Rule’’ 

which is hereby corrected was originally 

published in the Federal Register on 

October 30, 2009 (74 FR 56117). 

The approval for Massachusetts titled 

‘‘Approval and Promulgation of Air 

Quality Implementation Plans; 

Massachusetts; State Implementation 

Plan Revision to Implement the Clean 

Air Interstate Rule’’ which is hereby 

corrected was originally published in 

the Federal Register on December 3, 

2007 (72 FR 67854). 

The approval for Minnesota titled 

‘‘Approval and Promulgation of Air 

Quality Implementation Plans; 

Minnesota; Interstate Transport of 

Pollution’’ which is hereby corrected 

was originally published in the Federal 

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

The approval for Mississippi titled 

‘‘Approval and Promulgation of 

Implementation Plans; Mississippi: 

Clean Air Interstate Rule’’ which is 

hereby corrected was originally 

published in the Federal Register on 

October 3, 2007 (72 FR 56268). 

The approval for Missouri titled 

‘‘Approval and Promulgation of 

Implementation Plans; Missouri; Clean 

Air Interstate Rule’’ which is hereby 

corrected was originally published in 

the Federal Register on December 14, 

2007 (72 FR 71073) and the approval of 

Missouri titled ‘‘Approval and 

Promulgation of Implementation Plans; 

Missouri; Interstate Transport of 

Pollution’’ which is hereby corrected 

was originally published in the Federal 

Register on May 8, 2007 (75 FR 25975). 

The approval for New York titled 

‘‘Approval and Promulgation of 

Implementation Plans; New York: Clean 

Air Interstate Rule’’ which is hereby 

corrected was originally published in 

the Federal Register on January 24, 

2008 (73 FR 4109). 

The approval for North Carolina titled 

‘‘Approval of Implementation Plans; 

North Carolina: Clean Air Interstate 

Rule’’ which is hereby corrected was 

originally published in the Federal 

Register on October 5, 2007 (72 FR 

56914) and the approval for North 

Carolina titled ‘‘Approval and 

Promulgation of Air Quality 

Implementation Plans; North Carolina; 

Clean Air Interstate Rule’’ which is 

hereby corrected was originally 

published in the Federal Register on 

November 30, 2009 (74 FR 62496). 

The approval for Ohio titled 

‘‘Approval and Promulgation of Air 

Quality Implementation Plans; Ohio; 

Clean Air Interstate Rule’’ which is 

hereby corrected was originally 

published in the Federal Register on 

February 1, 2008 (73 FR 6034) and the 

approval for Ohio titled ‘‘Approval and 

Promulgation of Air Quality 

Implementation Plans; Ohio; Clean Air 

Interstate Rule’’ which is hereby 

corrected was originally published in 

the Federal Register on September 25, 

2009 (74 FR 48857). 

The approval for Pennsylvania titled 

‘‘Approval and Promulgation of Air 

Quality Implementation Plans; 

Pennsylvania; Clean Air Interstate Rule; 

NOX SIP Call Rule; Amendments to 

NOX Control Rules’’ which is hereby 

corrected was originally published in 

the Federal Register on December 10, 

2009 (74 FR 65446). 

The approval for South Carolina titled 

‘‘Approval of Implementation Plans of 

South Carolina: Clean Air Interstate 

Rule’’ which is hereby corrected was 

originally published in the Federal 

Register on October 9, 2007 (72 FR 

57209) and the approval for South 

Carolina titled ‘‘Approval and 

Promulgation of Air Quality 

Implementation Plans; South Carolina; 

Clean Air Interstate Rule’’ which is 

hereby corrected was originally 

published in the Federal Register on 

October 16, 2009 (74 FR 53167). 

The approval for Virginia titled 

‘‘Approval and Promulgation of Air 

Quality Implementation Plans; Virginia; 

Clean Air Interstate Rule Budget 

Trading Programs’’ which is hereby 

corrected was originally published in 

the Federal Register on December 28, 

2007 (72 FR 73602). 

The approval for West Virginia titled 

‘‘Approval and Promulgation of Air 

Quality Implementation Plans; West 

Virginia; Clean Air Interstate Rule’’ 

which is hereby corrected was originally 

published in the Federal Register on 

December 18, 2007 (72 FR 71576) and 

the approval for West Virginia titled 

‘‘Approval and Promulgation of Air 

Quality Implementation Plans; West 

Virginia; Clean Air Interstate Rule’’ 

which is hereby corrected was originally 

published in the Federal Register on 

August 4, 2009 (74 FR 38536). 

EPA is taking this final action without 

prior opportunity for notice and 

comment because EPA finds, for good 

cause, that notice and public procedure 

thereon are unnecessary and not in the 

public interest. Section 553(b)(B) of the 

Administrative Procedure Act provides 

that the notice and comment 

requirements in section 553 do not 

apply when the agency for good cause 

finds that notice and public procedure 

there on are impracticable, unnecessary, 

or contrary to the public interest. 5 

U.S.C. 553(b)(B). Section 307(d)(1) of 

the CAA in turn provides that the 

requirements of section 307(d) do not 

apply in the case of a rule or 

circumstance referred to in section 

553(b)(A) or section 553(b)(B) of the 

Administrative Procedure Act in Title 5. 

42 U.S.C. 7607(1). 

EPA finds that notice and public 

procedure are unnecessary because EPA 

has no discretion given the specific 


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circumstances presented in this case. 

EPA is bound by the decisions of the 

courts and must act in accordance with 

those decisions. EPA must accept the 

Court’s conclusion that compliance with 

CAIR does not satisfy the requirements 

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

lacks discretion to reach a different 

conclusion. This correction is a 

ministerial matter consistent with the 

decisions of the courts. For these 

reasons, it is unnecessary to provide an 

opportunity for notice and comment. 

V. Analysis of Downwind Air Quality 

and Upwind State Emissions 

A. Pollutants Regulated 

To address interstate transport of air 

pollution, EPA must choose which 

pollutants to regulate relevant to 

significant contribution to 

nonattainment or interference with 

maintenance of the NAAQS of concern 

downwind. This section of the preamble 

discusses the pollutants regulated under 

the final Transport Rule. 

1. Background 

Based on scientific and technical 

information, as well as EPA’s air quality 

modeling, EPA concluded for CAIR that 

the most effective approach to reducing 

the contribution of interstate transport 

to PM2.5 was to control SO2 and NOX

emissions. For CAIR, EPA did not limit 

emissions of other components of PM2.5, 

noting that ‘‘current information relating 

to sources and controls for other 

components identified in transported 

PM2.5 (carbonaceous particles, 

ammonium, and crustal materials) does 

not, at this time, provide an adequate 

basis for regulating the regional 

transport of emissions responsible for 

these PM2.5 components’’ (69 FR 4582). 

With respect to ozone transport, EPA 

has previously concluded that it is 

proper to control ozone-season NOX

emissions. For CAIR and the NOX SIP 

Call programs, EPA based this 

conclusion on the assessment of ozone 

transport conducted by the Ozone 

Transport Assessment Group (OTAG) in 

the mid-1990s. The OTAG Regional and 

Urban Scale Modeling and Air Quality 

Analysis Work Groups concluded that 

regional NOX emission reductions are 

effective in producing ozone benefits 

that grow with increasing regional NOX

abatement. 

The relative importance of NOX and 

VOC in ozone formation and control 

varies with local and time-specific 

factors, including the relative amounts 

of VOC and NOX present. In rural areas 

and many urban areas with high 

concentrations of VOC from biogenic 

sources, ozone formation and control is 

governed by NOX. In some urban core 

situations, NOX concentrations can be 

high enough relative to VOC to suppress 

ozone formation locally, but still 

contribute to increased ozone 

downwind from the city. In such 

situations, VOC reductions are most 

effective at reducing ozone within the 

urban environment and immediately 

downwind. The formation of ozone 

increases with temperature and 

sunlight, which is one reason ozone 

levels are higher during the summer. 

Increased temperature also increases 

emissions of volatile man-made and 

biogenic organics and can indirectly 

increase NOX as well (e.g., increased 

electricity generation for air 

conditioning). Summertime conditions 

also bring increased episodes of large 

scale stagnation of air masses, which 

promote the build-up of direct 

emissions and pollutants formed 

through atmospheric 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, regionalscale ozone transport is still an 

important component of high ozone 

concentrations during the extended 

summer ozone season. A series of more 

recent progress reports discussing the 

effect of the NOX SIP Call reductions 

can be found on EPA’s Web site at: 

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

progress/progress-reports.html. 

More recent assessments of ozone 

(including those conducted for the 

Regulatory Impact Analysis for the 

ozone standards in 2008) continue to 

show the importance of NOX transport 

as a factor in ozone formation. For 

addressing interstate ozone transport in 

CAIR, EPA required NOX emission 

reductions but did not include 

requirements for VOCs. EPA believes 

that VOCs from some upwind states do 

indeed have an impact in some nearby 

downwind states, particularly over short 

transport distances. EPA expects that 

states, typically in local nonattainment 

planning, would benefit from examining 

the extent to which VOC emissions 

affect ozone pollution levels within and 

near urban nonattainment areas, and 

states may identify areas where multistate VOC strategies might assist in 

attainment planning for meeting the 8- 

hour standard. However, EPA continues 

to believe that the most effective 

regional pollution control strategy for 

mitigation of interstate transport of 

ozone remains NOX emission 

reductions. 

2. Which pollutants did EPA propose to 

control for purposes of PM2.5 and ozone 

transport? 

For the proposed rule, EPA concluded 

that its findings in CAIR regarding the 

nature of pollutant contributions are 

still appropriate. EPA proposed to 

require SO2 and annual NOX emission 

reductions to control PM2.5 transport 

and to require ozone-season NOX

emission reductions to control ozone 

transport. In the proposal, EPA 

discussed and requested comment on 

the inclusion of southern states in the 

annual NOX program for PM2.5 control. 

3. Comments and Responses 

EPA received no adverse comments 

on its proposal to regulate SO2 for 

addressing PM2.5 transport, the proposal 

not to regulate direct PM2.5 or organic 

PM2.5 precursors, and the proposal to 

focus 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 

PM2.5 contribution from those states, or 

(2) the required remedy for emission 

reductions in those states should not 

require reductions in annual NOX. 

For the final rule, EPA retains the 

approach for regulated pollutants in the 

proposal, which regulates annual NOX

and SO2 for states affecting downwind 

state PM2.5 nonattainment and 

maintenance sites, and ozone-season 

NOX for states impacting downwind 

state ozone nonattainment and 

maintenance. EPA considered 

commenters’ requests to remove some 

states from the annual NOX program. 

However, EPA believes that it is 


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16SO2 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. 

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, Alabama 

and Tennessee are both linked to 

Washtenaw County, MI for 24-hour 

PM2.5; North Carolina is linked to 

Lancaster County, PA for 24-hour PM2.5; 

and Texas is linked to Madison County, 

IL for both annual and 24-hour PM2.5. 

All of these downwind areas have 

appreciable nitrate deposition 

contributing to nonattainment and 

maintenance concerns for the PM2.5

NAAQS. If the states linked to those 

receptors were to make SO2 reductions 

only, their beneficial impact on 

downwind air quality would be 

partially eroded by nitrate replacement. 

EPA therefore believes that it is 

reasonable to seek both SO2 and NOX

reductions from states included in the 

Transport Rule program that are found 

to significantly contribute to 

nonattainment or interfere with 

maintenance of the PM2.5 NAAQS in 

downwind states. 

In addition, EPA notes that there 

would be important disbenefits to 

effectively removing CAIR’s existing 

annual NOX requirements in those 

states. If EPA were to allow annual NOX

emissions to increase for those states, 

there would be potentially harmful 

effects on visibility, nitrogen deposition, 

and other aspects of human and 

environmental health. 

B. Baseline for Pollution Transport 

Analysis 

Implementing the mandate of CAA 

section 110(a)(2)(D)(i)(I) requires EPA to 

determine which states significantly 

contribute to nonattainment and 

interfere with maintenance of the 

NAAQS in other states, as well as to 

quantify the emissions in each state that 

must be eliminated. This process begins 

with an analysis of baseline emissions. 

Baseline emissions are the emissions 

that would occur in each state if EPA 

did not promulgate the Transport Rule. 

To conduct such analysis, EPA 

generally takes into account emission 

limitations that are currently, and will 

continue to be, in place. From that 

baseline, EPA analyzes whether 

additional reductions are necessary 

beyond those already mandated by 

existing emission limitation 

requirements. For example, the base 

case used in CAIR reflected the 

reductions already required by the NOX

SIP Call, which remained in effect even 

after the CAIR emission reduction 

requirements took effect. 

The unique legal situation addressed 

by the Transport Rule necessarily affects 

the quantification of baseline emissions. 

Specifically, because the Transport Rule 

will replace CAIR, EPA cannot consider 

reductions associated with CAIR in the 

‘‘base case’’ (i.e., analytical baseline 

emissions scenario). If EPA were to 

consider all reductions associated with 

CAIR in the ‘‘base case,’’ the baseline 

emissions would not adequately reflect 

the true 2012 baseline in each state (i.e., 

the emissions that would occur in each 

state in 2012 if the Transport Rule did 

not require any reductions in that state). 

Similarly, if EPA were to treat the 

capital investments that have already 

been made to meet the requirements of 

CAIR as new costs rather than treating 

them as ‘‘sunk’’ capital costs, EPA’s 

analysis would not accurately reflect the 

cost of emission reductions required by 

the Transport Rule. As explained below, 

EPA’s analysis both properly considered 

all capital investments made in 

response to CAIR and properly 

recognized that, after CAIR is 

terminated, the emission limitations 

imposed by CAIR will cease to exist. 

In 2005 EPA promulgated CAIR, 

which required large electric generating 

units in 29 states to make phase I 

emission reductions in NOX emissions 

starting in 2009, phase I emission 

reductions in SO2 starting in 2010 and 

phase II reductions in emissions of both 

pollutants starting in 2015. On July 11, 

2008, the DC Court of Appeals held that 

CAIR had ‘‘more than several fatal 

flaws,’’ North Carolina, 531 F.3d at 901, 

and remanded and vacated the rule, id. 

at 930. The Court subsequently granted 

EPA’s petition for rehearing in part and 

remanded CAIR without vacatur ‘‘for 

EPA to conduct further proceedings 

consistent with’’ the Court’s July 11, 

2008 opinion. North Carolina, 550 F.3d 

1176. The Court explained that it was 

‘‘allowing CAIR to remain in effect until 

it is replaced by a rule consistent with 

[the July 11, 2008] opinion’’ because 

this ‘‘would at least temporarily 

preserve the environmental values 

covered by CAIR.’’ Id. at 1178. 

Moreover, the Court stated that it did 

not ‘‘intend to grant an indefinite stay 

of the effectiveness of’’ the July 11, 2008 

order vacating CAIR. Id. In summary, 

the Court determined that CAIR was 

fatally flawed and could remain in effect 

only as a stopgap measure until EPA 

could act to replace it. 

Thus, unlike most other regulatory 

requirements (such as the Acid Rain 

Program under CAA Title IV, the NOX

Budget Trading Program under the NOX

SIP Call, New Source Performance 

Standards, and state laws and consent 

orders requiring emission reductions), 

the emission limitations contained in 

CAIR are only temporary. Moreover, the 

duration of these limitations is directly 

tied to the Transport Rule. The 

Transport Rule replaces CAIR. Thus, 

CAIR itself will be terminated for the 

SO2, annual NOX, and ozone-season 

NOX control periods starting in 2012 

when the emission limitations 

established in the final Transport Rule 

for those control periods take effect 

(January 1, 2012 for the annual control 

periods and May 1, 2012 for the ozoneseason control period). For this reason, 

emission reductions made to comply 

with CAIR cannot be treated as if they 

were emission reductions achieved to 

comply with statutory provisions, rules, 

consent decrees, and other enforceable 

requirements that establish permanent 

emission limitations. EPA takes 

reductions made to comply with 

permanent limitations into 

consideration when quantifying each 

state’s baseline emissions for the 

purpose of analyzing whether its 

emissions significantly contribute to 

nonattainment or interfere with 

maintenance in another state. However, 

the unique legal status of CAIR and its 

replacement with the Transport Rule 

distinguish the emission reductions 

required by CAIR from those of other 

regulatory requirements. Since the 

limitations and emission reduction 

requirements in CAIR are temporary and 

will be terminated by the Transport 

Rule, they must be excluded from the 

Transport Rule’s base case analysis. 

Some comments on the Transport 

Rule proposal claim that EPA’s 

treatment of CAIR is inconsistent with 

the treatment, in prior rulemakings, of 

the Acid Rain Program and the NOX SIP 

Call. Such comments ignore the unique 

legal status of CAIR, and EPA therefore 

rejects these claims. 

A simple example illustrates this 

point. Assume state Z’s emissions before 


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17For more details on how EPA models economic 

operation of existing pollution control equipment in 

the Transport Rule base case, please see Section 6 

(‘‘Dispatchable Controls’’) in ‘‘Updates to EPA Base 

Case v3.02 EISA Using the Integrated Planning 

Model’’ Technical Support Document (TSD) for the 

Transport Rule Docket ID No. EPA–HQ–OAR– 

2009–0491, U.S. EPA, July 2010 (available at http:// 

www.epa.gov/airmarkets/progsregs/epa-ipm/IPM 

Update Documentation.pdf). 

CAIR were 2,000 tons and that state Z 

was required by CAIR to reduce its 

emissions to 1,000 tons. If EPA were to 

determine that state Z’s baseline 

emissions were 1,000 tons and then 

conclude, based on that assumption, 

that no additional reductions in state Z 

are necessary because state Z does not 

significantly contribute to downwind 

nonattainment unless its emissions 

exceed 1,500 tons, then state Z would 

not be covered by the Transport Rule. 

However, the Transport Rule will 

terminate all CAIR requirements in all 

CAIR states regardless of whether they 

are covered by the Transport Rule. 

Thus, after promulgation of the 

Transport Rule, state Z would again be 

allowed, and would be projected in this 

example, to emit 2,000 tons. In other 

words, state Z would be allowed to 

significantly contribute to 

nonattainment and/or interfere with 

maintenance in other states—a result 

that would be inconsistent with the 

statutory mandate of CAA section 

110(a)(2)(D)(i)(I). On the other hand, if 

EPA assumes state Z’s baseline 

emissions are 2,000 tons as projected 

without CAIR in place, EPA can 

properly determine whether, if state Z 

were allowed to emit that amount (i.e., 

the amount state Z would be projected 

to emit if excluded from the Transport 

Rule), the state would significantly 

contribute to nonattainment or interfere 

with maintenance in any other state. In 

other words, EPA can determine the 

stringency of emission limitations 

needed (if any) to replace those that 

were established by CAIR in order to 

ensure that state Z prohibits all 

emissions that significantly contribute 

to nonattainment or interfere with 

maintenance in other states. 

In fact, commenters’ suggestion that 

the Transport Rule base case should 

include CAIR would cause the 

anomalous result of excluding sources 

in a state from the Transport Rule 

because of their CAIR–required 

emission reductions while 

simultaneously eliminating those CAIR 

emission reduction requirements. If 

EPA’s base case analysis were to assume 

erroneously that reductions from CAIR 

would continue indefinitely, a state 

currently covered by CAIR, but not 

covered by the Transport Rule, would 

have no CAIR requirements once the 

Transport Rule programs began and so 

could increase emissions beyond the 

CAIR limitations. Downwind areas that 

are in attainment (and are not 

experiencing interference with 

maintenance of such attainment) solely 

because of emission reductions required 

by CAIR could again face nonattainment 

or interference with maintenance 

problems because the current protection 

from upwind pollution from such an 

upwind state would not be replaced. In 

short, the analysis 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 CAIRspecific emission reductions. 

As a result, EPA’s 2012 base case 

shows emissions higher than current 

levels in some states. In the absence of 

the CAIR SO2 and NOX programs that 

EPA has been directed to eliminate and 

replace, utility emissions in CAIR states 

will be limited only by non-CAIR 

constraints including the Acid Rain 

Program, the NOX SIP Call, New Source 

Performance Standards, any state laws 

and consent order requiring emission 

reductions, and any other permanent 

and enforceable binding reduction 

commitments. This will lead to 

increased emissions in some states in 

the 2012 base case relative to current 

emissions. For example, efforts to 

comply with the Acid Rain Program at 

the least cost may occur, in some cases, 

without the operation of existing 

scrubbers through use of readily 

available, inexpensive Title IV 

allowances. 

It is important to note that, to the 

extent that emission reductions 

currently required by CAIR are also 

reflected in emission reduction 

requirements under the Acid Rain 

Program, the NOX SIP Call, New Source 

Performance Standards, any state laws 

and consent orders requiring emission 

reductions, and any other enforceable 

binding reduction commitments, such 

reductions are accounted for in EPA’s 

2012 base case. Some commenter 

claimed 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. 

Such allegations are incorrect. As 

discussed elsewhere in this preamble, 

EPA accounted for any Title V permits, 

consent decrees, state rules, and other 

enforceable limitations on sources’ 

emissions; if these non-CAIR limitations 

effectively restrain a state’s emissions to 

not exceed the state’s CAIR limitations, 

EPA’s base case modeling would reflect 

this outcome. Commenters also assert 

that utilities are unlikely to dismantle or 

discontinue running the installed 

controls to the point of returning to preCAIR emission levels. EPA agrees that 

installed controls are not likely to be 

physically dismantled, and as discussed 

elsewhere in this preamble, EPA’s 

analysis properly treats the capital 

investments made in emission controls 

attributed to CAIR as ‘‘sunk’’ capital 

costs (i.e., capital costs already obligated 

in the past) that are not included as 

costs of meeting Transport Rule 

requirements. 

Our cost analysis for significant 

contribution reflects on-the-ground 

realities. Investments in pollution 

control equipment were made in 

response to CAIR requirements. Those 

expenditures are ‘‘sunk’’ capital costs, 

meaning that those investments were 

committed in the past, prior to the 

Transport Rule. Adding the capital costs 

of that equipment into the costs of 

Transport Rule emission reduction 

options would be incorrect; those 

capital investments are represented in 

place in the base case. 

However, given ongoing costs 

associated with operating these controls, 

EPA believes sources would have an 

economic incentive to discontinue 

operating installed controls, or to 

operate those controls less effectively, 

except to the extent non-CAIR legal 

requirements mandate emission 

reductions or to the extent that sources 

would find it economic to operate the 

controls for non-CAIR market-based 

emission control programs. EPA 

properly treats the costs of operating 

controls installed to meet CAIR 

requirements as costs of meeting 

Transport Rule requirements.17 EPA’s 

base case accounts for non-CAIR 

requirements and does not make the 

unreasonable assumption that installed 

controls would be operated to achieve 

emission reductions that are not 

necessary to meet non-CAIR 

requirements. For all of these reasons, 

EPA rejects commenters’ claims that the 

base case is ‘‘unrepresentative’’ or lacks 

‘‘a rational relationship to the real 

world.’’ 

C. Air Quality Modeling To Identify 

Downwind Nonattainment and 

Maintenance Receptors 

1. Emission Inventories 

To inform air quality modeling for the 

development of the final Transport 

Rule, EPA developed emission 


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inventories for a 2005 base year and for 

2012 and 2014 projections. The 

inventories for all years include 

emission estimates for EGUs, non-EGU 

point sources, stationary nonpoint 

sources, onroad mobile sources, 

nonroad mobile sources, and biogenic 

(non-human) sources. EPA’s air quality 

modeling relies on this comprehensive 

set of emission inventories because 

emissions from multiple source 

categories are needed to model ambient 

air quality and to facilitate comparison 

of model outputs with ambient 

measurements. In addition, EPA 

considers all relevant emissions 

(regardless of source category) when 

determining whether a state is found to 

be significantly contributing to or 

interfering with maintenance of a 

particular NAAQS in another state. 

The emission inventories were 

processed through the Sparse Matrix 

Operator Kernel Emissions (SMOKE) 

Modeling System version 2.6 to produce 

the gridded, hourly, speciated, modelready emissions for input to the CAMx 

air quality model. Additional 

information on the development of the 

emission inventories and related data 

sets for emissions modeling are 

provided in the Emission Inventory 

Final Transport Rule TSD. 

On October 27, 2010, EPA issued a 

NODA on ‘‘Revisions to Emission 

Inventories.’’ The NODA’s primary 

purpose was to notify the public about 

changes to emission inventories made 

since the proposal modeling. The 

affected emission sectors were non-EGU 

stationary point sources, nonpoint 

sources, and Category 3 commercial 

marine vessel sources. The NODA also 

presented a newly released model for 

developing onroad mobile source 

emissions for use in air quality 

modeling for the final Transport Rule. 

The major comments received in 

response to the emission inventories 

and modeling included in the proposed 

Transport Rule and the October 27 

NODA are summarized in the following 

subsections. EPA agreed with the 

comments summarized below and 

adopted technical corrections or 

updates to the emission inventories and 

modeling accordingly. For EPA to be 

able to take appropriate action, 

comments on the emission inventories 

needed to be specific enough to allow 

for credible alternative data sources to 

be located. EPA adopted corrections 

from comments on in-place control 

programs or devices where the controls 

were enforceable and quantifiable. 

a. Foundation Emission Inventory Data 

Sets 

EPA developed emission data 

representing the year 2005 to support air 

quality modeling of a base year from 

which future air quality could be 

forecasted. EPA used the 2005 National 

Emission Inventory (NEI), version 2 

from October 6, 2008, as the chief basis 

for the U.S. inventories supporting the 

2005 air quality modeling. This 

inventory includes 2005-specific data 

for point and mobile sources, while 

most nonpoint data were carried 

forward from version 3 of the 2002 NEI. 

The future base case scenarios modeled 

for 2012 and 2014 represent predicted 

emission reductions primarily from 

already promulgated federal measures. 

EPA used a 2006 Canadian inventory 

and a 1999 Mexican inventory for the 

portions of Canada and Mexico within 

the air quality modeling domains for all 

modeled scenarios. Emissions from 

Canada and Mexico for all source 

sectors (including EGUs) in these 

countries were held constant for all 

base- and future-year cases. EPA made 

this assumption because it does not 

currently have sufficient data to support 

projections of future-year emissions 

from Canada and Mexico. 

b. Development of Emission Inventories 

for EGUs 

The annual NOX and SO2 emissions 

for EGUs in the 2005 NEI v2 are based 

primarily on data from continuous 

emissions monitoring systems (CEMS), 

with other EGU pollutants estimated 

using emission factors and annual heat 

input data reported to EPA. Although 

only NOX and SO2 are considered for 

control in this rule, emissions for all 

criteria air pollutants are necessary to 

model air quality. For EGUs without 

CEMS, EPA used data submitted to the 

NEI by the states. For more information 

on the details of how the 2005 EGU 

emissions were developed, see the 

Emissions Inventory Final Rule TSD. 

Commenters stated that some point 

sources that were classified as nonEGUs in the proposal modeling were 

actually EGUs, resulting in double 

counting of emissions in future-year 

modeling. EPA reviewed its assignment 

of EGUs and non-EGUs and reclassified 

EGU sources found to be in the nonEGU inventory for the updated 2005 

EGU inventory to prevent double 

counting of future-year emissions. 

The future base case scenarios for 

EGUs reflect projected changes to fuel 

usage and economics, as described in 

the Emission Inventory Final Rule TSD. 

Future year base case EGU emissions 

that predict SO2, NOX, and PM2.5 were 

obtained from version 4.10_FTransport 

of the Integrated Planning Model (IPM) 

outputs (http://www.epa.gov/airmarkt/ 

progsregs/epa-ipm/index.html). The 

IPM is a multi-regional, dynamic, 

deterministic linear programming model 

of the U.S. electric power sector; version 

4.10_FTransport reflects state rules and 

consent decrees through December 1, 

2010, and incorporates public 

comments on existing controls 

submitted to EPA through both the 

Transport Rule-related notice and 

comment process as well as the 

proposed Mercury and Air Toxics 

Standards Information Collection 

Request (ICR). The operation of existing 

SO2 or NOX advanced controls (e.g., 

scrubber, SCR) on units that were not 

required to operate those controls for 

compliance with Title IV, New Source 

Review (NSR), state settlements, or 

state-specific rules was projected by 

IPM on the basis of providing least cost 

operation of the power generation 

system subject to existing regulatory 

requirements except CAIR (see baseline 

discussion in section V.B). 

Additionally, IPM v.4.10_FTransport 

incorporates comments received during 

the rulemaking process. Fuel-related 

updates include comment-driven unitspecific 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 

Details on the development of 

emission inventories are available in the 

Emission Inventory Final Rule TSD. In 

both the proposal and final modeling, 

controls on industrial boilers installed 

under the NOX SIP call were assumed 

to have been implemented by 2005 and 

captured in the 2005 NEI v2. The nonEGU point source emissions were 

updated from the 2005 NEI and the 


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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 nonEGU emissions. More details on the 

rationale for not applying economic 

growth to non-EGU industrial sources 

can be found in Appendix D of the 

Regulatory Impact Assessment (RIA) for 

the PM NAAQS rule (http:// 

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

Appendix%20D—Inventory.pdf). 

Although projections based on 

economic growth were not included, 

EPA did include reductions resulting 

from plant and unit closures, local and 

federal consent decrees, and several 

Maximum Achievable Control 

Technology (MACT) standards. 

For non-EGU point sources, local 

control programs that may be necessary 

for areas to attain the annual PM2.5

NAAQS and the ozone NAAQS are only 

included in the future base case 

projections when specific information 

about existing enforceable local controls 

was provided. 

Since aircraft at airports were treated 

as point emissions sources in the 2005 

NEI v2, we applied projection factors 

based on activity growth projected by 

the Federal Aviation Administration 

Terminal Area Forecast (TAF) system, 

published in December 2008. 

A number of comments were received 

on the stationary non-EGU point source 

inventories. Below is a summary of the 

major comments that impacted the 

stationary non-EGU point source 

inventories for the final modeling: 

Comment: Commenters stated that 

EPA did not properly represent some 

point source emissions in base-year and 

future-year inventories due to facility 

and unit closures, consent decrees, 

emission caps, control programs, and 

alternative emission estimates. 

Response: EPA reviewed the sources 

referenced in the individual comments 

regarding the base-year and future-year 

inventories. In cases where credible 

alternative data were available, EPA 

revised the emission inventories to 

incorporate additional facility and unit 

closures, consent decrees, emission 

caps, control programs, enforceable 

local controls, and alternative emission 

estimates. 

Comment: Commenters stated that 

EPA should include controls from the 

National Emission Standards for 

Hazardous Air Pollutants for 

Reciprocating Internal Combustion 

Engines (RICE NESHAP) in our 

modeling. 

Response: EPA included reductions 

expected to be achieved by the RICE 

NESHAP across the United States in our 

final modeling of stationary non-EGU 

and nonpoint sources. 

Comment: Commenters stated that 

EPA was not properly representing 

existing or planned controls for cement 

plants. 

Response: EPA updated control and 

projection information for cement plants 

based on the latest available data and 

cement sector-specific modeling results. 

Comment: EPA specifically requested 

comments on whether to incorporate 

emission reduction estimates from the 

NESHAP for Major Sources: Industrial, 

Commercial, and Institutional Boilers 

and Process Heaters (75 FR 32006). 

Commenters stated that emission 

reduction estimates should not be 

included until the rule became final. 

Response: EPA did not incorporate 

emission reduction estimates from the 

NESHAP for Major Sources: Industrial, 

Commercial, and Institutional Boilers 

and Process Heaters (75 FR 32006) into 

the proposal or final modeling because 

the rule was not final at the time the 

modeling was performed. Note that 

reductions from this rule would 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 (evaporative, exhaust, 

brake wear and tire wear) and allocated 

those emissions to counties according to 

state-county NMIM emissions ratios. For 

California (the emissions for which are 

included to support the coarse modeling 

domain), the onroad mobile emissions 

data were derived from data provided 

by the state. These data were augmented 

with MOVES 2010 outputs for NH3

because data for that pollutant had not 

been provided. Additional information 

on the approach to onroad mobile 

source emissions is available in the 

Emission Inventory Final Rule TSD. 

In the future-year base modeling for 

mobile sources, all national measures 

available at the time of modeling were 

included. The future scenarios for 

mobile sources reflect projected changes 

to fuel usage, as described in the 

Emission Inventory Final Rule TSD. 

Emissions for these years reflect onroad 

mobile control programs including the 

Light-Duty Vehicle Tier 2 Rule, the 

Onroad Heavy-Duty Rule, the LightDuty Vehicle Greenhouse Gas Rule, the 

Renewable Fuel Standards Rule, and the 

Mobile Source Air Toxics (MSAT) final 

rule. 

e. Development of Commercial Marine 

Category 3 Vessel Emission Inventories 

For the 2005 modeling, the 

commercial marine category 3 (C3) 

vessel emissions, a portion of nonroad 

mobile emissions, were augmented with 

gridded 2005 emissions from the 

previous modeling efforts for the rule 

called ‘‘Control of Emissions from New 

Marine Compression-Ignition Engines at 

or Above 30 Liters per Cylinder.’’ 

Emissions out to 200 nautical miles 

from the coastline were allocated to 

states in the proposal modeling. A major 

comment on the proposal modeling was 

the following: 

Comment: Commenters stated that 

emissions from commercial marine 

sources (a component of the nonroad 

emissions in the summaries that were 

provided for the NPR) were too high. 

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 statefederal 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 


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(EPA–420–F–10–041, August 2010) 

control strategy; reductions of NOX,

VOC, and CO emissions for new C3

engines starting in 2011; and fuel sulfur 

limits that go into effect as early as 

2010. 

f. Development of Emission Inventories 

for Other Nonroad Mobile Sources 

The nonroad mobile source emissions 

for sources other than C3 marine were 

primarily based on NMIM monthly, 

county, and process level emissions 

from the 2005 NEI v2. These emissions 

were unchanged from proposal 

modeling, except for PM emissions in 

California that were updated to correct 

for missing emissions in a few counties 

and source categories. 

Nonroad mobile emissions were 

created for future years with NMIM 

using an approach consistent with that 

used for 2005. The nonroad emissions 

for 2012 and 2014 were calculated using 

NMIM future-year equipment 

population estimates and control 

programs. Nonroad mobile emission 

reductions for 2012 and 2014 include 

reductions to locomotives, various 

nonroad engines including diesel 

engines and various marine engine 

types, fuel sulfur content, and 

evaporative emissions standards. A 

more comprehensive list of control 

programs included for mobile sources is 

available in the Emission Inventory 

Final Rule TSD. 

The 2012 and 2014 nonroad mobile 

emissions for locomotives and category 

1 and 2 (C1 and C2) commercial marine 

vessels were based on emissions 

published in EPA’s Locomotive Marine 

Rule, Regulatory Impact Assessment, 

Chapter 3. 

g. Development of Nonpoint Emission 

Inventories 

For the proposal Transport Rule 

modeling, EPA augmented the 2002 NEI 

nonpoint emission inventory with a 

non-California Western Regional Air 

Partnership (WRAP) oil and gas 

exploration inventory, which includes 

emissions in several states within the 

eastern U.S. 12 km modeling domain 

and additional states within the national 

36 km modeling domain. For the final 

Transport Rule modeling, EPA updated 

the nonpoint emission estimates for oil 

and gas sources. EPA continued to use 

the same WRAP inventory from the 

proposal, emissions in Texas and 

Oklahoma were updated but for the 

final modeling with data from the Texas 

Commission on Environmental Quality 

(TCEQ) and the Oklahoma Department 

of Environmental Quality (DEQ), 

respectively. 

The average-year county-based 

inventories for wildfire and prescribed 

burning emissions were unchanged 

between the proposal and final 

modeling. 

For stationary nonpoint sources, local 

control programs that may be necessary 

for areas to attain the annual PM2.5

NAAQS and the ozone NAAQS are not 

included in the future base case 

projections unless specific information 

about existing enforceable controls was 

available (e.g., ozone SIP controls from 

Ozone Transport Commission rules that 

impact source categories such as 

Consumer Products, Solvent Cleaning, 

Adhesives and Sealants). EPA 

specifically requested comment on local 

control data as part of the proposal and 

the October 27 NODA, and incorporated 

any usable data that was provided into 

the final inventories. 

For stationary nonpoint sources, 

refueling emissions were projected 

using the refueling results from the 

NMIM runs performed for the onroad 

mobile sector. 

Portable fuel container emissions 

were projected to future years using 

estimates from previous OTAQ 

rulemaking inventories. Emissions of 

ammonia and dust from animal 

operations were projected based on 

animal population data from the 

Department of Agriculture and EPA. 

Residential wood combustion was 

projected by replacement of obsolete 

wood stoves with new wood stoves and 

a 1 percent annual increase in 

fireplaces. Landfill emissions were 

projected using MACT controls. All 

other nonpoint sources were held 

constant between 2005 and the future 

years. 

Some specific adjustments to the 

inventories were made in the final 

modeling to address comments that 

were received as described below. Area 

source MACT programs and controls 

from the RICE NESHAP were included 

in the final modeling to address 

submitted comments, as were fuel sulfur 

controls that were enforceable and that 

take effect by 2014. 

The major comments that impacted 

the nonpoint sectors are as follows: 

Comment: Commenters stated that the 

SO2 emissions from industrial fuel 

combustion in Nebraska EPA are too 

high. 

Response: EPA reviewed the NEI 

2002-based data that had been used for 

the proposal modeling and determined 

that emissions from the 2005 inventory 

compiled for the Central Regional Air 

Planning Association (CENRAP) were 

more up to date for this source category 

and based on more localized data 

sources. The 2005 CENRAP emissions 

for industrial fuel combustion were 

used in the final modeling. 

Comment: Commenters stated that 

EPA should include sulfur rule controls 

that take effect prior to the future years 

that were modeled. 

Response: EPA included quantifiable 

sulfur rule controls in 2014 modeling 

for those states that had implemented 

the rules (New Jersey and Maine). 

Comment: A commenter stated that 

emissions for Delaware were 

overestimated for several nonpoint 

categories in base-year and future-year 

inventories and provided alternative 

estimates for these categories. 

Response: EPA reviewed the 

alternative estimates provided and 

found them to be credible and based on 

more detailed local scale information 

than were available in the national 

inventories. EPA incorporated the 

alternative emission estimates for 

Delaware into the final modeling. 

Comment: A commenter stated that 

residual oil is not used as an industrial 

fuel in South Carolina. 

Response: EPA analyzed the 

emissions from residual oil industrial 

fuel combustion in South Carolina and 

all other states, and analyzed 

preliminary regional planning office 

inventories and the 2008 NEI 

submittals. The South Carolina residual 

oil industrial fuel emissions were 

determined to be anomalously large in 

comparison to the near zero emissions 

in other submittals and were therefore 

removed from the nonpoint inventory. 

2. Air Quality Basis for Identifying 

Receptors 

a. Introduction 

In this section, we describe the final 

approach to identify downwind 

nonattainment and maintenance 

receptors. We briefly summarize the 

modeling platform, the proposed 

approach to identify receptors, 

comments received, and the results of 

the final analysis. 

In the Transport Rule, EPA has 

explicitly given independent meaning to 

the ‘‘interfere with maintenance’’ prong 

of section 110(a)(2)(D)(i)(I) by evaluating 

contributions to identified maintenance 

receptors as well as contributions to 

identified nonattainment receptors. EPA 

identified maintenance receptors as 

those receptors that would have 

difficulty maintaining the relevant 

NAAQS in a scenario that takes into 

account historic variability in air quality 

at that receptor. Specifically, EPA 

projects future air quality design values 

based on measured data during the 

period 2003 to 2007. In determining the 

downwind receptors of concern, EPA 


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does not solely rely on the projection of 

an average design value based on 

measured data from the relevant period 

(in this case 2003 to 2007) to make a 

determination of ‘‘attainment’’ or 

‘‘nonattainment.’’ Instead, EPA also 

evaluates the maximum future design 

value at that receptor based on 

measured data over the relevant period. 

Receptors for which this latter analysis 

projects design values higher than the 

NAAQS are identified as maintenance 

receptors. 

EPA believes it is appropriate and 

reasonable to use this approach to 

identify receptors that may have 

maintenance problems in the future. 

This approach uses measured data in 

order to establish potential air quality 

outcomes at each receptor that take into 

account the variable meteorological 

conditions present across the entire 

period of measured data (2003 to 2007). 

EPA interprets the maximum future 

design value to be a potential future air 

quality outcome consistent with the 

meteorology that yielded maximum 

measured concentrations in the ambient 

data set analyzed for that receptor. In 

other words, the average design value 

gives a reasonable projection of future 

air quality at the receptor under 

‘‘average’’ conditions. However, EPA 

also recognizes that previously 

experienced meteorological conditions 

(e.g., dominant wind direction, 

temperatures, air mass patterns) 

promoting ozone or fine particle 

formation that led to maximum 

concentrations in the measured data 

may reoccur in the future. The 

maximum design value gives a 

reasonable projection of future air 

quality at the receptor under a scenario 

in which such conditions do, in fact, 

reoccur. It also identifies upwind 

emissions that under those 

circumstances could interfere with the 

downwind area’s ability to maintain the 

NAAQS. 

Per the court’s opinion in North 

Carolina, it is necessary for the Agency 

to evaluate ‘‘interference with 

maintenance’’ separately from 

‘‘significant contribution to 

nonattainment’’ in order to give 

independent meaning to that phrase in 

the statute. The approach described 

above does so and provides a reasonable 

basis for identifying upwind emissions 

that interfere with maintenance of the 

NAAQS at downwind receptors. 

Because the methodology is based on 

actual variations in design values 

measured at the receptors, EPA believes 

that the application of this design value 

methodology for identifying 

maintenance receptors reasonably 

anticipates possible future air quality 

outcomes based on meteorological 

conditions independent of emission 

reduction requirements occurring 

between 2005 (the base year for air 

quality analysis) and 2012 (the future 

year for air quality analysis of the base 

case without CAIR or the Transport Rule 

in place). EPA uses air quality modeling 

to properly account for changes in air 

quality from 2005 to 2012 due to 

emission control requirements and 

trends in emission source fleet turnover 

(such as increasingly cleaner motor 

vehicle fleets). The air quality modeling 

process allows EPA to effectively adjust 

measured data to project design values 

in 2012 based on the forecast changes in 

emissions. For a given receptor, the 

forecast change in emissions from 2005 

to 2012 is a constant factor applied 

across all of the design values from the 

period 2003 to 2007. Thus, a 

comparison of the projected (futureyear) design values themselves is 

equivalent to comparing the base period 

design values from the data set to 

consider how pollution concentrations 

are affected by non-modeled factors 

such as environmental and 

meteorological variability independent 

of the forecast emission reductions that 

stem from successful imposition of 

emission limitations and controls on 

various sources between the base and 

future modeling years. EPA believes it is 

reasonable to anticipate that these yearto-year meteorological fluctuations may 

reoccur at any time in the future and are 

relevant to determining receptors that 

are at risk of having a problem in the 

future with maintenance of the NAAQS. 

Therefore, EPA assesses the relationship 

of the maximum projected design value 

for 2012 at each receptor to the relevant 

NAAQS, and where such a value 

exceeds the NAAQS, EPA determines 

that receptor to be a ‘‘maintenance’’ 

receptor for purposes of defining 

interference with maintenance under 

the Transport Rule. 

To provide an illustrative example, 

consider a hypothetical receptor ‘‘Y’’ 

whose measured data for 2003–2007 

yields three design values for annual 

fine particles: 17 for 2003–05; 14 for 

2004–06; and 12 μg/m3 for 2005–07. 

Thus, the maximum measured design 

value for this period is 17 and the 

average design value is 14.3. To 

determine whether the receptor is a 

nonattainment or maintenance receptor, 

EPA projects a corresponding futureyear (2012) design value for each 

measured design value. These 

projections are based on the results of 

air quality modeling, which 

demonstrates predicted changes in 

pollution concentrations for each 

receptor from 2005 to 2012. For this 

example, assume that the projected 

future-year design values that 

correspond with the measured design 

values, are 16 (corresponds with the 

2003–05 design value of 17), 13 

(corresponds with the 2004–06 design 

value of 14), and 11 μg/m3 (corresponds 

with the 2005–07 design value of 12). 

The average future-year design value is 

13.3 (corresponds with the average 

measured design value from 2003–2007 

of 14.3). The projected future design 

values are all lower than the measured 

design values because air quality is 

projected to improve between 2005 and 

2012. In this example, the analysis 

establishes that the average projected 

future design value is 13.3 and the 

maximum projected future design value 

is 16. 

The average future (2012) projected 

design value of 13.3 based on the 

average design value for the period 

2003–07 does not exceed the 1997 

annual PM2.5 NAAQS. For this reason, 

EPA would conclude that receptor Y 

will most likely have attainment air 

quality in the future year. Therefore, it 

would not be identified as a 

nonattainment receptor. 

However, the future projected design 

value of 16 based on the maximum 

design value for the period 2003–07 

does exceed the NAAQS. For this 

reason, EPA would conclude that the 

receptor may have difficulty 

maintaining attainment with the 

NAAQS under future potential 

meteorological conditions. EPA 

therefore would identify the receptor as 

a maintenance receptor and evaluate 

whether upwind state emissions 

interfere with maintenance of the 

NAAQS at that receptor. 

EPA’s methodology accounts for the 

range of meteorological conditions 

reflected by design values from the 

measured 2003–2007 data at receptor Y 

and also accounts for the projected 

changes in emissions from 2005 to 2012 

at receptor Y. The range of 

meteorological conditions is accounted 

for by using data from three different 

3-year periods as described above. The 

projected changes in emissions are 

accounted for by applying to the 

measured design values the forecasted 

change in PM2.5 concentrations, as 

determined through air quality 

modeling of the 2005 and 2012 

emissions. In this example, the 

maximum measured design value for 

receptor Y is 17. This design value 

represents measured data from 2003 to 

2005. EPA applies to this design value 

the modeled 2005–to–2012 change in 

concentrations at receptor Y to obtain a 

2012 maximum design value for that 


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18Comprehensive Air Quality Model with 

Extensions Version 5 User’s Guide. Environ 

International Corporation. Novato, CA. March 2009. 

19The 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. 

receptor, which is 16. In this way, this 

maximum 2012 design value takes into 

consideration the air quality impacts of 

all known and legally applicable 

emission limitations taking effect after 

the 2003 to 2005 base period. Therefore, 

each of the projected future-year design 

values provide a fair representation of 

future air quality at receptor Y under 

different conditions while accounting 

for the emissions projected to remain in 

2012. EPA thus believes that if one of 

these future-year design values for a 

particular receptor exceeds the NAAQS, 

it is reasonable to conclude that the area 

may have difficulty maintaining that 

NAAQS. For this reason, EPA identifies 

such receptors as maintenance 

receptors. In this example, EPA would 

find that while receptor Y’s average 

future-year design value would not 

exceed the NAAQS, its maximum 

future-year design value (16) would 

exceed the NAAQS, and it would thus 

be designated as a ‘‘maintenance’’ 

receptor for purposes of the Transport 

Rule analyses. 

In the proposed rule we used air 

quality modeling to (1) Identify 

locations where we expected there to be 

nonattainment and/or maintenance 

problems for annual average PM2.5, 

24-hour PM2.5, and/or 8-hour ozone in 

2012, (2) quantify the impacts (i.e., air 

quality contributions) of SO2 and NOX

emissions from upwind states on 

downwind annual average and 24-hour 

PM2.5 concentrations at monitoring sites 

projected to be nonattainment or have 

maintenance problems in 2012 for the 

1997 annual and 2006 24-hour PM2.5

NAAQS, respectively, and (3) quantify 

the impacts of NOX emissions from 

upwind states on downwind 8-hour 

ozone concentrations at monitoring sites 

projected to be nonattainment or have 

maintenance problems in 2012 for the 

1997 ozone NAAQS. 

To support the proposal, air quality 

modeling was performed for four 

emission scenarios: a 2005 base year, a 

2012 ‘‘no CAIR’’ base case, a 2014 ‘‘no 

CAIR’’ base case, and a 2014 control 

case that reflects the emission 

reductions expected from the FIPs. The 

modeling for 2005 was used as the base 

year for projecting air quality for each of 

the 3 future-year scenarios. The 2012 

base case modeling was used to identify 

future nonattainment and maintenance 

locations and to quantify the 

contributions of emissions in upwind 

states to annual average and 24-hour 

PM2.5 and 8-hour ozone. The 2012 ozone 

and PM2.5 concentrations were derived 

by projecting 2003 through 2007 based 

ambient ozone and/or PM2.5 data to the 

future using the relative (percent) 

change in modeled concentrations 

between 2005 and 2012. The 2014 base 

case and 2014 control case modeling 

were used to quantify the benefits of 

this proposal. 

In the proposed rule, EPA used the 

Comprehensive Air Quality Model with 

Extensions (CAMx) version 5.20 18 to 

simulate ozone and PM2.5

concentrations for the 2005 base year 

and the 2012 and 2014 future year 

scenarios. The CAMx model 

applications were designed to cover 

states in the central and eastern U.S. 

using a horizontal resolution of 12 x 12 

km.19

CAMx contains ‘‘source 

apportionment’’ tools that are designed 

to quantify the contribution of 

emissions from various sources and 

areas to ozone and PM2.5 component 

species in other downwind locations. 

The source apportionment tools were 

used to quantify the downwind 

contributions of ozone and PM2.5 from 

upwind states. 

In the proposed rule, EPA used a 

2005-based air quality modeling 

platform which included 2005 base year 

emissions and 2005 meteorology for 

modeling ozone and PM2.5 with CAMx. 

We received comments related to 

several aspects of the air quality 

modeling platform. 

Comment: There was wide support 

from commenters for the use of CAMx 

as an appropriate, state-of-the science 

air quality tool for use in the Transport 

Rule. There were no comments that 

suggested that EPA should use an 

alternative model for quantifying 

interstate transport. Many commenters 

requested that EPA update the emission 

inventories used for the Transport Rule 

and then remodel the 2005 base year 

and future year emissions using the 

updated emissions and the most recent 

version of CAMx to reassess interstate 

transport for the final rule. 

Response: For the final rule we have 

updated our modeling using the latest 

public release of CAMx (version 5.30) 

and associated preprocessors. We have 

also made numerous improvements to 

the emission inventories for the 2005 

base year as well as the 2012 and 2014 

future year base cases in response to 

public comments. The emissions 

changes are described in section V.C.1. 

The projection of future year 

nonattainment and maintenance sites 

and the quantification of ozone and 

PM2.5 transport for the final rule are 

based on modeling with CAMx v5.30 

using the updated emission inventories. 

The final rule air quality projections of 

2012 nonattainment and maintenance 

are described below. The final rule 

interstate contributions are presented in 

section V.D. 

Comment: The performance 

evaluation of the 2005 base year model 

predictions for the proposed rule was 

too cursory and did not provide 

sufficient detail on model performance. 

Commenters requested additional 

analyses and spatial resolution 

describing how well base year model 

predictions compare to the 

corresponding measured values. 

Response: For the final rule we have 

expanded the scope of the model 

evaluation for 2005 to include a broader 

suite of statistics to characterize 

performance for individual subregions 

of the eastern U.S. modeling domain. 

The results of the performance 

evaluation for the final rule 2005 base 

year air quality modeling are described 

in the Air Quality Modeling Final Rule 

TSD. 

Comment: The 2005 based modeling 

platform should be updated to a more 

recent year. There were several different 

aspects of this comment. Some 

commenters stated that EPA should be 

using a more recent emission inventory 

as a base year, due to identified changes 

and updates to the inventories. Other 

commenters stated that EPA should use 

a more recent base year, due to a trend 

of improvement in air quality over the 

past few years. The commenters claim 

that the 2005-based EPA modeling does 

not account for large emission 

reductions and air quality 

improvements that have occurred over 

the last several years. 

Response: There are several reasons 

why the use of a 2005 modeling base 

case is both reasonable and, in fact, 

necessary for the Transport Rule. As 

explained in section V.B, above, because 

the Transport Rule will replace CAIR, 

EPA cannot consider reductions 

associated with CAIR in the analytical 

baseline emissions scenario. Thus, the 

base year for the air quality projections 

should be a year that represents 

emissions before CAIR was in place (i.e. 

2005). We are projecting emissions to a 

future 2012 ‘‘no CAIR’’ case and 

therefore want to best represent the air 

quality change between 2005 and 2012, 

without CAIR. To do this, we projected 

emissions that existed before CAIR was 

in effect and modeled the air quality 

change that occurs between 2005 and 

2012 without CAIR. 


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20The 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, 2004–2006, and 

2005–2007. 

21The CAIR final rule was published on May 12, 

2005. 

A key consideration in our projection 

methodology is the use of ambient data 

to anchor the design value projections to 

the future. The modeling is used in a 

relative sense by multiplying the 

modeled percent change in ozone or 

PM2.5 species concentrations by the base 

year ambient data. The ozone and PM2.5

modeling guidance recommends 

projecting design values based on 5 

years 20 of monitoring data that is 

centered on the base model year. Using 

2005 as a base emissions and 

meteorological year entailed the use of 

2003–2007 ambient air quality data (5 

years of data centered about 2005). This 

was a reasonable choice because the 

majority of the ambient data from this 

period was not impacted by CAIR 

emission reductions. 

After 2005, early emission reductions 

of SO2 and NOX in response to CAIR 

began to impact the measured air 

quality concentrations. Since the 

modeling projection methodology uses 

both modeled and observed data, 2005 

is the latest base year that we deemed 

appropriate (before CAIR emission 

reductions took place) for use in 

projecting the measured air quality to a 

2012 future year. The early years of the 

5 year period (2003, 2004, and 2005) 

were not impacted by CAIR.21 The last 

2 years in the period (2006 and 2007) 

were slightly impacted by CAIR 

emission reductions. But the 5 year 

average is weighted towards the middle 

year of the period (2005), so the impact 

of the years after CAIR promulgation 

should be minimal. 

The 2005 base year was also chosen 

because it was an appropriate 

meteorological year. In the eastern U.S. 

there was relatively high ozone during 

the summer of 2005 and relatively high 

PM2.5 periods during the year. The 

modeled attainment tests for both ozone 

and 24-hour PM2.5 depend on having a 

sufficient number of ‘‘high’’ modeled 

days to project to the future. Modeling 

a year that is not meteorologically 

conducive to ozone and/or PM2.5

formation is discouraged by the 

modeling guidance because a 

meteorological year that is not 

conducive to ozone or PM2.5 formation 

may be less responsive to changes in 

emissions in the future. Therefore, 

projecting the relative change in ozone 

or PM2.5 for a non-conducive 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 installation of 

emissions controls after 2005 were 

included in the 2012 base case 

inventory. As explained above in 

section V.B, to capture changes in EGU 

emissions between 2005 and 2012, EPA 

did not assume operation of all controls 

installed during that time period, as 

many of those controls were built in 

response to CAIR. EPA used IPM to 

project 2012 EGU emissions 

incorporating all non-CAIR enforceable 

emission constraints; operation of 

existing pollution controls was taken 

into account only where non-CAIR 

constraints made it economic or legally 

necessary to operate them. We also 

accounted for permanent source 

shutdowns that occurred after 2005. 

Where possible, we incorporated 

reported emission changes based on 

comments to the proposed rule and a 

subsequent emission inventory NODA. 

Comment: Several commenters stated 

that we used a ‘‘modeled + monitored’’ 

test in CAIR to identify future year 

nonattainment receptors, but we only 

used a modeled test in the Transport 

Rule proposal. They suggest that we 

should either go back to the ‘‘modeled 

+ monitored’’ test or explain why we 

should not use monitoring data in the 

identification of nonattainment and 

maintenance receptors. They say that 

we should not base nonattainment and 

maintenance receptors solely on 

modeled violations. They also say that 

we if we had looked at the most recent 

ambient data we would see that most of 

the modeled nonattainment and 

maintenance receptors are already 

attaining the ozone and/or PM2.5

NAAQS. 

Response: In the identification of 

future year nonattainment receptors for 

CAIR, EPA used what was called the 

‘‘modeled + monitored test’’. The most 

recent ambient data (2001–2003 design 

values at the time) were examined to 

further verify that nonattainment was 

still being measured at potential future 

year nonattainment receptors. In the 

proposed Transport Rule, EPA 

identified future year nonattainment 

and maintenance receptors based on 

modeled projections of ambient data 

from the 2003–2007 time period. The 

future year receptors were not compared 

to most recent ambient data to verify 

that nonattainment still existed. 

For the final Transport Rule, there are 

several reasons that EPA did not 

examine the most recent ambient data to 

verify that receptors were still 

measuring nonattainment. The main 

reason for dropping the ‘‘monitored’’ 

part of the modeled + monitored test is 

the fact that the most recent monitoring 

data (2007–2009 design values) include 

large emission reductions from CAIR. 

As explained in section V.B, above, 

because the Transport Rule will replace 

CAIR, we must model a future year base 

case which does not assume that CAIR 

is in place (a ‘‘no-CAIR’’ case). It is 

simply not appropriate to examine the 

current monitoring data, which 

represent air quality with CAIR 

emission reductions in place, and 

compare the values to 2012 projected air 

quality that is based on a no-CAIR 

modeling case. As discussed above, we 

modeled a 2005 base case with preCAIR emissions and a 2012 future ‘‘no 

CAIR’’ case. The change in modeled air 

quality is due to the non-CAIR 

enforceable emission changes between 

2005 and 2012 and therefore explicitly 

does not take CAIR into account. As a 

consequence, the 2012 projected design 

values represent a unique case 

(necessary for analyzing future air 

quality without either CAIR or its 

replacement Transport Rule in effect) 

that cannot be represented by current 

ambient data. 

It is also important to note that all of 

the projected 2012 design values are 

based on projections of measured 

ambient data. They are a combination of 

measured data and modeled response 

factors. Therefore, it is inaccurate to 

imply that future year nonattainment 

and maintenance receptors are solely 

based on modeled projections. The 

future year concentrations are firmly 

rooted in base year measured ambient 

data that have been projected to the 

future using modeled data. 

There are additional reasons for not 

verifying the nonattainment and 

maintenance receptors against the most 

recent ambient data. In CAIR we did not 

explicitly identify maintenance 

receptors. In the Transport Rule 

proposal we identified maintenance 

receptors based on 2012 projections of 

maximum design values from the 2003– 

2007 period. Even though receptors may 

be measuring attainment based on 

recent data, they may still be at risk for 

falling back into nonattainment. 

Therefore, even if commenters argue 

that recent data show that monitoring 

sites should not be nonattainment 

receptors (with which we disagree), the 

same argument cannot be made 

regarding maintenance receptors. 

Clearly, receptors with recent ‘‘clean’’ 

ambient data may still experience 

higher PM2.5 and/or ozone 

concentrations in the future (based on 


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22The 2010 data is preliminary. Exceptional 

event data has not been flagged and removed from 

the reported data. 

meteorological and emission variability) 

and therefore may be appropriate 

maintenance receptors. 

Comment: Several commenters claim 

that the maintenance receptor 

methodology overstates actual future 

design values. They also recommend an 

alternative methodology which takes 

into account the downward trend in 

observed PM2.5 concentrations over the 

last 5+ years. The methodology would 

remove the trend in the data where air 

quality is improving over the period by 

applying a linear fit to the data, 

calculating the residuals and then 

adding the residuals back to the average 

of the data. Given a site with a 

downward trend, this has the effect of 

decreasing the calculated maximum 

values from the early years in the period 

and increasing the values from the end 

years in the period. 

Response: EPA continues to believe 

that our approach to identify 

maintenance receptors is reasonable and 

appropriate. For the final rule, we 

continue to identify maintenance 

receptors by projecting the maximum 

design value from the 2003–2007 period 

to the future. The methodology assumes 

that the combination of emissions and 

meteorology that occurred in the base 

period (which led to relatively high 

ambient design values) could happen 

again in the future (albeit at lower 

emissions levels). There is no 

information presented by the 

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 

preliminary 22 2010 ambient data in the 

eastern U.S. show that ozone and PM2.5

values were considerably higher in 2010 

compared to 2009. In the states that are 

included in the final Transport Rule 

region, there were 158 ozone monitor 

days that exceeded 84 ppb in 2009 

compared to 412 monitor exceedance 

days in 2010. For PM2.5, there were 251 

monitor days that exceeded 35 μg/m 3 in 

2009 compared to 417 monitor 

exceedance days in 2010. Even though 

the SO2 and NOX emissions were 

generally lower in 2010, the observed 

ozone and PM2.5 concentrations were 

higher. This shows the important 

influence of meteorology on ambient 

concentrations. Clearly, the year to year 

variability due to meteorology can be 

large. We acknowledge the downward 

trend in ambient data over the last few 

years. But this does not mean that 

conditions that led to high ozone 

and/or PM2.5 in the 2003–2007 period 

could not occur again in the future. The 

2010 ambient data show that 

meteorology can cause concentrations to 

go back up, even though there is a 

downward trend in emissions. 

We also believe that the alternate 

maintenance methodology presented by 

the commenter is inappropriate. The 

EPA modeling for 2012 (and 2014) 

appropriately accounts for emission 

reductions that occur after 2005 except 

for those that should not be considered, 

as explained in section V.B., because 

they were required only by CAIR. 

Therefore, the starting point design 

values used to project to the future 

should not be lowered to account for 

emission reduction trends that occur 

after 2005. Doing so would give ‘‘double 

credit’’ to the more recent emission 

reductions and provides an 

inappropriate downward adjustment to 

the early design value periods of the 

2003–2007 period. 

Comment: One commenter claims that 

EPA did not follow our own modeling 

guidance by not doing local scale 

modeling in urban areas with high PM2.5

concentration gradients. They suggested 

that the methodology to calculate future 

year design values should have 

included dispersion modeling to 

calculate the change in concentration 

over time of primary PM2.5 emissions. 

Response: EPA modeling guidance for 

PM2.5 attainment demonstrations 

recommends photochemical grid 

modeling to examine future year 

changes in PM2.5 concentrations. There 

are several optional aspects of the 

modeling which are recommended in 

specific cases. This includes a 

recommendation for a ‘‘local area 

analysis’’ using a dispersion model. An 

area with relatively large local primary 

PM2.5 concentration gradients may want 

to do additional modeling to examine 

the impacts of local controls on its 

future year PM2.5 concentrations. This is 

particularly important when local 

controls of primary PM2.5 are included 

as part of the attainment demonstration. 

As noted above, a ‘‘local area 

analysis’’ is recommended as part of the 

local attainment demonstration process 

in specific situations. It is impractical 

for EPA to perform this type of analysis 

for each local area in the regional 

Transport Rule. National rulemakings 

are not attainment demonstrations. We 

are not able to perform fine scale 

analyses for each area. For the final rule 

modeling, we have attempted to address 

all emissions and modeling related 

comments. We have updated the 

modeling platform to use the latest 

version of CAMx and are continuing to 

model ozone and PM2.5 at 12km grid 

resolution, which for PM2.5 is a more 

refined grid resolution compared to the 

CAIR modeling. 

Additionally, there is no evidence 

presented by the commenter that would 

indicate that the future year PM2.5

concentrations from the Transport Rule 

are biased high. In fact, depending on 

the circumstances, local fine scale grid 

or dispersion modeling may result in 

lower or higher future year design 

values. In a fine scale analysis, the 

dominant local primary PM2.5 emissions 

become a larger percentage of the PM2.5

concentrations. Therefore, if the local 

emissions are forecast to decrease, fine 

scale modeling may lead to lower future 

design values. However, if the local 

emissions are forecast to increase or stay 

the same between the base and future 

years, local modeling will likely show 

higher future year design values 

compared to a regional analysis. This 

points to the fact that perceived biases 

in modeling results may not always be 

correct. 

In sum, fine scale modeling of local 

areas may lead to either higher or lower 

future year design values. There is no 

indication that EPA’s regional modeling 

is biased in either direction. EPA’s 

Transport Rule modeling generally 

followed EPA’s modeling guidance and 

is appropriate for the purpose of this 

rulemaking. 

Comment: One commenter completed 

and submitted a detailed CAMx based 

modeling analysis with a 2008 base year 

and future years of 2014 and 2018. The 

analysis shows that the majority of the 

proposed rule 2012 nonattainment and 

maintenance sites are already attaining 

based on either 2006–2008 or 2007– 

2009 ambient data. Based on this, the 

commenter claims that air quality has 

improved more rapidly than predicted 

by EPA’s proposed rule modeling. Also, 

based on the commenter’s 2014 

modeling of CAIR emissions (including 

utility consent decrees and state 

programs), the commenter concludes 

that no additional controls are needed 


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23The 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. 

24The base year design values were updated 

based on the latest official data. See http:// 

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

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 CAA. For this 

reason, and as explained in greater 

detail in section V.B of this preamble, 

any analysis of whether beyond CAIR 

controls are necessary is irrelevant to 

this rulemaking. Nonetheless, we have 

carefully reviewed different aspects of 

the commenter’s analysis. We 

previously addressed comments related 

to the use of more recent ambient data 

to examine future year nonattainment 

and maintenance receptors. As noted 

above, the 2006–2008 and 2007–2009 

ambient data is heavily influenced by 

several factors. Among them are the 

emissions reductions from CAIR, the 

relatively low recent observed ozone 

and PM2.5 concentrations at least 

partially due to non-conducive 

meteorology (particularly in 2009), and 

the atypical suppression of emissions 

due to the sharp recession. For all of 

these reasons, we believe it is not 

possible to directly compare the most 

recent design values to the predicted 

future year 2012 and 2014 design values 

from the Transport Rule. In particular, 

it is inappropriate to compare current 

design values to EPA’s no-CAIR 2012 

future year modeling results. As noted 

in the comment summary, the 

commenter’s modeling analysis 

assumed that CAIR was in place in both 

2008 and the future years. This is a 

fundamentally different assumption 

than the modeling EPA used to define 

the Transport Rule nonattainment and 

maintenance receptors in 2012 and is 

inappropriate for purposes of the 

Transport Rule for reasons described 

above and in section V.B. 

Additionally, EPA’s maintenance 

methodology chooses the highest of 

three base year design value periods 

projected to the future. The commenter 

only used a single design value period 

in their analysis and therefore did not 

fully examine maintenance issues. In 

fact, the 2014 nonattainment modeling 

receptors in the final Transport Rule 

and the commenter’s modeling analysis 

are similar. As documented in section 

VI.D, in the 2014 final rule remedy case, 

there is only one remaining 

nonattainment area for ozone and one 

remaining nonattainment area for 

24-hour PM2.5. This is similar to the 

modeling results presented in the 

comments.23 However, EPA modeling 

identifies additional maintenance 

receptors in 2012 that continue to have 

maintenance issues in 2014. 

EPA also examined our ozone and 

PM2.5 projection procedures to see if 

there might be additional reasons for the 

relatively lower current ambient design 

values (and modeled design values in 

the commenter’s analysis) compared to 

the 2014 remedy modeled values. Upon 

further analysis of EPA’s 24-hour 

attainment test methodology, we noted 

certain discrepancies between the 

methodology and the calculation of the 

ambient 24-hour design values. In the 

proposed rule 24-hour attainment test, 

for each PM2.5 monitor, we projected the 

measured 98th percentile 

concentrations from the 2003–2007 

period to the future. A basic assumption 

in this methodology is that the 

distribution of high measured days in 

the base period will be the same in the 

future. For example, if the observed 

98th percentile day is the 3rd high day 

for a particular year, we assume that the 

1st, 2nd, and 3rd high days (and 

subsequent high days) in the future 

remain in the same basic distribution. 

Further examination of the proposed 

rule modeling found that this is not 

always the case. In situations where 

there are large summer PM2.5

concentration reductions, some of the 

high days may switch from the summer 

in the base period to the winter in the 

future period. 

In order to better account for the 

complicated future response in 24-hour 

design values, we have updated the 

24-hour attainment demonstration 

methodology to more closely reflect the 

way 24-hour design values are 

calculated. In the revised methodology, 

we do not assume that the temporal 

distribution of high days in the base and 

future periods will remain the same. We 

project a larger set of ambient days from 

the base period to the future and then 

re-rank the entire set of days to find the 

new future 98th percentile value (for 

each year). More specifically, we project 

the highest 8 days per quarter (32 days 

per year) to the future and then re-rank 

the 32 days to derive the future year 

98th percentile concentrations. In the 

case of the Transport Rule model 

results, this has the effect of lowering 

the future year 24-hour design values 

compared to the old methodology. The 

2012 base case design values for all 

nonattainment and maintenance 

receptors were either unchanged or 

lower with the revised methodology. 

3. How did EPA project future 

nonattainment and maintenance for 

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

ozone? 

Final Rule: In general, the 

methodology to project ozone and PM2.5

concentrations to the future year(s) 

remains the same for the final rule. The 

proposal modeling followed the 

modeling guidance procedures for 

projecting ambient design values to 

future years. For the final rule, we 

continue to follow the basic procedures 

outlined in the guidance. The 8-hour 

ozone and annual PM2.5 methodology 

are unchanged from the proposal. 

However, the 24-hour PM2.5

methodology has been updated in the 

final rule to be more consistent with the 

calculation of 24-hour PM2.5 design 

values. There were also additional 

minor updates to the ambient data.24

The methodology to identify 

maintenance receptors is also 

unchanged from the proposal. We 

continue to use the maximum design 

value (projected from the 5 year base 

period) to calculate future year 

maintenance receptors. 

As noted in the proposal, EPA 

considers that the maintenance concept 

has two components: Year-to-year 

variability in emissions and air quality, 

and continued maintenance of the air 

quality standard over time. The way that 

EPA defined maintenance based on 

year-to-year variability (as discussed in 

detail here) directly affects the 

requirements of this final rule. EPA also 

considered whether further reductions 

were necessary to ensure continued lack 

of interference with maintenance of the 

NAAQS over time (e.g., after 2014). EPA 

concluded that in light of projected 

emission trends, and also considering 

the emission reductions from this 

proposed rule, no further reductions are 

required solely for this purpose at PM2.5

and ozone receptors for which we are 

partially or fully determining significant 

contribution for the current NAAQS. 

(See discussion of emission trends in 

Chapter 7 of TSD entitled ‘‘Emission 

Inventories,’’ included in the docket for 

the Transport Rule proposal.) 


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25U.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. 

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. 

28For 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. 

a. Which ambient ozone and PM2.5 data 

did EPA use for the purpose of 

projecting future year concentrations? 

The final rule modeling continues to 

use a 2005 base case inventory and 2005 

meteorology. Therefore, we continue to 

use ambient data from the 2003–2007 

period. For each monitoring site, all 

valid design values (up to 3) from this 

period were averaged together. Since 

2005 is included in all three design 

value periods, this has the effect of 

creating a 5-year weighted average, 

where the middle year is weighted 3 

times, the 2nd and 4th years are 

weighted twice, and the 1st and 5th 

years are weighted once. We refer to this 

as the 5-year weighted average value. 

The 5-year weighted average values 

were then projected to the future years 

that were analyzed for this final rule. 

The 2003–2005, 2004–2006, and 2005– 

2007 design values are accessible at 

http://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 guidance.25

b. Projection of Future Annual and 24- 

Hour PM2.5 Nonattainment and 

Maintenance 

(1) Methodology for Projecting Future 

Annual PM2.5 Nonattainment and 

Maintenance 

For the final rule, annual PM2.5

modeling was performed for the 2005 

base year emissions and for the 2012 

base case as part of the approach for 

projecting which locations are expected 

to be in nonattainment and/or have 

difficulty maintaining the PM2.5

standards in 2012. We refer to these 

areas as nonattainment sites and 

maintenance sites respectively. 

Concentrations of PM2.5 in 2012 were 

estimated by applying the modeled 

2005-to-2012 relative change in PM2.5

species to each of the 3-year ambient 

monitoring data periods (i.e., 2003– 

2005, 2004–2006, and 2005–2007) to 

obtain up to 3 future-year PM2.5 design 

values for each monitoring site. We used 

the highest of these projections at each 

monitoring site to determine which sites 

are expected to have maintenance 

problems in 2012. We used the 5 year 

weighted average of those projections to 

determine which monitoring sites are 

expected to be nonattainment in this 

future year. 

For the analysis of both 

nonattainment and maintenance, 

monitoring sites were included in the 

analysis if they had at least one 

complete design value in the 2003–2007 

period.26 There were 721 monitoring 

sites in the 12 km modeling domain 

which had at least one complete design 

value period for the annual PM2.5

NAAQS, and 722 sites which met this 

criterion for the 24-hour NAAQS.27

EPA followed the procedures 

recommended in the modeling guidance 

for projecting PM2.5 by projecting 

individual PM2.5 component species 

and then summing these to calculate the 

concentration of total PM2.5. EPA’s 

Modeled Attainment Test Software 

(MATS) was used to calculate the future 

year design values. The software 

(including documentation) is available 

at: http://www.epa.gov/scram001/ 

modelingapps_mats.htm. Additional 

details on the annual PM2.5

nonattainment and maintenance 

projections methodology can be found 

in the Air Quality Modeling Final Rule 

TSD. 

The 2012 annual PM2.5 design values 

were calculated for each of the 721 sites. 

The calculated annual PM2.5 design 

values are truncated after the second 

decimal place.28 This is consistent with 

the ambient monitoring data truncation 

and rounding procedures for the annual 

PM2.5 NAAQS. Any value that is greater 

than or equal to 15.05 μg/m3 is rounded 

to 15.1 μg/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 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 

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 


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29There were no updates to the ozone and annual 

PM2.5 attainment test methodology. 

TABLE V.C–1—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE ANNUAL PM2.5 DESIGN VALUES (μG/M3) AT

PROJECTED NONATTAINMENT SITES—Continued 

Monitor ID State County 

Average 

design value 

2003–2007 

Maximum 

design value 

2003–2007 

Final rule 

average design 

value 2012 

Final rule 

maximum design 

value 2012 

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 

The procedures for calculating the 

future year 24-hour PM2.5 design values 

have been updated for the final rule.29

The revised procedures are in response 

to comments which noted relatively 

high future year 24-hour PM2.5 design 

values in EPA’s modeling of the 

proposed Transport Rule. The updates 

are intended to make the projection 

methodology more consistent with the 

procedures for calculating ambient 

design values. 

As noted above, for the proposed 

Transport Rule EPA projected for each 

PM2.5 monitor the measured 98th 

percentile concentrations from the 

2003–2007 period to the future. As an 

additional check, we also projected the 

next highest concentrations from the 

three calendar quarters in each year 

when the 98th percentile did not occur 

in the 2003–2007 base period, to ensure 

that the future year 98th percentile did 

not switch seasons in the future year 

compared to the base year. A basic 

assumption in this methodology is that 

the distribution of high measured days 

in the base period will be the same in 

the future. 

In other words, EPA assumed at 

proposal that the 98th-percentile day 

could only be displaced ‘‘from below’’ 

in the instance that a different day’s 

future concentration exceeded the 

original 98th-percentile day’s future 

concentration. In that case, the original 

98th-percentile day may become the 

97th- or 96th-percentile day in the 

future year; EPA accounted for this 

possibility at proposal. EPA did not, 

however, consider that the 98thpercentile day could also be displaced 

‘‘from above’’ in the instance that 

higher-concentration days in the base 

period were projected to have future 

concentrations lower than the original 

98th-percentile day’s future 

concentration. In that case, the original 

98th-percentile day may become the 

99th- or 100th-percentile day. Because 

EPA continued to use that day’s future 

concentration to determine the 

monitor’s future design value at 

proposal, this sometimes resulted in 

overstatement of future-year design 

values for 24-hour PM2.5 monitoring 

sites whose seasonal distribution of 

highest-concentration 24-hour PM2.5

days changed between the 2003–2007 

period and the future year modeling. 

Examination of the proposed rule 

remedy modeling (2014 remedy case) 

showed that many of the highest PM2.5

days switched from the summer in the 

base period to the winter in the future 

period. This is especially true in areas 

of the upper Midwest which experience 

both high summer and winter PM2.5

episodes. 

In the revised methodology, we do not 

assume that the seasonal distribution of 

high days in the base period years and 

future years will remain the same. We 

project a larger set of ambient days from 

the base period to the future and then 

re-rank the entire set of days to find the 

new future 98th percentile value (for 

each year). More specifically, we project 

the highest 8 days per quarter (32 days 

per year) to the future and then re-rank 

the 32 days to derive the future year 

98th percentile concentrations. In the 

case of the Transport Rule model 

results, this has the effect of lowering 

the future year 24-hour design values 

compared to the old methodology. 

The modeling guidance 

recommendations for state attainment 

demonstrations have been updated to 

reflect the changes outlined above. 

Further details on the 24-hour PM2.5

design value calculations can be found 

in the Air Quality Modeling Final Rule 

TSD. The above procedures for 

determining future year 24-hour PM2.5

concentrations were applied for each 

site. The 24-hour PM2.5 design values 

are truncated after the first decimal 

place. This approach is consistent with 

the ambient data truncation and 

rounding procedures for the 24-hour 

PM2.5 NAAQS. Any value that is greater 

than or equal to 35.5 μg/m3 is rounded 

to 36 μg/m3 and is violating the 

NAAQS. Sites with future year 5-year 

weighted average design values of 35.5 

μg/m3 or greater, based on the projection 

of 5-year weighted average 

concentrations, are predicted to be 

nonattainment. Sites with future year 

maximum design values of 35.5 μg/m3

or greater are predicted to be 

maintenance sites. Note that 

nonattainment sites for the 24-hour 

NAAQS are also maintenance sites 

because the maximum design value is 

always greater than or equal to the 5- 

year weighted average. The monitoring 


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sites that we project to be nonattainment 

and/or maintenance for the 24-hour 

PM2.5 NAAQS in the 2012 base case are 

the nonattainment/maintenance 

receptors used for assessing the 

contribution of emissions in upwind 

states to downwind nonattainment and 

maintenance of 24-hour PM2.5 NAAQS 

as part of this final rule. 

Table V.C–3 contains the 2003–2007 

base period average and maximum 24- 

hour PM2.5 design values and the 2012 

base case average and maximum design 

values for sites projected to be 2012 

nonattainment of the 24-hour PM2.5

NAAQS in 2012. Table V.C–4 contains 

this same information for projected 2012 

24-hour maintenance sites. 

TABLE V.C–3—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 24-HOUR PM2.5 DESIGN VALUES (μG/M3) AT

PROJECTED NONATTAINMENT SITES

Monitor ID State County 

Average 

design value 

2003–2007 

Maximum 

design value 

2003–2007 

Final rule 

average design 

value 2012 

Final rule 

maximum design 

value 2012 

010730023 ........ Alabama .................... Jefferson ................... 44.0 44.2 36.9 37.3 

170311016 ........ Illinois ........................ Cook .......................... 43.0 46.3 37.5 40.4 

171191007 ........ Illinois ........................ Madison ..................... 39.1 40.1 36.5 36.8 

180970043 ........ Indiana ...................... Marion ....................... 38.4 39.9 35.7 37.1 

180970066 ........ Indiana ...................... Marion ....................... 38.3 39.6 35.7 36.9 

180970081 ........ Indiana ...................... Marion ....................... 38.2 39.2 35.8 36.9 

261470005 ........ Michigan .................... St Clair ...................... 39.6 40.6 36.2 37.1 

261630015 ........ Michigan .................... Wayne ....................... 40.1 40.6 35.5 36.0 

261630016 ........ Michigan .................... Wayne ....................... 42.9 45.4 38.9 41.2 

261630019 ........ Michigan .................... Wayne ....................... 40.9 41.4 37.3 37.8 

261630033 ........ Michigan .................... Wayne ....................... 43.8 44.2 39.4 39.8 

390350038 ........ Ohio ........................... Cuyahoga .................. 44.2 47.0 39.4 41.8 

390350060 ........ Ohio ........................... Cuyahoga .................. 42.1 45.7 37.7 40.8 

420030064 ........ Pennsylvania ............. Allegheny .................. 64.2 68.2 56.7 59.9 

420030093 ........ Pennsylvania ............. Allegheny .................. 45.6 51.5 39.1 44.3 

420030116 ........ Pennsylvania ............. Allegheny .................. 42.5 42.5 35.5 35.5 

420070014 ........ Pennsylvania ............. Beaver ....................... 43.4 44.6 36.2 37.4 

420710007 ........ Pennsylvania ............. Lancaster .................. 40.8 44.0 35.9 38.3 

540090011 ........ West Virginia ............. Brooke ....................... 43.9 44.9 37.5 38.3 

550790043 ........ Wisconsin .................. Milwaukee ................. 39.9 40.8 36.2 37.1 

TABLE V.C–4—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 24-HOUR PM2.5 DESIGN VALUES (μG/M3) AT

PROJECTED MAINTENANCE-ONLY SITES

Monitor ID State County 

Average 

design value 

2003–2007 

Maximum 

design value 

2003–2007 

Final rule 

average design 

value 2012 

Final rule 

maximum design 

value 2012 

010732003 ........ Alabama .................... Jefferson ................... 40.3 40.8 35.3 35.9 

170310052 ........ Illinois ........................ Cook .......................... 40.2 41.4 34.9 36.0 

170312001 ........ Illinois ........................ Cook .......................... 37.7 40.6 33.6 36.1 

170313301 ........ Illinois ........................ Cook .......................... 40.2 43.3 34.9 37.6 

170316005 ........ Illinois ........................ Cook .......................... 39.1 41.8 34.1 36.4 

171190023 ........ Illinois ........................ Madison ..................... 37.3 38.1 35.1 35.8 

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-toSeptember 24-hour maximum 8-hour 

average concentrations from the 2005 

base case and the 2012 base case were 

used to project ambient design values to 

2012. The following is a brief summary 

of the future year 8-hour average ozone 

calculations. Additional details are 

provided in the Air Quality Modeling 

Final Rule TSD. 

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 


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30As 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. 

percent change in ozone on days with 

modeled ozone greater than 85 ppb.30

The maximum future design value is 

calculated by projecting design values 

for each of the three base periods (2003– 

2005, 2004–2006, and 2005–2007) 

separately. The highest of the three 

future values is the maximum design 

value. This maximum value is used to 

identify the 8-hour ozone maintenance 

receptors. 

The future year design values are 

truncated to integers in units of ppb. 

This approach is consistent with the 

ambient data truncation and rounding 

procedures for the 8-hour ozone 

NAAQS. Future year design values that 

are greater than or equal to 85 ppb are 

considered to be violating the NAAQS. 

Sites with future year 5-year weighted 

average design values of 85 ppb or 

greater are predicted to be 

nonattainment. Sites with future year 

maximum design values of 85 ppb or 

greater are predicted to be future year 

maintenance sites. Note that, as 

described previously for the annual and 

24-hour PM2.5 NAAQS, nonattainment 

sites for the ozone NAAQS are also 

maintenance sites because the 

maximum design value is always greater 

than or equal to the 5-year weighted 

average. The monitoring sites that we 

project to be nonattainment and/or 

maintenance for the 8-hour ozone 

NAAQS in the 2012 base case are the 

nonattainment/maintenance receptors 

used for assessing the contribution of 

emissions in upwind states to 

downwind nonattainment and 

maintenance of ozone NAAQS. 

Table V.C–5 contains the 2003–2007 

base period average and maximum 

8-hour ozone design values and the 

2012 base case average and maximum 

design values for sites projected to be 

2012 nonattainment of the 8-hour ozone 

NAAQS in 2012. Table V.C–6 contains 

this same information for projected 2012 

8-hour ozone maintenance sites. 

TABLE V.C–5—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 8-HOUR OZONE DESIGN VALUES (PPB) AT

PROJECTED NONATTAINMENT SITES

Monitor ID State County 

Average 

design value 

2003–2007 

Maximum 

design value 

2003–2007 

Final rule 

average design 

value 2012 

Final rule 

maximum design 

value 2012 

220330003 ........ Louisiana ................... East Baton Rouge ..... 92.0 96 85.6 89.3 

480391004 ........ Texas ........................ Brazoria ..................... 94.7 97 86.7 88.8 

482010051 ........ Texas ........................ Harris ......................... 93.0 98 86.1 90.8 

482010055 ........ Texas ........................ Harris ......................... 100.7 103 93.3 95.4 

482010062 ........ Texas ........................ Harris ......................... 95.7 99 88.8 91.8 

482010066 ........ Texas ........................ Harris ......................... 92.3 96 87.1 90.6 

482011039 ........ Texas ........................ Harris ......................... 96.3 100 88.8 92.2 

TABLE V.C–6—AVERAGE AND MAXIMUM 2003–2007 AND 2012 BASE CASE 8-HOUR OZONE DESIGN VALUES (PPB) AT

PROJECTED MAINTENANCE-ONLY SITES

Monitor ID State County 

Average 

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 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 thresholds we proposed, and 

those comments and EPA’s responses 

are discussed below. 

b. General Comments on the Overall 

Stringency and Use of 1 Percent of the 

NAAQS 

EPA received numerous comments 

supporting and opposing the proposed 

thresholds. A number of commenters 

cited support for EPA’s approach. Some 


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commenters believed that use of a 1 

percent threshold was too stringent, and 

recommended that EPA should use a 

threshold greater than 1 percent. Others 

believed that 1 percent was not stringent 

enough, and they recommended using a 

lower value such as 0.5 percent. EPA 

believes that for both PM2.5 and for 

ozone, it is appropriate to use a 

threshold of 1 percent of the NAAQS for 

identifying states whose contributions 

do not significantly contribute to 

nonattainment or interfere with 

maintenance of the relevant NAAQS; 

therefore, EPA has retained the 1 

percent threshold for the reasons 

described below. 

As we found at the time of CAIR, 

EPA’s analysis of base case PM2.5

transport shows that, in general, PM2.5

nonattainment problems result from the 

combined impact of relatively small 

contributions from many upwind states, 

along with contributions from in-state 

sources and, in some cases, 

substantially larger contributions from a 

subset of particular upwind states. (See 

section II of the January 2004 CAIR 

proposal, 69 FR 4575–87). 

In the 1998 NOX SIP Call (63 FR 

57456, October 27, 1998) and in CAIR, 

EPA also found important contributions 

from multiple upwind states. As a result 

of the upwind ‘‘collective 

contributions,’’ EPA determined that it 

is appropriate to use a low air quality 

threshold when analyzing upwind 

states’ contributions to downwind 

states’ attainment and maintenance 

problems for ozone as well as PM2.5. 

Low threshold values are also 

warranted, as EPA discussed in the 

notices for CAIR, due to adverse health 

impacts associated with ambient PM2.5

and ozone even at low concentrations 

(See relevant portions of the CAIR 

proposal notice (63 FR 4583–84) and the 

CAIR final rule notice (70 FR 25189– 

25192)). 

To aid in responding to comments, 

EPA has compiled the contribution 

modeling results to analyze the impact 

of different possible thresholds. This 

analysis demonstrates the 

reasonableness of using the 1 percent 

threshold to account for the combined 

impact of relatively small contributions 

from many upwind states (see Air 

Quality Modeling Final Rule TSD). In 

this analysis, EPA identifies for annual 

PM2.5 (sulfate and nitrate), 24-hour 

PM2.5 (sulfate and nitrate), and 8-hour 

ozone receptors: (1) Total upwind state 

contributions, and (2) the amount of the 

total upwind state contribution that is 

captured at thresholds of 1 percent, 5 

percent and 0.5 percent of the NAAQS. 

EPA continues to find that the total 

‘‘collective contribution’’ from upwind 

sources represents a large portion of 

PM2.5 and ozone at downwind locations 

and that the total amount of transport is 

composed of the individual contribution 

from numerous upwind states. 

The analysis shows that the 1 percent 

threshold captures a high percentage of 

the total pollution transport affecting 

downwind states for both PM2.5 and 

ozone. In response to commenters who 

advocated a higher threshold, EPA 

observes that higher thresholds would 

exclude increasingly large percentages 

of total transport, which we do not 

believe would be appropriate. For 

example, a 5 percent threshold would 

exclude the majority—and for annual 

PM, more than 80 percent—of interstate 

pollution transport affecting the 

downwind state receptors analyzed 

(based on the average percentage of total 

interstate transport across all receptors 

captured at the 5 percent threshold). 

In response to commenters who 

advocated a lower threshold, EPA 

observes that the analysis shows that a 

lower threshold such as 0.5 percent 

would result in relatively modest 

increases in the overall percentages of 

PM2.5 and ozone pollution transport 

captured relative to the amounts 

captured at the 1 percent level. A 0.5 

percent threshold could lead to 

emission reduction responsibilities in 

additional states that individually have 

a very small impact on those receptors— 

an indicator that emission controls in 

those states are likely to have a smaller 

air quality impact at the downwind 

receptor. We are not convinced that 

selecting a threshold below 1 percent is 

necessary or desirable. A strong 

indication that the amount of pollution 

transport being excluded from 

consideration is not excessive is that the 

controls required under this rule are 

projected to eliminate nonattainment 

and maintenance problems with air 

quality standards at most downwind 

state receptors. 

Considering the combined downwind 

impact of multiple upwind states, the 

health effects of low levels of PM2.5 and 

ozone pollution, and EPA’s previous use 

of a 1 percent threshold for PM2.5 in 

CAIR, EPA’s judgment is that the 1 

percent threshold is a reasonable choice. 

Some commenters noted that the 

PM2.5 thresholds used for this rule are 

less than the ‘‘significant impact levels’’ 

(SILs) used for permitting programs. As 

EPA stated at the time of CAIR, since 

the thresholds referred to by the 

commenters serve different purposes 

than the CAIR threshold for significant 

contribution, it does not follow that they 

should be made equivalent (70 FR 

25191; 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 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 believes to be counterintuitive and unworkable as an 

approach for assessing interstate 

contributions. 

Therefore, for this rule, EPA proposed 

and is now finalizing an approach that 

decouples the precision of the air 

quality thresholds from the monitoring 

reporting requirements, and uses 2-digit 

values representing one percent of the 

PM2.5 NAAQS; that is, 0.15 μg/m3 for 

the annual standard, and 0.35 μg/m3 for 

the 24-hour standard. EPA believes 

there are a number of considerations 

favoring this approach. First, it provides 

for a consistent approach for the annual 

and 24-hour standards. Second, the 


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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 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 transportrelated 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 MultiFactor Test EPA Used for Ozone in 

CAIR 

Some commenters suggested that, for 

ozone, EPA should use the multiplemetric test we used for CAIR, and not 

a simple threshold based on 1 percent 

of the NAAQS. With respect to ozone, 

EPA proposed in the Transport Rule to 

take a more straightforward approach to 

air quality thresholds than the multifactor 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 it provides for a consistent 

approach that takes into account, and is 

applicable to, any future ozone 

standards below 0.08 ppm. 

One of these commenters suggested 

that the 0.8 ppb threshold value was 

substantially more stringent than the 2 

ppb screening test which was a part of 

the approach used for CAIR. The 1 

percent threshold (0.8 ppb) is not 

substantially more stringent than the 

previous 2 ppb test because of 

differences in the metrics used to 

evaluate contributions against these two 

levels. The 2 ppb test was evaluated 

using the highest single day absolute 

model-predicted downwind 

contribution from an upwind state. The 

1 percent threshold is evaluated based 

on the average relative downwind 

impact calculated over multiple days. 

Therefore, it is appropriate to set a 

lower concentration threshold for use 

with the average contribution metric 

calculated for the Transport Rule. More 

details on the calculation of the 

contribution metric can be found in the 

Air Quality Modeling Final Rule TSD. 

As noted above, EPA believes that the 

approach used for the proposed rule 

provides for a simplified, yet robust 

approach compared to CAIR. 

Accordingly, for the final rule we have 

retained the approach used for the 

proposal. 

One commenter suggested that EPA 

retain the CAIR multiple-factor 

approach for ozone, and to apply that 

same approach to 24-hour PM2.5. As 

noted above, EPA is not retaining this 

approach for ozone, and for similar 

reasons we believe a multi-factor 

approach is not needed for 24-hour 

PM2.5. The approach based on 1 percent 

of the NAAQS is consistent with the 

form of the 24-hour standard. In 

addition, this approach is based on 

contributions on days with high 24-hour 

PM2.5 predictions and therefore is 

relevant for characterizing transport 

during short-term high PM2.5 episodic 

conditions. 

e. Comments on the Relationship to 

Measurement Precision 

Other commenters suggested that, as 

did commenters on the thresholds used 

in CAIR, EPA should take into 

consideration the measurement 

precision of existing PM2.5 monitors in 

setting the thresholds for the Transport 

Rule. EPA disagrees that monitoring 

precision is relevant to determining the 

amount of modeled PM2.5 or ozone that 

should be considered to be a 

‘‘contribution’’ from upwind states since 

states are not required to, nor would it 

be possible for them to, measure their 

individual state impacts on downwind 

receptors. The approach for eliminating 

significant contribution is based on the 

implementation of enforceable 

emissions budgets and not on a 

measurement of ambient air quality. 

Thus, EPA believes it is a reasonable 

exercise of its discretion to de-couple 

monitoring precision from the choice of 

contribution states. 

f. Comments Related to the CAIR Court 

Decision 

Commenters recommended that EPA 

should have retained the criteria used 

for CAIR because those values were 

upheld by the Court. As noted above, 

EPA could not have used the approach 

for annual PM2.5 that was used in CAIR 

to develop a 24-hour PM2.5 threshold, as 

that approach would have yielded a 

threshold value of zero 24-hour PM2.5. 

Further, nothing in the North Carolina 

opinion suggests that the thresholds and 

methods used in CAIR were the only 

possible approaches EPA could have 

used, that they were preferable to other 

approaches, or that other alternatives 

would not be acceptable. Instead, the 

Court upheld the 0.2 μg/m3 threshold 

used for PM2.5 on the grounds that it 

was not ‘‘wholly unsupported by the 

record’’ (North Carolina, 531 F.3d at 

915). EPA has determined for reasons 

explained in the record that the 

thresholds used in this final rule are 

both reasonable and appropriate for use 

in this final rule. 

2. Approach for Identifying Contributing 

Upwind States 

This section documents the 

procedures used by EPA to quantify the 

contribution of emissions in specific 

upwind states to air quality 

concentrations in projected 2012 

downwind nonattainment and 

maintenance locations for annual PM2.5, 

24-hour PM2.5, and 8-hour ozone. In the 


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31As 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. 

32There 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. 

proposed rule EPA used CAMx 

photochemical source apportionment 

modeling to quantify the impact of 

emissions in specific upwind states on 

projected downwind nonattainment and 

maintenance receptors for both PM2.5

and 8-hour ozone. In this modeling we 

tracked the ozone and PM2.5 formed 

from 2012 base case emissions from 

anthropogenic sources in each upwind 

state in the 12 km modeling domain. 

The CAMx Particulate Source 

Apportionment Technique (PSAT) was 

used to calculate downwind 

contributions to nonattainment and 

maintenance of PM2.5. In the PSAT 

simulation NOX emissions are tracked to 

particulate nitrate concentrations, SO2

emissions are tracked to particulate 

sulfate concentrations, and primary 

particulates (organic carbon, elemental 

carbon, and other PM2.5) are tracked as 

primary particulates. As described 

earlier in section V.A, the nitrate and 

sulfate contributions were combined 

and used to evaluate interstate 

contributions of PM2.5. 

The CAMx Ozone Source 

Apportionment Technique (OSAT) was 

used to calculate downwind 8-hour 

ozone contributions to nonattainment 

and maintenance. OSAT tracks the 

formation of ozone from NOX and VOC 

emissions. 

Comment: Three commenters stated 

that the CAMx source apportionment 

techniques used for the proposed rule 

reflect state-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 location in the modeling domain 

is tracked back to specific sources of 

emissions and boundary conditions to 

fully characterize culpable sources. No 

commenters provided technically valid 

analyses indicating that EPA’s use of 

CAMx source apportionment techniques 

are inappropriate for the purposes of the 

Transport Rule. 

Comment: We received comments 

that certain states included in the 

proposed rule should be excluded from 

the final rule because EPA had 

overstated the 2012 emissions in these 

states. Commenter requested that we 

redo the contribution modeling using 

2012 base case emission inventories that 

are revised based on proposed rule 

comments. Several commenters also 

asked that EPA update the contribution 

modeling analyses using the latest 

version of CAMx. 

Response: In response to these 

comments, we have rerun our source 

apportionment modeling for PM2.5 and 

ozone for the 2012 base case using the 

updated emission inventories described 

above in section V.C.1 and the latest 

version of CAMx, version 5.30. 

The states EPA analyzed for interstate 

contributions for ozone and for PM2.5 for 

the final rule are: Alabama, Arkansas, 

Connecticut, Delaware, Florida, Georgia, 

Illinois, Indiana, Iowa, Kansas, 

Kentucky, Louisiana, Maine, 

Maryland,31 Massachusetts, Michigan, 

Minnesota, Mississippi, Missouri, 

Nebraska, New Hampshire, New Jersey, 

New York, North Carolina, North 

Dakota, Ohio, Oklahoma, Pennsylvania, 

Rhode Island, South Carolina, South 

Dakota, Tennessee, Texas, Vermont, 

Virginia, West Virginia, and 

Wisconsin.32 These are the same states 

that EPA analyzed for the proposed rule. 

For the proposed rule, we used a 

relative approach for calculating the 

contributions to downwind 

nonattainment and maintenance 

receptors from the outputs of the source 

apportionment modeling. As part of this 

approach, the source apportionment 

predictions are combined with 

measurement-based concentrations to 

calculate the contributions from each 

state to nonattainment and/or 

maintenance receptors. This is similar 

to the approach used to calculate future 

year design values, as described in 

section V.C.2. 

Comment: One commenter said that 

using the source apportionment 

modeling predictions in a relative sense 

strengthens the determination of 

contributions and addresses an 

important source of uncertainty. There 

were no comments that suggested an 

alternative approach. 

Response: For the final Transport 

Rule we are applying the relative 

approach developed for the proposed 

rule to calculate contributions from each 

state to downwind nonattainment and 

maintenance receptors. 

As noted above, for the final rule we 

modeled the updated 2012 base case 

emissions using CAMX v5.30 to 

determine the contributions from 

emissions in upwind states to 

nonattainment and maintenance sites in 

downwind states. Contributions to 

nonattainment and maintenance 

receptors are evaluated independently 

for each state to determine if the 

contributions are at or above the 

threshold criteria. 

For each upwind state, the maximum 

contribution to nonattainment is 

calculated based on the single largest 

contribution to a future year (2012) 

downwind nonattainment receptor. The 

maximum contribution to maintenance 

is calculated based on the single largest 

contribution to a future year (2012) 

downwind maintenance receptor. Since 

the contributions are calculated 

independently for each receptor, the 

upwind contribution to maintenance 

can sometimes be larger than the 

contribution to nonattainment, and vice 

versa. This also means that maximum 

contributions to nonattainment can be 

below the threshold while maximum 

contributions to maintenance may be at 

or above the threshold, or vice versa. 

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/m 3 or more to 

24-hour PM2.5 nonattainment or 

maintenance in another state are 

identified as states with contributions to 

downwind nonattainment and 

maintenance sites large enough to 

warrant further analysis. 

For annual PM2.5, we calculated each 

state’s contribution to each of the 12 

monitoring sites that are projected to be 

nonattainment and each of the 4 sites 

that are projected to have maintenance 

problems for the annual PM2.5 NAAQS 

in the 2012 base case. A detailed 


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33As 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. 

description of the calculations can be 

found in the Air Quality Modeling Final 

Rule TSD. The largest contribution from 

each state to annual PM2.5

nonattainment in downwind sites is 

provided in Table V.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 

contributions from each state to all 

projected 2012 nonattainment and 

maintenance sites for the annual PM2.5

NAAQS are provided in the Air Quality 

Modeling Final Rule TSD. 

TABLE V.D–1—LARGEST CONTRIBUTION TO DOWNWIND ANNUAL PM2.5 (μG/M3) NONATTAINMENT AND MAINTENANCE FOR

EACH OF 37 STATES

Upwind state 

Largest downwind 

contribution to nonattainment for annual PM2.5 (μg/m3) 

Largest downwind 

contribution to 

maintenance 

for annual PM2.5

(μg/m3) 

Alabama ................................................................................................................................................... 0.51 0.19 

Arkansas .................................................................................................................................................. 0.10 0.04 

Connecticut .............................................................................................................................................. 0.00 0.00 

Delaware .................................................................................................................................................. 0.00 0.00 

Florida ...................................................................................................................................................... 0.08 0.01 

Georgia .................................................................................................................................................... 0.46 0.13 

Illinois ....................................................................................................................................................... 0.50 0.65 

Indiana ..................................................................................................................................................... 1.34 1.27 

Iowa ......................................................................................................................................................... 0.26 0.14 

Kansas ..................................................................................................................................................... 0.09 0.04 

Kentucky .................................................................................................................................................. 0.94 0.81 

Louisiana .................................................................................................................................................. 0.09 0.03 

Maine ....................................................................................................................................................... 0.00 0.00 

Maryland .................................................................................................................................................. 0.15 0.06 

Massachusetts ......................................................................................................................................... 0.00 0.00 

Michigan ................................................................................................................................................... 0.64 0.64 

Minnesota ................................................................................................................................................ 0.14 0.09 

Mississippi ................................................................................................................................................ 0.05 0.01 

Missouri .................................................................................................................................................... 1.22 0.27 

Nebraska .................................................................................................................................................. 0.06 0.03 

New Hampshire ....................................................................................................................................... 0.00 0.00 

New Jersey .............................................................................................................................................. 0.02 0.01 

New York ................................................................................................................................................. 0.21 0.21 

North Carolina .......................................................................................................................................... 0.20 0.06 

North Dakota ............................................................................................................................................ 0.06 0.04 

Ohio ......................................................................................................................................................... 1.34 0.94 

Oklahoma ................................................................................................................................................. 0.08 0.03 

Pennsylvania ............................................................................................................................................ 0.54 0.54 

Rhode Island ............................................................................................................................................ 0.00 0.00 

South Carolina ......................................................................................................................................... 0.24 0.04 

South Dakota ........................................................................................................................................... 0.03 0.01 

Tennessee ............................................................................................................................................... 0.32 0.32 

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 

states 33 which contribute 0.15 μg/m3 or 

more to downwind annual PM2.5

nonattainment. These states are: 

Alabama, Georgia, Illinois, Indiana, 

Iowa, Kentucky, Maryland, Michigan, 

Missouri, New York, North Carolina, 

Ohio, Pennsylvania, South Carolina, 

Tennessee, Texas, West Virginia, and 

Wisconsin. In Table V.D–2, we provide 

a list of the downwind nonattainment 

sites to which each upwind state 

contributes 0.15 μg/m3 or more (i.e., the 

upwind state to downwind 

nonattainment ‘‘linkages’’). 

There are 12 states which contribute 

0.15 μg/m3 or more to downwind 

annual PM2.5 maintenance. These states 

are: Alabama, Illinois, Indiana, 

Kentucky, Michigan, Missouri, New 

York, Ohio, Pennsylvania, Tennessee, 

West Virginia, and Wisconsin. In Table 

V.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’’). 


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TABLE V.D–2—UPWIND STATE TO DOWNWIND NONATTAINMENT SITE ‘‘LINKAGES’’ FOR ANNUAL PM2.5

Upwind state Downwind receptor sites 

Alabama ................ Fulton, GA (131210039) ...... Hamilton, OH (390610014) .. Hamilton, OH (390610042) .. Hamilton, OH (390618001). 

Georgia ................. Jefferson, AL (10730023) .... Jefferson, AL (10732003).

Illinois .................... Jefferson, AL (10732003) .... Fulton, GA (131210039) ...... Wayne, MI (261630033) ...... Cuyahoga, OH (390350038). 

Cuyahoga, OH (390350045) Cuyahoga, OH (390350060) Hamilton, OH (390610014) .. Hamilton, OH (390610042). 

Hamilton, OH (390618001) .. Allegheny, PA (420030064).

Indiana .................. Jefferson, AL (10730023) .... Jefferson, AL (10732003) .... Fulton, GA (131210039) ...... Madison, IL (171191007). 

Wayne, MI (261630033) ...... Cuyahoga, OH (390350038) Cuyahoga, OH (390350045) Cuyahoga, OH (390350060). 

Hamilton, OH (390610014) .. Hamilton, OH (390610042) .. Hamilton, OH (390618001) .. Allegheny, PA (420030064). 

Iowa ...................... Madison, IL (171191007).

Kentucky ............... Jefferson, AL (10730023) .... Jefferson, AL (10732003) .... Fulton, GA (131210039) ...... Madison, IL (171191007). 

Wayne, MI (261630033) ...... Cuyahoga, OH (390350038) Cuyahoga, OH (390350045) Cuyahoga, OH (390350060). 

Hamilton, OH (390610014) .. Hamilton, OH (390610042) .. Hamilton, OH (390618001) .. Allegheny, PA (420030064). 

Maryland ............... Allegheny, PA (420030064).

Michigan ................ Madison, IL (171191007) ..... Cuyahoga, OH (390350038) Cuyahoga, OH (390350045) Cuyahoga, OH (390350060).

Hamilton, OH (390610014) .. Hamilton, OH (390610042) .. Hamilton, OH (390618001) .. Allegheny, PA (420030064). 

Missouri ................. Madison, IL (171191007) ..... Cuyahoga, OH (390350038) Cuyahoga, OH (390350045) Cuyahoga, OH (390350060). 

Hamilton, OH (390610014) .. Hamilton, OH (390610042) .. Hamilton, OH (390618001).

New York .............. Cuyahoga, OH (390350038) Cuyahoga, OH (390350045) Cuyahoga, OH (390350060) Allegheny, PA (420030064). 

North Carolina ....... Fulton, GA (131210039).

Ohio ...................... Jefferson, AL (10730023) .... Jefferson, AL (10732003) .... Fulton, GA (131210039) ...... Madison, IL (171191007). 

Wayne, MI (261630033) ...... Allegheny, PA (420030064).

Pennsylvania ......... Fulton, GA (131210039) ...... Wayne, MI (261630033) ...... Cuyahoga, OH (390350038) Cuyahoga, OH (390350045). 

Cuyahoga, OH (390350060) Hamilton, OH (390610014) .. Hamilton, OH (390610042) .. Hamilton, OH (390618001). 

South Carolina ...... Fulton, GA (131210039).

Tennessee ............ Jefferson, AL (10730023) .... Jefferson, AL (10732003) .... Fulton, GA (131210039) ...... Madison, IL (171191007). 

Hamilton, OH (390610014) .. Hamilton, OH (390610042) .. Hamilton, OH (390618001).

Texas .................... Madison, IL (171191007).

West Virginia ......... Fulton, GA (131210039) ...... Wayne, MI (261630033) ...... Cuyahoga, OH (390350038) Cuyahoga, OH (390350045).

Cuyahoga, OH (390350060) Hamilton, OH (390610014) .. Hamilton, OH (390610042) .. Hamilton, OH (390618001). 

Allegheny, PA (420030064).

Wisconsin .............. Madison, IL (171191007) ..... Wayne, MI (261630033) ...... Cuyahoga, OH (390350038) Cuyahoga, OH (390350045)

Cuyahoga, OH (390350060) Hamilton, OH (390610014) .. Hamilton, OH (390618001).

TABLE V.D–3—UPWIND STATE TO DOWNWIND MAINTENANCE SITE ‘‘LINKAGES’’ FOR ANNUAL PM2.5

Upwind state Downwind receptor sites 

Alabama ................ Marion, IN (180970081) ....... Marion, IN (180970083) ....... Hamilton, OH (390617001). 

Illinois .................... Marion, IN (180970081) ....... Marion, IN (180970083) ....... Cuyahoga, OH (390350065) Hamilton, OH (390617001). 

Indiana .................. Cuyahoga, OH (390350065) Hamilton, OH (390617001). 

Kentucky ............... Marion, IN (180970081) ....... Marion, IN (180970083) ....... Cuyahoga, OH (390350065) Hamilton, OH (390617001). 

Michigan ................ Marion, IN (180970081) ....... Marion, IN (180970083) ....... Cuyahoga, OH (390350065) Hamilton, OH (390617001). 

Missouri ................. Marion, IN (180970081) ....... Marion, IN (180970083) ....... Cuyahoga, OH (390350065) Hamilton, OH (390617001). 

New York .............. Cuyahoga, OH (390350065). 

Ohio ...................... Marion, IN (180970081) ....... Marion, IN (180970083). 

Pennsylvania ......... Marion, IN (180970081) ....... Marion, IN (180970083) ....... Cuyahoga, OH (390350065) Hamilton, OH (390617001). 

Tennessee ............ Marion, IN (180970081) ....... Marion, IN (180970083) ....... Hamilton, OH (390617001). 

West Virginia ......... Marion, IN (180970081) ....... Marion, IN (180970083) ....... Cuyahoga, OH (390350065) Hamilton, OH (390617001). 

Wisconsin .............. Marion, IN (180970081) ....... Marion, IN (180970083) ....... Cuyahoga, OH (390350065) Hamilton, OH (390617001). 

For 24-hour PM2.5, we calculated each 

state’s contribution to each of the 20 

monitoring sites that are projected to be 

nonattainment and each of the 21 sites 

that are projected to have maintenance 

problems for the 24-hour PM2.5 NAAQS 

in the 2012 base case. A detailed 

description of the calculations can be 

found in the Air Quality Modeling Final 

Rule TSD. The largest contribution from 

each state to 24-hour PM2.5

nonattainment in downwind sites is 

provided in Table V.D–4. The largest 

contribution from each state to 24-hour 

PM2.5 maintenance in downwind sites is 

also provided in Table V.D–4. The 

contributions from each state to all 

projected 2012 nonattainment and 

maintenance sites for the 24-hour PM2.5

NAAQS are provided in the Air Quality 

Modeling Final Rule TSD. 

TABLE V.D–4—LARGEST CONTRIBUTION TO DOWNWIND 24-HOUR PM2.5 (μG/M3) NONATTAINMENT AND MAINTENANCE FOR

EACH OF 37 STATES

Upwind state 

Largest downwind 

contribution to nonattainment for 24- 

hour PM2.5 (μg/m3) 

Largest downwind 

contribution to 

maintenance for 

24-hour PM2.5

(μg/m3) 

Alabama ................................................................................................................................................... 0.51 0.42 


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34As 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. 

TABLE V.D–4—LARGEST CONTRIBUTION TO DOWNWIND 24-HOUR PM2.5 (μG/M3) NONATTAINMENT AND MAINTENANCE FOR

EACH OF 37 STATES—Continued 

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) 

Arkansas .................................................................................................................................................. 0.24 0.23 

Connecticut .............................................................................................................................................. 0.10 0.18 

Delaware .................................................................................................................................................. 0.22 0.20 

Florida ...................................................................................................................................................... 0.07 0.03 

Georgia .................................................................................................................................................... 1.10 0.92 

Illinois ....................................................................................................................................................... 3.72 5.70 

Indiana ..................................................................................................................................................... 3.56 5.15 

Iowa ......................................................................................................................................................... 0.82 1.55 

Kansas ..................................................................................................................................................... 0.37 0.81 

Kentucky .................................................................................................................................................. 4.38 3.58 

Louisiana .................................................................................................................................................. 0.11 0.13 

Maine ....................................................................................................................................................... 0.06 0.10 

Maryland .................................................................................................................................................. 2.83 2.11 

Massachusetts ......................................................................................................................................... 0.19 0.30 

Michigan ................................................................................................................................................... 1.86 2.03 

Minnesota ................................................................................................................................................ 0.61 1.01 

Mississippi ................................................................................................................................................ 0.06 0.07 

Missouri .................................................................................................................................................... 3.73 3.71 

Nebraska .................................................................................................................................................. 0.24 0.52 

New Hampshire ....................................................................................................................................... 0.05 0.10 

New Jersey .............................................................................................................................................. 0.68 0.75 

New York ................................................................................................................................................. 0.83 1.34 

North Carolina .......................................................................................................................................... 0.40 0.38 

North Dakota ............................................................................................................................................ 0.21 0.33 

Ohio ......................................................................................................................................................... 5.85 4.74 

Oklahoma ................................................................................................................................................. 0.17 0.20 

Pennsylvania ............................................................................................................................................ 2.85 2.29 

Rhode Island ............................................................................................................................................ 0.02 0.03 

South Carolina ......................................................................................................................................... 0.29 0.25 

South Dakota ........................................................................................................................................... 0.10 0.17 

Tennessee ............................................................................................................................................... 1.38 1.30 

Texas ....................................................................................................................................................... 0.37 0.33 

Vermont ................................................................................................................................................... 0.03 0.05 

Virginia ..................................................................................................................................................... 1.21 1.01 

West Virginia ............................................................................................................................................ 4.02 3.33 

Wisconsin ................................................................................................................................................. 0.69 0.97 

Based on the state-by-state 

contribution analysis, there are 21 

states 34 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’’). 

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). 


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

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). 

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). 

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).

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). 

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).


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48244 Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations 

35There 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. 

TABLE V.D–6—UPWIND STATE TO DOWNWIND MAINTENANCE SITE ‘‘LINKAGES’’ FOR 24-HOUR PM2.5—Continued 

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).

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). 

Jefferson, OH (390811001) Montgomery, OH 

(391130032).

Allegheny, PA (420031008) Allegheny, PA (420031301). 

Allegheny, PA (420033007) York, PA (421330008) ......... Milwaukee, WI (550790010).

Wisconsin .............. Cook, IL (170310052) .......... Cook, IL (170312001) .......... Cook, IL (170313301) .......... Cook, IL (170316005). 

Lake, IN (180890022) .......... Lake, IN (180890026).

b. Estimated Interstate Contributions to 

8-Hour Ozone 

In this section, we present the 

interstate contributions from emissions 

in upwind states to downwind 

nonattainment and maintenance sites 

for the ozone NAAQS. As described 

previously in section V.D.1, states 

which contribute 0.8 ppb or more to 

8-hour ozone nonattainment or 

maintenance in another state are 

identified as states with contributions to 

downwind attainment and maintenance 

sites large enough to warrant further 

analysis. 

We calculated each state’s 

contribution to ozone at each of the 4 

monitoring sites that are projected to be 

nonattainment and each of 6 35 sites that 

are projected to have maintenance 

problems for the 8-hour ozone NAAQS 

in the 2012 base case. A detailed 

description of the calculations can be 

found in the Air Quality Modeling Final 

Rule TSD. The largest contribution from 

each state to 8-hour ozone 

nonattainment in downwind sites is 

provided in Table V.D–7. The largest 

contribution from each state to 8-hour 

ozone maintenance in downwind sites 

is also provided in Table V.D.2–7. The 

contributions from each state to all 

projected 2012 nonattainment and 

maintenance sites for the 8-hour ozone 

NAAQS are provided in the Air Quality 

Modeling Final Rule TSD. 

TABLE V.D–7—LARGEST CONTRIBUTION TO DOWNWIND 8-HOUR OZONE NONATTAINMENT AND MAINTENANCE FOR EACH

OF 37 STATES

Upwind state 

Largest downwind 

contribution to 

nonattainment for 

ozone 

(ppb) 

Largest downwind 

contribution to 

maintenance for 

ozone 

(ppb) 

Alabama ................................................................................................................................................... 4.0 2.8 

Arkansas .................................................................................................................................................. 2.1 2.0 


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36As discussed in section III, EPA is issuing a 

supplemental notice of proposed rulemaking to 

provide an opportunity for public comment on our 

conclusion that emissions from Iowa, Kansas, 

Michigan, Missouri, Oklahoma, and Wisconsin 

significantly contribute to nonattainment or 

interfere with maintenance of the 1997 ozone 

NAAQS in other states. 

37As 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. 

38As discussed in section III, EPA is issuing a 

supplemental notice of proposed rulemaking to 

provide an opportunity for public comment on our 

conclusion that emissions from Iowa, Kansas, 

Michigan, Missouri, Oklahoma, and Wisconsin 

significantly contribute to nonattainment or 

interfere with maintenance of the 1997 ozone 

NAAQS in other states. 

TABLE V.D–7—LARGEST CONTRIBUTION TO DOWNWIND 8-HOUR OZONE NONATTAINMENT AND MAINTENANCE FOR EACH

OF 37 STATES—Continued 

Upwind state 

Largest downwind 

contribution to 

nonattainment for 

ozone 

(ppb) 

Largest downwind 

contribution to 

maintenance for 

ozone 

(ppb) 

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 2.7 

Massachusetts ......................................................................................................................................... 0.0 0.6 

Michigan ................................................................................................................................................... 0.0 0.9 

Minnesota ................................................................................................................................................ 0.3 0.2 

Mississippi ................................................................................................................................................ 4.0 3.3 

Missouri .................................................................................................................................................... 1.1 4.8 

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

New Hampshire ....................................................................................................................................... 0.0 0.1 

New Jersey .............................................................................................................................................. 0.0 11.5 

New York ................................................................................................................................................. 0.0 18.8 

North Carolina .......................................................................................................................................... 0.5 1.3 

North Dakota ............................................................................................................................................ 0.2 0.1 

Ohio ......................................................................................................................................................... 0.1 3.2 

Oklahoma ................................................................................................................................................. 0.3 2.8 

Pennsylvania ............................................................................................................................................ 0.1 8.2 

Rhode Island ............................................................................................................................................ 0.0 0.0 

South Carolina ......................................................................................................................................... 0.4 0.9 

South Dakota ........................................................................................................................................... 0.1 0.1 

Tennessee ............................................................................................................................................... 2.2 1.1 

Texas ....................................................................................................................................................... 3.9 1.9 

Vermont ................................................................................................................................................... 0.0 0.0 

Virginia ..................................................................................................................................................... 0.2 8.2 

West Virginia ............................................................................................................................................ 0.0 2.8 

Wisconsin ................................................................................................................................................. 0.2 2.2 

Based on the state-by-state 

contribution analysis, there are 11 states 

that contribute 0.8 ppb or more to 

downwind 8-hour ozone nonattainment. 

These states are: Alabama, Arkansas, 

Georgia, Illinois, Indiana, Kentucky, 

Louisiana, Mississippi, Missouri, 

Tennessee, and Texas.36 In Table V.D– 

8, we provide a list of the downwind 

nonattainment counties to which each 

upwind state contributes 0.8 ppb or 

more (i.e., the upwind state to 

downwind nonattainment ‘‘linkages’’). 

There are 26 states 37 which 

contribute 0.8 ppb or more to 

downwind 8-hour ozone maintenance. 

These states are: Alabama, Arkansas, 

Florida, Georgia, Illinois, Indiana, Iowa, 

Kansas, Kentucky, Louisiana, Maryland, 

Michigan, Mississippi, Missouri, New 

Jersey, New York, North Carolina, Ohio, 

Oklahoma, Pennsylvania, South 

Carolina, Tennessee, Texas, Virginia, 

West Virginia, and Wisconsin.38 In 

Table V.D.2–9, we provide a list of the 

downwind nonattainment counties to 

which each upwind state contributes 0.8 

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

downwind nonattainment ‘‘linkages’’). 


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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).

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).

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 

A. Cost and Air Quality Structure for 

Defining Reductions 

1. Summary 

Section V, above, describes EPA’s 

approach to identifying upwind states 

with air quality contributions that meet 

or exceed the air quality thresholds 

discussed therein for each of the 

NAAQS addressed in this rule. A state 

is covered by the Transport Rule if its 

contributions meet or exceed one of 

those air quality thresholds and the 

Agency identifies, using the cost- and 

air quality-based approach described 

below, emissions within the state that 

constitute the state’s significant 

contribution to nonattainment and 

interference with maintenance with 

respect to the 1997 ozone, 1997 PM2.5 or 

2006 PM2.5 NAAQS. 

In this section, EPA explains its final 

cost- and air 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 

this rule: The 1997 ozone NAAQS, the 

1997 annual PM2.5 NAAQS and the 2006 

24-hour PM2.5 NAAQS. EPA believes 

that the methodology finalized could 

also be used to address transport 

concerns under other NAAQS, 

including future revisions to the ozone 

and PM2.5 NAAQS. 

EPA applies the methodology 

described herein to fully quantify the 

emissions that constitute each covered 

state’s significant contribution to 

nonattainment and interference with 

maintenance with 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 


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39This area is not currently designated as 

nonattainment for the 24-hour PM2.5 standard. EPA 

is portraying the receptors and counties in this area 

as a single 24-hour maintenance area based on the 

annual PM2.5 nonattainment designation of 

Chicago-Gary-Lake County, IL-IN. 

40 In the Transport Rule proposal, EPA noted that 

the Liberty-Clairton receptor in Allegheny county 

was significantly impacted by local emissions from 

a sizeable coke production facility and other nearby 

sources (75 FR 45281). 

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, ozoneseason 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. We finalize 

FIPs with respect to the 1997 ozone 

standards for 10 of these 11 states 

(Alabama, Arkansas, Georgia, Illinois, 

Indiana, Kentucky, Louisiana, 

Mississippi, Tennessee, and Texas). We 

are also publishing a supplemental 

notice of rulemaking to take comment 

on whether FIPs should be finalized for 

the remaining state (Missouri). The FIPs 

for these 10 states (and the FIP for the 

remaining state, if finalized) make 

measurable progress toward satisfying 

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

with respect to the 1997 ozone NAAQS 

in each covered state. To the extent that 

significant contribution to 

nonattainment and interference with 

maintenance is not entirely eliminated 

for the 1997 ozone NAAQS through 

today’s action, EPA will address these 

instances in a future rulemaking. This is 

further explained in section VI.D. 

With respect to the 1997 annual PM2.5

NAAQS, this rule finds that 18 states 

have SO2 and NOX emission reduction 

responsibilities. EPA also finds that 21 

states have SO2 and NOX emission 

reduction responsibilities with respect 

to the 2006 24-hour PM2.5 NAAQS. 

There are a total of 23 states that have 

SO2 and NOX emission reduction 

responsibilities for one or both of the 

above PM2.5 NAAQS. We apply the 

methodology to quantify emission 

reductions that these states must 

achieve to eliminate the state’s 

significant contribution to 

nonattainment and interference with 

maintenance. The states are listed in 

Table III–1 in section III of this 

preamble. 

This rule will prohibit all significant 

contribution to nonattainment and 

interference with maintenance with 

respect to the annual and 24-hour PM2.5.

In addition, it will resolve air quality 

issues at most nonattainment and 

maintenance receptors identified by 

EPA. EPA projects that unresolved 

nonattainment and maintenance issues 

will remain in only a few downwind 

states after promulgation and 

implementation of the Transport Rule. 

For the annual PM2.5 standard, EPA 

projects that this rule will help assure 

that all areas in the east fully resolve 

their nonattainment and maintenance 

concerns. This rule will also help a 

number of areas achieve the standard 

earlier than they may have otherwise. 

For the 2006 24-hour PM2.5 NAAQS, one 

area is projected to remain in 

nonattainment (Liberty-Clairton) and 

three areas are projected to have 

remaining maintenance concerns after 

imposition of the Transport Rule 

(Chicago,39 Detroit, and Lancaster 

County).40

The methodology provides similar 

assistance for ozone, assuring upwind 

reductions that will assist downwind 

states in controlling ozone pollution. It 

reduces ozone concentration levels in 

2012 and helps assure that all but two 

downwind areas fully resolve their 

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 

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 multi-factor approach to 

quantify significant contribution to 

nonattainment and interference with 

maintenance (i.e., to determine the 

specific amount of emissions that each 

upwind state must reduce) could serve 

as a precedent for quantifying upwind 

state emission reduction responsibilities 

with respect to potential future NAAQS. 

One commenter suggested that the 

rule could set a flawed precedent for 

future transport analyses and remedies, 

as it does not fully eliminate the 

prohibited emissions in every upwind 

state. EPA disagrees with this 

characterization of the Transport Rule. 

EPA notes that the partial determination 

of significant contribution to 

nonattainment and interference with 

maintenance for certain upwind states 

in the Transport Rule with respect to the 

ozone NAAQS is not a function of the 

multi-factor approach itself, but is 

instead a function of its limited 

application in this rulemaking to 

identify emission reductions from a 

single source category (EGUs). In fact, 

the Transport Rule’s approach itself 

allowed EPA to determine for which 

upwind states we have identified all 

emissions that constitute significant 

contribution to nonattainment and 

interference with maintenance, and for 

which upwind states we have identified 

emissions that are necessary but may 

not be sufficient to eliminate the 

prohibited emissions. As EPA explained 

at proposal, developing the additional 

information needed to consider NOX

emissions from non-EGU source 

categories in order to fully quantify 

upwind state responsibility with respect 

to the 1997 ozone NAAQS would 


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substantially delay promulgation of the 

Transport Rule. EPA explained that we 

do not believe that effort should delay 

the emission reductions and large health 

benefits this final rule will deliver 

(75 FR 45213). EPA further explained 

that we believe it is likely that the 

Agency can provide the greatest 

assistance to states in addressing 

transported pollution by issuing a 

separate (subsequent) rule to address 

additional reductions that may be 

necessary to fully eliminate upwind 

state responsibility with respect to the 

1997 ozone NAAQS (75 FR 45288). 

Thus, EPA decided to promulgate the 

Transport Rule as quickly as possible. 

EPA anticipates that application of this 

air-quality and cost-based multi-factor 

approach to a broader set of source 

categories in a subsequent rulemaking 

will identify any remaining prohibited 

emissions in the upwind states for 

which the Transport Rule may not fully 

eliminate those emissions with respect 

to the 1997 ozone NAAQS. 

2. Background 

After using air quality analysis to 

identify upwind states that are ‘‘linked’’ 

to downwind air quality monitoring 

sites with nonattainment and 

maintenance problems through 

contribution of at least one percent of 

the relevant NAAQS, EPA quantifies the 

portion of each state’s contribution that 

constitutes its ‘‘significant contribution’’ 

or ‘‘interference with maintenance.’’ 

This section describes the 

methodology developed by EPA for this 

analysis and then explains how that 

methodology is applied to measure 

significant contribution to 

nonattainment and interference with 

maintenance with respect to the 

NAAQS of concern. For this portion of 

the analysis, EPA expands upon the 

methodology used in the NOX SIP Call 

and CAIR but modifies it in important 

respects. In the NOX SIP Call and CAIR, 

EPA’s methodology defined significant 

contribution as those emissions that 

could be removed with the use of 

‘‘highly cost effective’’ controls. In the 

Transport Rule, rather than relying 

solely on an analysis of what constitutes 

‘‘highly cost effective’’ controls, EPA 

relies on an analysis that accounts for 

both cost and air quality improvement 

to identify the portion of a state’s 

contribution that constitutes its 

significant contribution to 

nonattainment and interference with 

maintenance. Furthermore, in response 

to the Court’s opinion in North 

Carolina, EPA has developed an 

approach which gives independent 

meaning to the ‘‘interfere with 

maintenance’’ prong of section 

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

The methodology takes into account 

both the D.C. Circuit Court’s 

determination that EPA may consider 

cost when measuring significant 

contribution, Michigan, 213 F.3d at 679, 

and its rejection of the manner in which 

cost was used in the CAIR analysis, 

North Carolina, 531 F.3d at 917. It also 

recognizes that the Court accepted—but 

did not require—EPA’s use of a single, 

uniform cost threshold to measure 

significant contribution. Michigan, 213 

F.3d at 679. 

As EPA discussed at length in the 

Transport Rule proposal, using both air 

quality and cost factors allows EPA to 

consider the full range of circumstances 

and state-specific factors that affect the 

relationship between upwind emissions 

and downwind nonattainment and 

maintenance problems (75 FR 45271). 

For example, considering cost takes into 

account the extent to which existing 

plants are already controlled as well as 

the potential for, and relative difficulty 

of, additional emission reductions. 

Therefore, EPA believes that it is 

appropriate to consider both cost and air 

quality metrics when quantifying each 

state’s significant contribution. 

This methodology is consistent with 

the statutory mandate in section 

110(a)(2)(D)(i)(I) which requires upwind 

states to prohibit emissions that 

significantly contribute to 

nonattainment or interference with 

maintenance in another state. As 

discussed in more detail in the 

proposal, interpreting significant 

contribution to nonattainment and 

interference with maintenance 

inherently involves a decision on how 

much emissions control responsibility 

should be assigned to upwind states, 

and how much responsibility should be 

left to downwind states. EPA’s 

methodology is intended to ‘‘assign a 

substantial but reasonable amount of 

responsibility to upwind states. * * *to 

control their emissions’’ (75 FR 45272). 

EPA believes that upwind states 

contributing to downwind state air 

quality degradation should bear 

substantial responsibility to control 

their emissions because of the plain 

language of the good neighbor 

provision, the health risks and control 

cost impacts that upwind emissions 

cause in the downwind state, and the 

cumulative impact in the downwind 

state of emissions from multiple upwind 

states, and the importance of achieving 

attainment in downwind states as 

expeditiously as practicable but no later 

than specific deadlines as required by 

the Act. EPA’s approach does not shift 

the responsibility for achieving or 

maintaining the NAAQS to the upwind 

state. See 75 FR 45272. 

The methodology defines each state’s 

significant contribution to 

nonattainment and interference with 

maintenance as the emission reductions 

available at a particular cost threshold 

in a specific upwind state which 

effectively address nonattainment and 

maintenance of the relevant NAAQS in 

the linked downwind states of concern. 

Unlike the NOX SIP Call and CAIR, 

where EPA’s significant contribution 

analysis had a regional focus, the 

methodology used in the Transport Rule 

focuses on state-specific factors. The 

methodology uses a multi-step process 

to analyze costs and air quality impacts, 

identify appropriate cost thresholds, 

quantify reductions available from EGUs 

in each state at those thresholds, and 

consider the impact of variability in 

EGU operations. There are four steps to 

this methodology: (1) Identification of 

each state’s emission reductions 

available at ascending costs per ton as 

appropriate; (2) assessment of those 

upwind emission reductions’ 

downwind air quality impacts; (3) 

identification of upwind ‘‘cost 

thresholds’’ delivering effective 

emission reductions and downwind air 

quality improvement; and (4) 

enshrinement of the upwind emission 

reductions available at those cost 

thresholds in state budgets. 

In step one, EPA identifies what 

emission reductions are available at 

various cost thresholds, quantifying 

emission reductions that would occur 

within each state at ascending costs per 

ton of emission reductions. In other 

words, EPA determined for specific cost 

per ton thresholds, the emission 

reductions that would be achieved in a 

state if all EGUs greater than 25 MW in 

that state used all emission controls and 

emission reduction measures available 

at that cost threshold. For purposes of 

this discussion, we refer to these as 

‘‘cost curves.’’ 

For this final rule, EPA used updated 

IPM modeling to conduct a similar cost 

curve analysis as conducted in the 

Transport Rule proposal (75 FR 45275). 

In the proposal, the cost curves only 

reflected escalating cost for one 

pollutant while the other pollutant cost 

was held constant at base case levels 

(i.e., $0/ton). However, EPA improved 

the costing analysis for the final rule by 

identifying upwind emission reductions 

available as costs were imposed on both 

SO2 and NOX simultaneously for states 

linked to downwind states on the basis 

of the PM2.5 NAAQS. In other words, the 

cost curves in the proposal depicted 

state level emissions when only one 

pollutant was priced (i.e., NOX at $500/ 


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41As 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. 

42The 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. 

ton). Separate cost curves were done for 

each pollutant. For the final rule, EPA 

conducted some preliminary cost curve 

analysis for identifying NOX thresholds 

in this manner. However, for the final 

cost curve analysis, EPA relied on cost 

curves that reflected state emissions 

when pollutants were priced 

simultaneously (e.g., NOX at $500/ton 

and SO2 at $1,600/ton). For reasons 

described in section VI.B, EPA was able 

to conduct this type of analysis because 

the preliminary cost curves specific to 

annual and ozone-season NOX suggested 

little flexibility in adjusting the $500/ 

ton cost thresholds imposed for each. 

Therefore, EPA was able to hold the cost 

threshold constant at $500/ton for these 

pollutants in its examination of SO2 at 

various cost thresholds. EPA believes 

this approach to cost analysis is a better 

simulation of the Transport Rule’s likely 

impact on covered sources. Under the 

final Transport Rule, covered sources in 

states regulated for PM2.5 must address 

compliance requirements for SO2 and 

NOX emissions simultaneously, and this 

refined approach to cost curve analysis 

and subsequent air quality analysis 

better reflects this reality. Section VI.B 

of this preamble describes the costing 

analysis in further detail. Also, for more 

detail on the development of the cost 

curves, see ‘‘Significant Contribution 

and State Emission Budgets Final Rule 

TSD’’ in the docket for this rule. 

Although the cost curves presented in 

this rule only include EGU reductions, 

EPA also assessed the cost of SO2 and 

NOX emission reductions available for 

source categories other than EGUs in the 

proposed rulemaking. This preliminary 

assessment in the rule proposal 

suggested that there likely would be 

very large emission reductions available 

from EGUs before costs reach the point 

for which non-EGU sources have 

available reductions (75 FR 45272). EPA 

revisited these non-EGU reduction cost 

levels in this final rulemaking and 

verified that there are little or no 

reductions available from non-EGUs at 

costs lower than the thresholds that EPA 

has chosen ($500/ton for NOX, $2,300/ 

ton for SO2). 

Further details on EPA’s application 

of cost curves are provided below, in 

section VI.B. 

In step two, EPA uses an air quality 

assessment tool to estimate the impact 

that the combined reductions available 

from upwind contributing states and the 

downwind receptor state at different 

cost-per-ton levels would have on air 

quality at downwind monitoring sites 

projected to have nonattainment and/or 

maintenance problems.41 While less 

rigorous than the air quality models 

used for attainment demonstrations, 

EPA believes this air quality assessment 

tool (which has been refined since 

proposal) is acceptable for assessing the 

impact of numerous options for upwind 

emission reductions in the process of 

defining an upwind state’s significant 

contribution to nonattainment and 

interference with maintenance. It allows 

the Agency to anticipate specific air 

quality impacts of many more potential 

emission reduction scenarios pertinent 

to the relevant NAAQS than time- and 

resource-intensive comprehensive air 

quality modeling would permit. 

Further details on EPA’s application 

of step two in this methodology are 

provided below, in section VI.C. 

In step three, EPA examines cost and 

air quality information to identify 

‘‘significant cost thresholds.’’ EPA 

considered a significant cost threshold 

to be a point along the cost curves 

where a noticeable change occurred in 

downwind air quality, such as a point 

where large upwind emission 

reductions become available because a 

certain type of emissions control 

strategy becomes cost-effective.42

This methodology allows EPA, where 

appropriate, to define multiple cost 

thresholds that vary for a particular 

pollutant for different upwind states. As 

explained in the Transport Rule 

proposal, EPA does not believe it is 

required to utilize multiple cost 

thresholds to regulate upwind emissions 

for purposes of the mandate in CAA 

section 110(a)(2)(D), but EPA’s multifactor methodology developed for the 

Transport Rule to define significant 

contribution to nonattainment and 

interference with maintenance allows 

the Agency to consider whether a single 

cost threshold or multiple cost 

thresholds are appropriate for meeting 

the requirements of CAA section 

110(a)(2)(D) relevant to a particular 

NAAQS (75 FR 45274). 

In step four, EPA uses the information 

regarding emission reductions available 

in each ‘‘linked’’ upwind state at the 

appropriate cost threshold to form a 

state ‘‘budget,’’ representing the 

remaining emissions from covered 

sources for the state in an average year 

once significant contribution to 

nonattainment and interference with 

maintenance have been eliminated; each 

budget also allows for the identification 

of an associated variability limit. These 

budgets and variability limits are used 

to develop enforceable requirements 

under the final remedy. The final rule’s 

methodology for identifying state 

budgets is derived directly from the cost 

curves and multi-factor analysis EPA 

uses to determine each state’s 

significant contribution to 

nonattainment and interference with 

maintenance. State emission budgets are 

discussed in section VI.D and the 

variability limits are discussed in 

section VI.E. 

B. Cost of Available Emission 

Reductions (Step 1) 

This subsection provides more detail 

on the cost curves that EPA developed 

to assess the costs of reducing SO2 and 

NOX emissions to address transport 

related to ozone and PM2.5

concentrations (described previously as 

Step 1). It summarizes the information 

from the curves and then provides 

EPA’s interpretation of that information. 

EPA used IPM to develop the EGU cost 

curves described in this rulemaking. 

More information can be found 

regarding EPA’s use of IPM for the final 

Transport Rule in the ‘‘Significant 

Contribution and State Emission 

Budgets Final Rule TSD’’. 

The amount of emission reductions 

that the cost curves suggest are available 

at various costs are specific to the 2012 

and 2014 time periods. These cost 

estimates factor in the time interval 

between rule finalization and 

compliance periods, existing controls 

already in place, and controls that could 

potentially come on line by the start of 

the compliance period. EPA notes that 

cost curves are a fluid concept and 

would vary given different compliance 

dates. 

1. Development of Annual NOX and 

Ozone-Season NOX Cost Curves 

EPA conducted preliminary cost 

curve analysis for annual NOX and 

ozone-season NOX in a similar manner 

to that used in the proposed rulemaking. 

That is, the impact of various cost 

thresholds on emissions was examined 

individually. For example, state level 

emissions were examined at cost levels 

for annual NOX of $500, $1,000, and 


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$2,500/ton while SO2 was held at base 

case levels. EPA used this approach to 

examine NOX and ozone-season NOX

emission reductions available from 

EGUs by 2012 and 2014 at various cost 

levels, reaching to $2,500/ton for annual 

NOX and up to $5,000/ton for ozoneseason NOX (in 2007-year dollars). 

Section VI.D explains why EPA 

analyzed the $500/ton threshold for 

annual and ozone-season NOX. EPA 

selected two higher cost thresholds to 

analyze for annual and ozone-season 

NOX that provided a reasonable 

spectrum of emission reduction 

opportunities from EGUs at higher cost 

thresholds. Specifically, EPA analyzed 

these two higher cost thresholds 

because the first ($1,000/ton) was 

informative in regards to the additional 

EGU NOX emissions reductions 

available without installation of 

advanced controls, and the second 

($2,500/ton for annual NOX, $5,000/ton 

for ozone-season NOX) was informative 

in regards to additional EGU reductions 

available at cost thresholds where 

advanced NOX control retrofits are 

economic for some units. The cost 

thresholds were only applied to states 

with air quality contributions that meet 

or exceed the air quality thresholds as 

identified in section V.D. For both 

annual and ozone-season NOX, EPA did 

not consider cost thresholds below 

$500/ton for reasons explained in 

section VI.D. 

EPA observed in the proposal that 

low-cost NOX reductions are available at 

upwind sources with existing pollution 

control equipment that may not 

otherwise be operated in the future 

without the Transport Rule. EPA 

believes it is appropriate to prohibit any 

‘‘linked’’ upwind state from potentially 

increasing its emissions through a 

failure to operate these existing 

pollution controls, which could worsen 

downwind air quality problems. Thus, 

EPA reflected operation of these 

controls in all modeling of different cost 

thresholds (i.e., the modeling assumes 

year-round operation of postcombustion NOX controls in covered 

PM2.5 states and ozone-season operation 

of post-combustion NOX controls in 

covered ozone states). 

Table VI.B–1 shows the annual NOX

emissions from EGUs at various levels 

of control cost per ton for 2014. Table 

VI.B–2 presents the cost curves for 

ozone-season NOX emissions from 

EGUs. As discussed in section VI.D, 

EPA determined that $500/ton for 

annual and ozone NOX was the 

appropriate cost threshold for this rule 

(although EPA plans to determine in the 

future whether a higher cost/ton 

threshold may be warranted for states 

contributing to nonattainment or 

maintenance problems with the 1997 

ozone air quality standard projected to 

remain in two downwind areas). 

TABLE VI.B–1—2014 ANNUAL NOX EMISSIONS FROM FOSSIL-FUEL FIRED EGUS GREATER THAN 25 MW FOR EACH

TRANSPORT RULE STATE AT VARIOUS COSTS PER TON

[(2007$) per ton (thousand tons)] 

Base case 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 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 TRANSPORT RULE STATE AT VARIOUS COSTS

[(2007$) per ton (thousand tons)] 

Base case level $500 $1,000 $5,000 

Alabama ........................................................................................... 34 34 34 31 

Arkansas .......................................................................................... 15 15 15 14 

Florida .............................................................................................. 42 27 27 24 

Georgia ............................................................................................ 29 28 28 25 

Illinois ............................................................................................... 21 21 21 21 

Indiana ............................................................................................. 47 46 46 43 

Kentucky .......................................................................................... 38 37 36 34 


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TABLE VI.B–2—2012 OZONE-SEASON NOX EMISSIONS FROM FOSSIL-FUEL FIRED EGUS GREATER THAN 25 MW FOR

EACH TRANSPORT RULE STATE AT VARIOUS COSTS—Continued 

[(2007$) per ton (thousand tons)] 

Base case level $500 $1,000 $5,000 

Louisiana .......................................................................................... 13 13 13 13 

Maryland .......................................................................................... 7 7 7 7 

Mississippi ........................................................................................ 10 10 10 9 

New Jersey ...................................................................................... 3 3 3 3 

New York ......................................................................................... 8 8 8 8 

North Carolina .................................................................................. 23 23 23 21 

Ohio ................................................................................................. 42 42 42 38 

Pennsylvania .................................................................................... 53 53 52 49 

South Carolina ................................................................................. 15 15 15 14 

Tennessee ....................................................................................... 16 16 15 15 

Texas ............................................................................................... 65 63 63 60 

Virginia ............................................................................................. 15 15 15 13 

West Virginia .................................................................................... 26 26 26 24 

Total .......................................................................................... 523 504 501 467 

EPA notes that the cost curves 

presented here differ somewhat from the 

cost curves presented in the proposal. 

The NOX emissions modeled at a $500/ 

ton cost threshold for the final rule are 

lower than they were at proposal. In 

addition, the emission reductions they 

represent from the updated base case are 

not as pronounced as was found in 

modeling for the proposed rule. It is 

worth emphasizing that the lower 

emission reductions observed at $500/ 

ton in this final rulemaking are due to 

a lower starting point in updated base 

case EGU NOX emission levels (and thus 

do not reflect higher NOX emissions 

remaining after the reductions made at 

the $500/ton threshold). While the base 

case 2012 nationwide annual EGU NOX

emissions were approximately 3 million 

tons in the proposal, they were only 2.1 

million tons in the final rule. This 

approximately 33 percent reduction in 

base case EGU NOX emissions in the 

final rule modeling relative to the 

proposal is due to a combination of 

modeling updates, including lower 

natural gas prices, reduced electricity 

demand, newly-modeled consent 

decrees and state rules, and updated 

NOX rates to reflect 2009 emissions 

data. All of these factors resulted in 

substantially lower base case Transport 

Rule NOX emissions in the final rule 

modeling. 

2. Development of SO2 Cost Curves 

As explained in detail below in 

section VI.D, EPA determined that a 

single threshold of $500/ton for ozoneseason NOX control in the states covered 

for the 1997 ozone NAAQS and a single 

threshold of $500/ton for annual NOX

control in the states covered for the 

PM2.5 NAAQS were appropriate cost 

thresholds for identifying upwind 

control under the Transport Rule. With 

these parameters determined, EPA was 

able to assess the availability of SO2

emission reductions from EGUs at 

various SO2 cost per ton thresholds with 

the corresponding NOX reduction 

requirements simultaneously 

represented in the analysis. 

This approach of simultaneously 

modeling cost levels for covered 

pollutants is different from the approach 

taken in the proposal. In the proposal, 

cost curves were developed and 

examined independently for each 

pollutant. For example, with the SO2

cost curves in the proposal, the NOX

cost level was held constant at base case 

levels as the SO2 cost threshold was 

varied from base case levels to $2,400/ 

ton. Commenters noted that this did not 

accurately reflect a reality where source 

owners/operators view price signals for 

all covered pollutants simultaneously 

and make operation decisions 

accordingly. For the final rule, EPA 

included cost thresholds of $500/ton for 

annual NOX in PM2.5 states and $500/ 

ton for ozone-season NOX in ozoneseason 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 

the final rule represents a point where 

there is a significant change in available 

controls, emission reductions, or costs 

and economic impacts. EPA believes 

analysis of these thresholds illustrate a 

meaningful progression of costs and air 

quality impacts that enabled the Agency 

to determine a proper threshold along 

this cost curve to identify significant 

contribution to nonattainment and 

interference with maintenance for this 

rulemaking. 

The cost thresholds above $500/ton 

were applied starting in 2014. In all 

modeling, the 2012 cost per ton 

threshold was held constant at $500/ton 

as EPA believes that this cost threshold 

captures all emission reductions feasible 

by 2012 (see section VI.B.3 below for 

more discussion). At the higher cost 

levels (e.g., $2,800/ton and above), the 

curve does not include all available 

reductions as they do not include nonEGU 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 


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Transport Rule in place. Therefore, all 

of the final SO2 cost curves assume 

operation of existing scrubbers in PM2.5

states under the Transport Rule. In 

2014, approximately 3 million tons of 

SO2 reductions can be achieved at the 

$500/ton cost threshold through 

operation of existing controls and some 

fuel switching. 

This final cost curve also 

appropriately reflects the Group 1/ 

Group 2 distinction for states covered 

for PM2.5. As discussed in more detail in 

section VI.D, EPA identified Group 2 

states as those that were linked to states 

where all nonattainment and 

maintenance issues had been resolved at 

$500/ton levels. There is no longer any 

significant contribution to 

nonattainment or interference with 

maintenance by these seven Group 2 

states at levels above $500/ton. 

Therefore, in the final curves, these 

Group 2 states’ cost thresholds were 

held constant at $500/ton as the higher 

cost thresholds were applied to the 

remaining Group 1 states starting in 

2014. For example, the modeled 

emissions at the $2,300 per ton cost 

threshold shown in Table VI.B–3 below 

reflect each state’s emissions when 

Group 1 states are subjected to a $2,300 

per ton SO2 constraint and Group 2 

states are subjected to a $500/ton SO2

constraint. 

Additional reductions can be 

achieved at the higher cost thresholds. 

The cost curves demonstrate that 

sources begin to build significant 

additional flue gas desulfurization 

(FGD) retrofits at an SO2 cost threshold 

of $1,600 per ton and additional dry 

sorbent injection (DSI) retrofits at an 

SO2 cost threshold of $2,300 per ton. 

With these final cost curves in hand, 

EPA was able to identify the combined 

reductions available from upwind 

contributing states and the downwind 

state, at different cost-per-ton levels. 

Additionally, EPA was able to examine 

the economic impacts of imposing such 

cost constraints on power sector 

generation. However, this only 

constitutes a portion of EPA’s multifactor assessment used to determine the 

amount of emissions that represent 

significant contribution to 

nonattainment and interference with 

maintenance. As noted in the Transport 

Rule proposal, EPA’s multi-factor 

assessment considered air quality and 

cost considerations when identifying 

cost thresholds (75 FR 45271). The air 

quality portion of the assessment is 

described in section VI.C of the final 

Transport Rule preamble. 

3. Amount of Reductions That Could Be 

Achieved by 2012 and 2014 

EPA applied escalating SO2 cost per 

ton thresholds for Group 1 states to 

create the cost curves for 2014 and 

beyond. For 2012 SO2, the cost per ton 

was held constant at $500/ton as the 

cost thresholds in 2014 and beyond 

were varied. The advanced pollution 

controls incentivized by these higher 

cost-per-ton levels can reasonably be 

installed by 2014. EPA also considered 

whether any of these emission 

reductions could be achieved prior to 

2014. For the reasons that follow, EPA 

concluded that significant reductions 

could be achieved by 2012 and that it 

is important to require all such 

reductions by 2012 to ensure that they 

are achieved as expeditiously as 

practicable. SO2 and NOX reductions 

come from operating existing controls, 

installing combustion controls, fuel 

switching, and increased dispatch of 

lower-emitting generation which can be 

achieved by 2012. In general, 

compliance mechanisms that do not 

involve post-combustion 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 ozoneseason NOX in states linked to receptors 

for ozone. These cost per ton levels do 

not precipitate advanced postcombustion 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. 

TABLE VI.B–3—2014 SO2 EMISSIONS FROM FOSSIL-FUEL-FIRED EGUS GREATER THAN 25 MW FOR EACH TRANSPORT

RULE STATE AT VARIOUS COSTS PER TON

[Thousand tons] a

State 

SO2

group 

Base 

case 

level 

$500 $1,600 $2,300 $2,800 $3,300 $10,000 

Alabama ........................................................................... 2 417 201 226 213 214 236 190 

Georgia ............................................................................ 2 170 94 94 95 95 95 98 

Illinois ............................................................................... 1 138 134 130 124 117 102 36 

Indiana ............................................................................. 1 711 245 179 161 153 121 69 

Iowa .................................................................................. 1 127 112 78 75 67 45 13 

Kansas ............................................................................. 2 70 55 57 61 61 61 45 

Kentucky .......................................................................... 1 488 161 126 106 103 89 46 

Maryland .......................................................................... 1 43 32 28 28 26 24 18 

Michigan ........................................................................... 1 266 206 189 144 105 94 24 

Minnesota ......................................................................... 2 66 43 45 46 46 46 44 

Missouri ............................................................................ 1 382 212 173 166 109 84 21 

Nebraska .......................................................................... 2 72 68 70 70 70 70 66 

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 


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43Observable indicators of the sensitivity of PM2.5

nitrate to emission reductions—Part II: Sensitivity 

to errors in total ammonia and total nitrate of the 

CMAQ-predicted non-linear effect of SO2 emission 

reductions. R.L. Dennis, P.K. Bhave, and R.W. 

Pinder. 2008. Atmospheric Environment (42):1287– 

1300.doi:10.1016/j.atmosenv.2007.10.036. 44Houston and Baton Rouge nonattainment areas. 

TABLE VI.B–3—2014 SO2 EMISSIONS FROM FOSSIL-FUEL-FIRED EGUS GREATER THAN 25 MW FOR EACH TRANSPORT

RULE STATE AT VARIOUS COSTS PER TON—Continued 

[Thousand tons] a

State 

SO2

group 

Base 

case 

level 

$500 $1,600 $2,300 $2,800 $3,300 $10,000 

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 

a Note: 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 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 Final Rule TSD’’, 

address commenter’s concerns about the 

scientific rigor of the design and 

application of AQAT and commenter’s 

recommendations to rely upon air 

quality modeling as part of this analysis. 

For the final Transport Rule, EPA 

created an AQAT calibration scenario 

consisting of full-scale air quality 

modeling using CAMx of a 2014 control 

scenario reflecting SO2 and NOX

emission reductions of similar 

stringency and from the same geography 

as the Transport Rule proposal. 

Modeling of this AQAT calibration 

scenario reflected all updates made to 

the air quality modeling platform, as 

described in the ‘‘Air Quality Modeling 

Final Rule TSD’’ found in the docket for 

this rulemaking. CAMx modeling of 

each receptor’s response in this control 

scenario accounts for complex chemical 

interactions and covariation of these 

pollutants. Among the important 

atmospheric chemical interactions 

accounted for in CAMx is ‘‘nitrate 

replacement.’’ 43 Nitrate replacement 

occurs when SO2 emission reductions 

lead to decreases in ammonium sulfate, 

which in turn, can result in an increase 

in ammonium nitrate concentrations. As 

described below, EPA used the CAMx 

modeling results for this AQAT 

calibration scenario together with the 

modeling for the 2012 base case to 

characterize the response of ozone, 

nitrate, and sulfate at each 

nonattainment and maintenance 

receptor to the mix of upwind NOX and 

SO2 emission reductions at each cost 

threshold. 

As described in section VI.D, EPA 

determined that the $500/ton threshold 

for upwind annual and ozone-season 

NOX control is appropriate for the final 

Transport Rule (although EPA plans to 

determine in the future whether a 

higher cost/ton threshold may be 

warranted for states contributing to 

nonattainment or maintenance problems 

with the 1997 ozone air quality standard 

projected to remain at receptors in two 

downwind areas 44). Because this 

threshold corresponds to the NOX

control strategy modeled in the AQAT 

calibration scenario described above, 

EPA is able to rely on this CAMx air 

quality modeling to assess the response 

of ozone and nitrate concentrations due 

to NOX reductions and does not 

estimate ozone or nitrate impacts for 

this final rulemaking using AQAT. 

Further information on the air quality 

modeling of this AQAT calibration 

scenario can be found in the Air Quality 

Modeling Final Rule TSD and the 

Significant Contribution and State 

Emission Budgets Final Rule TSD in the 

docket for this rulemaking. 

In order to estimate 2014 annual and 

24-hour PM2.5 concentrations, AQAT 

uses the 2012 annual and seasonal 

contributions which quantify the 

contribution of SO2 emissions in 

specific upwind states to sulfate 

concentrations at specific downwind 

receptors. These contributions are 

described in section V.D.2 and the Air 

Quality Modeling Final Rule TSD. 

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 


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45EPA used CAMx to conduct full air quality 

modeling of the final Transport Rule remedy 

embodying the emission reductions that EPA first 

selected on the basis of the multi-factor analysis 

using AQAT to project air quality impacts from 

varying levels of emission reductions analyzed. The 

CAMx results confirmed the relative magnitude and 

direction of AQAT’s estimates of the outcomes for 

the 2012 base case nonattainment and maintenance 

receptors analyzed, and the AQAT estimates closely 

tracked CAMx-modeled concentrations at those 

receptors under the Transport Rule remedy. The 

paired 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 

and State Emission Budgets Final Rule TSD. 

calibration scenario. Calibration factors 

were constructed for the annual and 

24-hour PM2.5 AQAT. 

To further allow adequate assessment 

of the seasonal impacts of various levels 

of upwind SO2 reductions on each 

receptor’s 24-hour PM2.5 concentration 

using AQAT, EPA developed response 

factors for sulfate on a quarterly basis to 

capture important air quality differences 

between summer and winter emissions 

and concentrations. This process 

allowed EPA to estimate the air quality 

values for each season at each cost 

threshold, and then estimate the air 

quality design values. 

Finally, EPA’s air quality assessment 

accounts for the impact that this 

differential response in sulfate by 

quarter can have on the ordering of 24- 

hour concentrations when calculating 

the 98th percentile for the 24-hour 

standard. AQAT estimates quarterlyspecific relative response factors that 

estimate quarterly-specific proportional 

change in ammonium sulfate resulting 

from the SO2 emission reduction from 

the 2012 base case scenario to the 2014 

cost threshold scenario being assessed. 

These quarterly relative response factors 

are then applied to each of the 

maximum 24-hour PM2.5 concentrations 

for eight days per quarter per year at 

each receptor from the 2012 base case. 

This methodology improvement allows 

EPA to redetermine the 98th percentile 

day for each year and recalculate 

average and maximum design values for 

the 24-hour PM2.5 standard. 

These improvements for the final rule 

increase EPA’s confidence that the air 

quality estimates provided by AQAT, 

now customized for this application, 

more accurately estimate the results of 

full-scale air quality modeling of the 

various levels of upwind SO2 reductions 

considered. EPA evaluated the estimates 

from AQAT using an independent data 

set, the 2014 base case estimates from 

CAMx, finding that the results are 

unbiased with minimal differences. See 

‘‘Significant Contribution and State 

Emission Budgets Final Rule TSD’’ for 

more details. 

As such, EPA believes the revised 

AQAT provides an appropriate basis for 

assessing the air quality portion of the 

multi-factor methodology to define 

significant contribution to 

nonattainment and interference with 

maintenance.45

2. Utilization of AQAT To Evaluate 

Control Scenarios 

For the final Transport Rule, EPA 

performed air quality analysis for each 

downwind annual and 24-hour PM2.5

receptor with a nonattainment and/or 

maintenance problem in the 2012 base 

case. For each receptor, EPA quantified 

the sulfate reduction and resulting air 

quality improvement when a group of 

states consisting of the upwind states 

that are ‘‘linked’’ to the downwind 

receptor (as explained in section V.D) 

and the downwind state where the 

receptor is located, all made the SO2

emission reductions that EPA identified 

as available at each cost threshold. EPA 

assumes reductions at each cost 

threshold from the linked upwind states 

as well as the downwind receptor state 

to assess the shared responsibility of 

these upwind 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 statespecific analysis to support a 

determination of the amount of each 

upwind state’s responsibility for air 

quality problems at the downwind 

receptors that it significantly affects. If 

the AQAT analysis were to assume 

emissions reductions in other nonlinked states, the AQAT analysis would 

then contradict the first step of our twostep approach to defining significant 

contribution to nonattainment and 

interference with maintenance. Under 

EPA’s two-step approach, only a state 

that (1) contributes a threshold amount 

or more to a particular downwind state 

receptor’s air quality problem, and (2) 

has emission reductions available at the 

selected cost threshold can be deemed 

to have responsibility to reduce its 

emissions to improve air quality at that 

downwind receptor. EPA believes that 

the commenters’ suggested approach 

would not qualify as a state-specific 

approach for determining upwind state 

responsibility for downwind air quality 

problems. 

Because EPA is relying on the CAMx 

estimate of nitrate concentrations from 

the AQAT calibration scenario, the 

response in nitrate to NOX reductions at 

a cost threshold of $500/ton is present 

in each SO2 cost threshold scenario 

analyzed. 

EPA determines the cumulative air 

quality improvement that can be 

expected at a particular downwind 

receptor by multiplying each upwind 

state’s percent SO2 emission reduction 

by its calibrated receptor specific sulfate 

response factor and summing the 

sulfate, nitrate, and other PM2.5

components (also taken from the 2014 

CAMx AQAT calibration scenario). 

3. Air Quality Assessment Results 

The results of EPA’s air quality 

assessment of the cost threshold 

scenarios focus on air quality metrics 

including, but not limited to, average air 

quality improvement at receptors with 

2012 base case nonattainment and 

maintenance exceedances and an 

evaluation of estimated receptor design 

values against annual and 24-hour PM2.5

standards. See ‘‘Significant Contribution 

and State Emission Budgets Final Rule 

TSD’’ for more details. 

In EPA’s air quality analysis of each 

downwind receptor, all air quality 

improvements are measured relative to 

the ‘‘AQAT base case.’’ This base case 

reflects AQAT’s estimated PM2.5

concentrations under base case 2014 

SO2 emissions. The AQAT base case 

itself is not used for any decision points 

and only serves as an appropriate 

starting 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 


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case. EPA assessed the cumulative 

reduction in 24-hour PM2.5 maximum 

design value at each increasing SO2 cost 

threshold from the maximum design 

value from the AQAT base case, and 

averaged the reduction across the 41 

receptors. The results of this assessment 

indicate diminishing incremental 

returns to 24-hour PM2.5 maximum 

design value reduction as SO2 cost 

threshold levels increase. EPA finds 

reductions in maximum design value of 

4.28 μg/m3 at $500; 4.98 μg/m3 at 

$1,600; 5.33 μg/m3 at $2,300; 5.46 μg/m3

at $2,800; 5.60 μg/m3 at $3,300; and 6.08 

μg/m3 at $10,000. These results are 

provided in table VI.C–1. 

TABLE VI.C–1—AVERAGE 2014 AIR

QUALITY IMPROVEMENT AT RECEPTORS WITH 2012 BASE CASE NONATTAINMENT AND MAINTENANCE

PROBLEMS

Group 1 state SO2 cost 

per ton threshold 

Average air quality improvement 

at exceeding 

receptors in 2012 

base case 

(μg/m3) 

$500 .................................. 4.28 

$1,600 ............................... 4.98 

$2,300 ............................... 5.33 

$2,800 ............................... 5.46 

$3,300 ............................... 5.60 

$10,000 ............................. 6.08 

Additionally, EPA evaluated the 

AQAT estimated 2014 average and 

maximum design values for these 

receptors at each cost threshold against 

the annual and 24-hour PM2.5 standards. 

EPA determined the estimated number 

of receptors with nonattainment or 

maintenance problems at $500/ton cost 

threshold of NOX and each of the cost 

threshold scenarios assessed for SO2. 

These results are provided in table 

VI.C–2 in terms of the number of 

receptors and the number of 

nonattainment areas containing these 

receptors. 

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 meet or exceed the 1 percent 

contribution thresholds used to identify 

linkages between upwind and 

downwind states. Such shifting of 

emissions between states may occur 

because of the interconnected nature of 

the country’s energy system (including 

both the electricity grid as well as coal 

and natural gas supplies). 

Using updated emissions and air 

quality information developed for the 

final rule, EPA’s IPM modeling found 

that of the states not covered in the final 

rule for PM2.5, Arkansas, Colorado, 

Louisiana, Montana, and Wyoming are 

all projected to have SO2 emission 

increases above 5,000 tons in 2014 with 

the rule in effect. EPA analysis shows 

the SO2 emission increases result from 

expected shifts to higher sulfur coal in 

these states. Using AQAT, a state-level 

assessment of these emission increases 

relative to the state specific 

contributions to downwind receptors 

(where available) indicates that 

projected increases in the SO2 emissions 

would not increase any of these states’ 

contributions to an amount that would 

meet or exceed the 0.15 μg/m3 or 0.35 

μg/m3 thresholds for annual and 

24-hour PM2.5, respectively. For this 

reason, EPA has determined that it is 

not necessary to include these 

additional states in the Transport Rule 

as a result of the effects of the rule itself 

on SO2 emissions in uncovered states. 

See ‘‘Significant Contribution and State 

Emission Budgets Final Rule TSD’’ in 

the docket for this rulemaking for more 

details. 

D. Multi-Factor Analysis and 

Determination of State Emission 

Budgets 

EPA used the cost, emission, and air 

quality information described in the 

previous sections to perform its multifactor analysis. By looking at different 

‘‘cost thresholds’’—places where there 

was a noticeable change on the cost 

curve because emission reductions 

occur—and examining the 

corresponding impact on air quality, 

EPA identified the amount of emissions 

that represent significant contribution to 

nonattainment and interference with 

maintenance within each state. After 

quantifying this amount of emissions, 

EPA established state ‘‘budgets’’ which 

represent the remaining emissions for 

the state in an average year (step 4). 

For states covered by the rule for 

PM2.5, EPA calculated annual NOX and 

annual SO2 budgets. For states covered 

by the rule for ozone, EPA calculated 

ozone-season NOX budgets. This section 

explains the multi-factor assessment 

and how EPA used this assessment to 

determine state-specific budgets. 

1. Multi-Factor Analysis (Step 3) 

a. Overview 

As described in section VI.B, EPA 

examined how different cost thresholds 

impacted emissions in states with air 

quality contributions that meet or 

exceed specific air quality thresholds, as 

discussed in section V.D of this 

preamble. Section VI.C summarizes the 

estimated air quality impacts in 2014 of 

these emission levels at downwind 

receptors, including estimates of their 

nonattainment and maintenance status 

(see ‘‘Significant Contribution and State 

Emission Budgets Final Rule TSD’’ for 

more details). From these two steps, 

EPA evaluated the interaction between 

upwind emissions at different cost 

levels and air quality at downwind 

receptors to identify ‘‘significant cost 

thresholds.’’ These cost thresholds are 


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based on air quality considerations 

(such as the cost at which the air quality 

assessment analysis projects large 

numbers of downwind site maintenance 

and nonattainment problems would be 

resolved) or cost criteria (such as a cost 

where large emissions reductions occur 

because a particular technology is 

widely implemented at that cost). EPA 

examined each cost threshold and then 

used a multi-factor assessment to 

determine which serve as cost 

thresholds that eliminate significant 

contribution to nonattainment and 

interference with maintenance for 

upwind states. Air quality 

considerations in the assessment 

include, for example, how much air 

quality improvement in downwind 

states results from upwind state 

emission reductions at different levels; 

whether, considering upwind emission 

reductions and assumed local (in-state) 

reductions, the downwind air quality 

problems would be resolved; and the 

components of the remaining 

downwind air quality problem (e.g., 

whether it is a predominantly local or 

in-state problem, or whether it still 

contains a large upwind component). 

Cost considerations include, for 

example, how the cost per ton of 

emission reduction compares with the 

cost per ton of existing federal and state 

rules for the same pollutant; whether 

the cost per ton is 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. 

The specific cost per ton thresholds 

selected as a basis for identifying 

significant contribution to 

nonattainment and interference with 

maintenance in this rulemaking apply 

only to the determinations made in this 

rule and do not establish any precedent 

for future EPA actions under section 

110(a)(2)(D)(i)(I) or any other section of 

the CAA. EPA’s selection of specific 

cost thresholds in the context of this 

rulemaking relies on current analyses of 

the cost of available emission 

reductions, the pattern of interstate 

linkages for pollution transport, and the 

downwind air quality impacts 

specifically related to the 1997 ozone 

NAAQS, the 1997 annual PM2.5

NAAQS, and the 2006 24-hour PM2.5

NAAQS. In addition and as explained 

below, the selection of the threshold for 

ozone-season NOX was influenced by 

the limited scope of this rule. Any or all 

of these variables used to identify 

specific cost thresholds are subject to 

change. Thus, EPA may use different 

cost thresholds in future actions, even if 

those actions relate to the same NAAQS 

addressed in this rule. 

b. Cost Thresholds Examined and 

Selected for Ozone-Season NOX

In the proposal, EPA examined 

various cost thresholds for ozone season 

NOX and identified a cost threshold 

with rapidly diminishing returns at 

$500/ton. EPA observed that moving 

beyond the $500 cost threshold up to a 

$2,500 cost threshold would result in 

only minimal additional ozone season 

NOX emission reductions and would 

likely bypass less expensive non-EGU 

emission reduction opportunities (75 FR 

45281). EPA noted that for greater costs 

the curves did not include all available 

reductions as they do not include nonEGU reductions (75 FR 44286). In the 

proposal, EPA noted the timely 

promulgation and implementation of 

this rule is responsive to the Court’s 

remand of CAIR, will accelerate critical 

air quality improvement, and more 

effectively address the mandate of CAA 

section 110(a)(2)(D) to address 

significant contribution to 

nonattainment and interference with 

maintenance as expeditiously as 

practicable. EPA did not want to risk 

delaying air quality benefits available 

from EGU emission reductions, 

particularly those emission reductions 

which eliminate significant contribution 

to nonattainment and interference with 

maintenance for many receptors, while 

the Agency conducts additional analysis 

to support subsequent transport-related 

rulemakings including coverage of nonEGU sources (75 FR 45285). 

EPA received comments suggesting 

that it consider cost thresholds higher 

than $500/ton as reductions beyond the 

proposed $500/ton cost threshold were 

needed to fully resolve nonattainment 

and maintenance issues in downwind 

states analyzed at proposal. Some of 

these comments suggested EPA should 

include non-EGUs as they consider the 

higher cost thresholds, others suggested 

EPA continue to exclude non-EGU 

sources in this rulemaking. 

In response to those comments that 

suggested EPA explore higher cost 

thresholds because nonattainment and 

maintenance was not fully resolved, 

EPA first notes that CAA section 110 

(a)(2)(D)(i)(I) only requires the 

elimination of emissions that 

significantly contribute to 

nonattainment or interfere with 

maintenance of the NAAQS in other 

states. Section 110(a)(2)(D)(i)(I) focuses 

exclusively on the transport component 

of nonattainment and maintenance 

problems. Section 110(a)(2)(D)(i)(I) does 

not shift to upwind states the 

responsibility for ensuring that all areas 

in other states attain the NAAQS. As 

such, the mandate of section 

110(a)(2)(D)(i)(I) is not to ensure that 

reductions in upwind states are 

sufficient to bring all downwind areas 

in to attainment, it is simply to ensure 

that all significant contribution to 

nonattainment and interference with 

maintenance is eliminated. Thus, the 

presence of residual nonattainment or 

maintenance areas does not, by itself, 

signify a failure to satisfy the 

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

Furthermore, as noted in section VI.A, 

EPA is finalizing coverage only for the 

EGU emission source-sector category in 

this rulemaking. EPA has not included 

non-EGU sources in this final 

rulemaking. EPA remains convinced 

that timely promulgation and 

implementation of this rule is 

responsive to the Court’s remand of 

CAIR. 

To the extent that significant 

contribution is not eliminated for the 

1997 ozone NAAQS standard at the 

$500/ton cost threshold, EPA is not 

addressing in this rulemaking whether a 

cost threshold greater than $500/ton is 

justified for some upwind states and 

downwind receptors. EPA believes it 

can best serve these states where 

concerns persist regarding projected 

nonattainment or maintenance of the 

1997 ozone NAAQS by quickly 

finalizing this rule and seeking further 

non-EGU reductions in subsequent 

rulemakings. Table VI.B–2 illustrates 

the small amount of EGU reductions 

available as cost threshold increases 

above $500/ton. The ozone-season NOX

reductions available in the Transport 

Rule states between the $500/ton and 

$1,000/ton cost thresholds amount to 

less than 3,000 tons. EPA believes that 

potentially substantial non-EGU ozoneseason 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 

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 


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46AQAT results indicated that one receptor in the 

Liberty-Clairton area continued to have 

maintenance problems with the annual PM2.5

standard. However, final air quality modeling 

results (described in section VIII.B) indicated that 

this maintenance problem was resolved for this 

receptor under the final Transport Rule. 

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 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 nonEGU reductions. EPA analysis suggests 

that while NOX emission reductions 

lead to reductions in PM2.5, SO2

reductions are generally more costeffective 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 to 

nonattainment and interference with 

maintenance. EPA finds in the final 

Transport Rule that the $500/ton cost 

threshold for annual NOX, in concert 

with the SO2 cost threshold selected 

below, successfully eliminates 

significant contribution to 

nonattainment and interference with 

maintenance for the 1997 annual PM2.5

NAAQS and the 2006 24-hour PM2.5

NAAQS in the states covered by this 

Rule for PM2.5. 

The reasons for not considering cost 

thresholds lower than $500/ton for 

annual NOX are the same as those 

identified for not doing so for ozoneseason NOX. In addition to its PM2.5

reduction benefits, annual NOX control 

at the $500/ton threshold can help to 

reduce nitrate replacement in the 

atmosphere. As explained earlier, 

nitrate replacement happens when SO2

emissions reductions successfully 

reduce ammonium sulfate (a component 

of PM2.5) but provoke a PM2.5 rebound 

effect by freeing up additional ammonia 

to form ammonium nitrate (another 

component of PM2.5). 

d. Cost Thresholds Examined and 

Selected for SO2

EPA first assessed the downwind air 

quality impacts of emission reductions 

modeled at the $500/ton threshold in all 

states found to be linked to downwind 

sites for PM2.5 transport, as well as in 

the states hosting those downwind sites. 

The air quality assessment tool 

projected that those reductions do not 

fully resolve nonattainment and 

maintenance problems with the PM2.5

standards for certain areas to which the 

following states are linked: Illinois, 

Indiana, Iowa, Kentucky, Maryland, 

Michigan, Missouri, New Jersey, New 

York, North Carolina, Ohio, 

Pennsylvania, Tennessee, Virginia, West 

Virginia, and Wisconsin. EPA 

proceeded to analyze available 2014 

emission reductions at higher cost 

thresholds from these states, collectively 

referred to as Group 1 states for SO2

control. 

For Group 2 states, the air quality 

assessment tool projected that the SO2

reductions at this first cost threshold 

assessed would resolve the 

nonattainment and maintenance 

problems for all of the areas to which 

the following states are linked: 

Alabama, Georgia, Kansas, Minnesota, 

Nebraska, South Carolina, and Texas. 

EPA thus finds that these states’ 

significant contribution is eliminated at 

the $500 per ton level in 2014; they are 

collectively referred to as Group 2 states 

for SO2 control. Because their 

significant contribution is eliminated at 

this stringency of control, EPA did not 

analyze higher cost thresholds for Group 

2 states. 

The states in Group 1 and Group 2 are 

rationally grouped considering air 

quality and cost. EPA determined that it 

would not be appropriate to assign the 

same cost threshold to Group 2 and 

Group 1 states because a significantly 

lower cost threshold was sufficient to 

resolve air quality problems at all 

downwind receptors linked to the 

Group 2 states. Although states are 

linked to different sets of downwind 

receptors, EPA analysis indicated that 

the cost threshold needed to resolve 

downwind air quality problems varied 

only to a limited extent among states 

within Group 1 and among states within 

Group 2. It did, however, vary greatly 

between the Group 1 and Group 2 states. 

The ruling of the DC Circuit in Michigan 

v. EPA, 213 F.3d 663, 679–80 (D.C. Cir. 

2000), accepting EPA’s prior use of a 

transport remedy with uniform controls, 

supports EPA’s decision to use a 

uniform cost threshold for a group of 

states. 

As discussed in section VI.B, the cost 

threshold for Group 1 states was 

examined at escalating levels in 2014 (it 

remained at $500/ton for Group 2 

states). EPA examined emissions at SO2

cost thresholds of $500, $1,600, $2,300, 

$2,800, $3,300, and $10,000/ton for 

Group 1 states in 2014. The higher SO2

marginal costs were only imposed in 

Transport Rule states starting in 2014, 

by which time the advanced pollution 

control retrofits induced at those higher 

cost thresholds could be installed. (See 

section VI.D.2 for EPA’s assessment and 

decisions regarding SO2 budget 

formation in Group 1 states in 2014.) 

EPA observed some degree of 

additional air quality benefit at 

downwind receptors across all of the 

cost thresholds examined for SO2, but 

significant air quality outcomes were 

achieved at the $2,300/ton cost 

threshold. The $2,300/ton threshold is 

projected to resolve the last remaining 

nonattainment area for the annual PM2.5

standard (Liberty-Clairton),46 and it also 

is projected to resolve the 

nonattainment and maintenance 

problems with the 24-hour PM2.5

standard at 1 monitor in the Detroit area 

and resolve the maintenance problems 

in the Cleveland area. There were 

significant air quality improvements at 

this level in connection with 

widespread deployment of pollution 

control technology, while the cost 

impacts remained reasonable. 

Moving beyond $2,300/ton to the 

$2,800/ton and $3,300/ton thresholds, 

EPA projected notably smaller air 

quality improvements compared to 

those projected when moving from the 

$1,600/ton threshold to the $2,300/ton 

threshold. EPA also projected no 

ultimate change in the 24-hour PM2.5


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47This area is not currently designated as 

nonattainment for the 24-hour PM2.5 standard. EPA 

is portraying the receptors and counties in this area 

as a single 24-hour maintenance area based on the 

annual PM2.5 nonattainment designation of 

Chicago-Gary-Lake County, IL-IN. 

48AQAT 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. 

49This area is not currently designated as 

nonattainment for the 24-hour PM2.5 standard. EPA 

is portraying the receptors and counties in this area 

as a single 24-hour maintenance area based on the 

annual PM2.5 nonattainment designation of 

Chicago-Gary-Lake County, IL-IN. 

attainment status of the remaining 

nonattainment area (Liberty-Clairton) or 

three remaining maintenance areas 

(Chicago,47 Detroit, and Lancaster).48 At 

the same time, the total program cost 

continued to increase by about the same 

interval at each of these thresholds as it 

had between the $1,600/ton and $2,300/ 

ton thresholds. EPA thus observed a 

relatively lower cost-effectiveness of 

downwind PM2.5 control via upwind 

SO2 reductions beyond $2,300/ton for 

the receptors linked to Group 1 states. 

Table VI.D–1 and Figure VI.D–1 

demonstrate this relationship between 

cost of EGU SO2 control and downwind 

PM2.5 concentration impacts, showing a 

sustained diminishing of cost 

effectiveness beyond the $2,300/ton 

threshold. The $2,300/ton threshold in 

this analysis is situated at the ‘‘knee-inthe-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 REDUCTIONS a 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 cost-effectiveness (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 

a Downwind PM2.5 improvement based on SO2 reductions from states ‘‘linked’’ to specific receptors. See section VI.C. b Measured as the reduction in maximum design value for the 24-hour PM2.5 NAAQS from AQAT base case to each SO2 threshold for receptors with remaining nonattainment and maintenance exceedances at the $500/ton threshold, averaged across these receptors. 

Furthermore, even at the $10,000/ton 

cost threshold, AQAT still projects 

Liberty-Clairton to face maintenance 

concerns with the annual PM2.5

standard and is projected to remain in 

nonattainment of the 24-hour PM2.5

standard, while the Chicago 49 and 

Lancaster areas are still projected to 

have residual maintenance problems 


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50http://www.epa.gov/pmdesignations/2006

standards/final/TSD/tsd_4.0_4.3_4.3.3_r03_PA_

2.pdf. 

with the 24-hour PM2.5 standard. EPA 

projected that even total elimination of 

EGU SO2 emissions (no matter the cost) 

would not be able to resolve either 

nonattainment of the 24-hour PM2.5

standard in the Liberty-Clairton area or 

the residual maintenance concerns with 

that standard in Lancaster County. EPA 

thus finds that other PM2.5 strategies, 

including local reductions of other 

PM2.5 precursors, are important to 

consider for remaining nonattainment 

and maintenance areas to seek further 

improvements in PM2.5 concentrations. 

Considering both air quality and cost, 

EPA’s multi-factor analysis indicated 

$2,300 per ton as an appropriate cost 

threshold for SO2 in the Group 1 states. 

EPA believes the analyzed cost 

thresholds lower than $2,300/ton were 

not appropriate for SO2 control in the 

Group 1 states under the Transport Rule 

for the following reasons: 

• Downwind air quality impacts up to 

the $2,300 threshold are significant. 

Moving up to $2,300/ton successfully 

resolves all downwind nonattainment of 

the annual and 24-hour PM2.5 standards 

except for the Liberty-Clairton receptor 

in Allegheny county with respect to 

24-hour PM2.5, which EPA has noted is 

heavily influenced by a local source of 

organic carbon (75 FR 45281). 

• Upwind emission reductions 

available up to $2,300/ton are highly 

cost-effective compared with similar 

regulations. 

• The emission reductions up to this 

threshold are achievable with 

widespread deployment of controls that 

can be installed at power plants by 

2014. 

• As stated at proposal, EPA finds it 

reasonable to require a substantial level 

of control of upwind state emissions 

that significantly contribute to 

nonattainment or maintenance problems 

in another state. The $2,300/ton cost 

threshold is comparable to EPA’s survey 

of local non-EGU SO2 reduction 

opportunities in the PM2.5 NAAQS RIA, 

which range in cost from just above 

$2,300/ton to over $16,000/ton (2007 $). 

EPA thus finds it reasonable to seek 

EGU SO2 reductions up to $2,300/ton 

(rather than at a lower cost threshold) in 

the states linked to receptors with 

ongoing attainment and maintenance 

concerns with the PM2.5 NAAQS. 

EPA believes the analyzed cost 

thresholds above $2,300/ton were not 

appropriate for SO2 control in the Group 

1 states under the Transport Rule for the 

following reasons: 

• As noted above, AQAT suggests 

reductions up to $2,300/ton were able to 

resolve all projected downwind 

nonattainment of the annual and 

24-hour PM2.5 NAAQS, with the sole 

exception of projected nonattainment of 

the 24-hour PM2.5 standard at a receptor 

in Liberty-Clairton. It is well-established 

that, in addition to being impacted by 

regional sources, the Liberty-Clairton 

area is significantly affected by local 

emissions from a sizable coke 

production facility and other nearby 

sources, leading to high concentrations 

of organic carbon in this area.50 EPA 

finds that the remaining PM2.5

nonattainment problem is 

predominantly local and therefore does 

not believe that it would be appropriate 

to establish a higher cost threshold 

solely on 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 costeffectiveness of controlling EGU 

emissions in Group 1 states to improve 

downwind PM2.5 concentrations at the 

linked receptors is notably diminished 

beyond the $2,300/ton threshold in this 

analysis. See Figure VI.D–1. 

• EGUs are by far the largest source 

category for SO2 emissions. This 

analysis shows that reductions of EGU 

SO2 emissions up to the $2,300/ton cost 

threshold were significantly more costeffective for improving downwind PM2.5

concentrations than further such 

reductions (beyond the $2,300/ton cost 

threshold) would be to address the 

remaining PM2.5 maintenance concerns. 

EPA’s analysis also shows that these 

maintenance concerns cannot be fully 

resolved even with complete 

elimination of all remaining EGU SO2

emissions, no matter the cost. EPA finds 

that other PM2.5 precursor emission 

reductions, particularly those from local 

sources will be critical for states in these 

remaining areas to consider for 

controlling PM2.5 concentrations with 

respect to maintenance of the 2006 

24-hour PM2.5 NAAQS. 

In summary, the appropriate cost 

thresholds for each state were identified 

through the multi-factor assessment. 

This assessment included both cost and 

air quality considerations. As explained 

above, the ozone-season NOX threshold 

was determined to be $500/ton for all 

states required to reduce ozone-season 

NOX, with residual nonattainment and 

maintenance concerns to be addressed 

in a future rulemaking addressing a 

broader set of source categories for 

additional cost-effective reductions. For 

PM2.5, the appropriate cost threshold for 

each state was determined to be either 

the level at which nonattainment and 

maintenance issues were completely 

resolved in downwind states to which 

the state is linked, the level where 

remaining nonattainment and 

maintenance issues are primarily local, 

or where we found greatly diminished 

improvements in air quality occurring if 

EPA moved further up the cost curve. 

This assessment yielded a cost 

threshold of $2,300/ton on SO2 for 

Group 1 states starting in 2014 ($500/ 

ton in 2012), a cost threshold of $500/ 

ton on SO2 for Group 2 states, and a cost 

threshold of $500/ton on annual NOX

for all states required to reduce 

emissions for purposes of the annual or 

24-hour PM2.5 NAAQS in this rule. 

As explained above, none of these 

specific cost thresholds establish any 

precedent for the cost per ton stringency 

of reductions EPA may require in future 

transport-related rulemakings; these 

specific cost thresholds are based on 

current analyses of air quality and cost 

of emission reductions with respect to 

the NAAQS considered in this 

rulemaking and thus would not be 

relevant to future rulemakings (which 

would consider updated information) or 

rulemakings with respect to different 

NAAQS. In particular, EPA 

acknowledges that additional action 

EPA will require in a subsequent 

rulemaking to address significant 

contribution to nonattainment and 

interference with maintenance of the 

2008 ozone NAAQS (once 

reconsideration is finalized) is very 

likely to require a higher cost per ton 

stringency of ozone-season NOX control 

applied to a broader set of source 

categories from upwind states than 

found to be appropriate for this 

rulemaking. 

2. State Emission Budgets (Step 4) 

a. Budget Methodology 

EPA used the multi-factor assessment 

to identify, for each state, the cost 

threshold that should be used to 

quantify that state’s significant 

contribution. As described above, in the 

context of this rulemaking EPA 

identified a cost threshold of $500/ton 

for ozone-season NOX control for all 

states required to reduce ozone-season 


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NOX emissions for purposes of the 1997 

ozone NAAQS in this rule. EPA also 

identified a cost threshold of $500/ton 

for annual NOX control for all states 

required to reduce annual NOX

emissions for purposes of the annual or 

24-hour PM2.5 NAAQS in this rule. 

Finally, EPA identified a cost threshold 

of $500/ton of SO2 starting in 2012 for 

all states required to reduce SO2

emissions for purposes of the annual or 

24-hour PM2.5 NAAQS in this rule, and 

$2,300/ton for the Group 1 states 

starting in 2014. 

EPA used these cost thresholds from 

the multi-factor analysis to quantify 

each state’s emissions that significantly 

contribute to nonattainment or interfere 

with maintenance downwind. For 

example, for a Group 1 state, EPA 

modeling of the cost threshold conveys 

emission reductions available in each 

covered state from operation of existing 

pollution controls as well as all 

emission reductions available at cost 

thresholds of $500/ton for annual NOX

in 2012 and 2014, $500/ton for SO2 in 

2012, and $2,300/ton for SO2 in 2014. 

The total SO2 and NOX projected at 

these cost levels in that state in those 

years represents that state’s emissions 

once significant contribution to 

nonattainment or interference with 

maintenance downwind for the relevant 

PM2.5 NAAQS has been eliminated. 

TABLE VI.D–2—EXAMPLE OF EMISSION REDUCTIONS AND BUDGET FORMATION IN PENNSYLVANIA FOR ANNUAL SO2 AND

NOXa

Final cost 

threshold 

Base case 

emissions 

(1,000 tons) 

Remaining 

emissions at 

cost thresholds 

(1,000 tons) 

Emissions 

eliminated 

(1,000 tons) 

A B C D E F 

2012 .......................................... SO2 ........................................... $500 493 279 215 

NOX .......................................... 500 129 120 9 

2014 .......................................... SO2 ........................................... 2,300 507 112 395 

NOX .......................................... 500 132 119 13 

a Note: In this table, emissions are shown for fossil-fuel-fired EGUs > 25 MW (i.e., those units likely covered by the Transport Rule). Table 

VI.D.2 illustrates how budgets are derived from the elimination of significant contribution for the state of Pennsylvania. Column C illustrates the 

cost thresholds applied in the costing run that was ultimately identified as the final cost threshold in the multi-factor analysis. Column D shows 

the base case emissions for the identified pollutant in the identified time period. Column E shows the emission levels that result when the cost 

thresholds identified in column C are applied. Because this is the cost threshold identified through the multi-factor analysis and the point where 

all significant contribution to nonattainment and interference with maintenance has been addressed for the PM2.5 NAAQS—state budgets are 

based on these emission levels. The final column illustrates the emission reductions for the state in an average year (before accounting for 

variability). 

EPA’s modeling of a state’s SO2 and 

annual NOX emission levels (from 

fossil-fired EGUs > 25 MW) at the 

relevant cost thresholds in each state 

reflect that state’s emissions from 

covered sources after the removal of 

significant contribution to 

nonattainment and interference with 

maintenance of the PM2.5 NAAQS 

considered in this rulemaking. As these 

state emission levels reflect the removal 

of significant contribution and 

interference with maintenance, they are 

reasonable levels on which to determine 

state budgets. Consequently, EPA based 

state budget levels on the state level 

emissions that remained at the cost 

threshold. Each state’s budget 

corresponds to its emission level 

following the elimination of significant 

contribution to nonattainment and 

interference with maintenance in an 

average year (before taking year-to-year 

variability into account, as discussed in 

section VI.E below). Therefore, the 

implementation and realization of these 

budgeted emission levels leads to the 

elimination of significant contribution 

to nonattainment and interference with 

maintenance and EPA meets the 

statutory mandate of section 

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

1997 annual PM2.5 NAAQS and the 2006 

24-hour PM2.5 NAAQS. 

EPA’s establishment of state budgets 

for ozone-season NOX control follow the 

same methodology as described above 

for SO2 and annual NOX.

Implementation of these ozone-season 

NOX budgets reflects the elimination of 

significant contribution to 

nonattainment and interference with 

maintenance of the 1997 ozone NAAQS 

for 15 states, whereas 11 other states’ 

ozone-season NOX budgets reflect 

meaningful progress toward (but may 

not reflect full completion of) this 

elimination under the mandate of 

section 110(a)(2)(D)(i)(I). See section III 

for lists of states. 

This approach to basing budgets on 

projected state level emissions used in 

the multi-factor analysis is identical to 

the approach used in the proposal for 

determining 2014 SO2 budgets for 

Group 1 states. EPA is extending this 

approach more broadly in the final 

Transport Rule to create state budgets 

for ozone-season NOX, annual NOX, and 

SO2 in all relevant states in both 2012 

and 2014. In the proposal EPA used a 

more complex approach based on a 

comparison of historic and projected 

unit-level emissions (further adjusted 

for operation of existing controls) in 

each state to create 2012 state budgets 

for ozone-season NOX, annual NOX, and 

Group 2 SO2. At the time of proposal, 

EPA believed that historic 2009 

emissions data were in some cases more 

representative of expected emissions in 

2012 than pure modeling projections 

made at the time (75 FR 45290). 

However, following the proposal EPA 

has made significant updates to the IPM 

model for projecting EGU emissions, 

including specifically the adoption of 

2009 historic data into its modeling 

parameters directly. EPA also received 

substantial public input following the 

proposal on the model’s assumptions 

and representation of individual units, 

which allowed EPA to improve its 2012 

and 2014 emission projections for states 

under the cost thresholds considered. 

These modeling updates diminish the 

concerns EPA expressed at proposal that 

2009 historic data may have offered for 

some states a better proxy for 2012 

emissions than model projections, 

particularly now that EPA is 

incorporating 2009 data directly in its 

updated modeling projections. Given 

these updates to the model in response 

to public comment, EPA believes it is 

more appropriate for the final rule to 

use a consistent approach based on 

projected state level emissions for all 

state budgets, as was done for Group 1 

SO2 budgets in 2014 at proposal. EPA 

received significant comment 

supporting the use of the model to 


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51These budgets include minor technical 

corrections to SO2 budgets in three states (KY, MI, 

and NY) that were made after the impact analyses 

for the final rule were conducted. EPA conducted 

sensitivity analysis confirming that these 

differences do not meaningfully alter any of the 

Agency’s findings or conclusions based on the 

projected cost, benefit, and air quality impacts 

presented for the final Transport Rule. The results 

of this sensitivity analysis are presented in 

Appendix F in the final Transport Rule RIA. 

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 emission 

budgets for those years on relevant 

pollutants for that state to control under 

the Transport Rule. EPA’s modeling 

projects that some states have 2014 

emissions that are lower than their 2012 

projected emissions even as the same 

cost threshold (e.g., $500/ton) is applied 

in both years. This occurs in the annual 

NOX, ozone-season NOX, and Group 2 

SO2 program. As such, EPA’s 

application of this budgeting 

methodology results in a tightening of 

budgets in states whose projected 

emissions of that budgeted pollutant 

decline from 2012 to 2014 as the cost 

threshold is held constant. 

There are two primary variables that 

explain the decrease in emissions for 

some states between 2012 and 2014 as 

the cost threshold remains constant over 

both time periods. First, even though 

the cost threshold is constant between 

2012 and 2014 for the programs noted 

above, the cost threshold for SO2 Group 

1 increases in 2014. This higher cost 

threshold for Group 1 SO2 results in 

obvious reductions in SO2 emissions in 

the Group 1 states, but also may lower 

the cost of certain related NOX

reductions in those states as well such 

that they become newly available within 

the $500/ton threshold. For example, if 

a state increases natural gas generation 

in response to the higher SO2 cost 

threshold, such action also yields 

additional annual and ozone-season 

NOX emission reductions that are costeffective 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 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 

provisions of a Georgia state rule that go 

into effect after 2012 but before 2014. 

These requirements involve the 

installation and operation of specific 

advanced pollution controls. These 

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 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 that allowing for 

such emission growth in covered states 

beyond 2012 would be inconsistent 

with the Transport Rule’s identification 

and elimination of significant 

contribution to nonattainment and 

interference with maintenance 

beginning in 2012. Therefore, for any 

covered state whose emissions of a 

relevant pollutant are projected to 

increase from 2012 to 2014 under the 

relevant cost thresholds selected in the 

multi-factor analysis described above, 

EPA is finalizing that state’s 2014 

emission budget to maintain the same 

level of the 2012 emission budget, 

thereby disallowing such an emission 

increase that is inconsistent with the 

110(a)(2)(D)(i)(I) mandate. Tables VI.D– 

3 and VI.D–4 below list state emission 

budgets.51

TABLE VI.D–3—SO2 AND ANNUAL NOX STATE EMISSION BUDGETS FOR ELECTRIC GENERATING UNITS BEFORE

ACCOUNTING FOR VARIABILITY * 

[Tons] 

Group 

SO2 NOX

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 


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52 It is important to note that Maryland’s modeled 

contributions in isolation were greater than the 1 

percent threshold for all three of the NAAQS 

considered at all of the same receptors for which 

Maryland and DC were ‘‘linked,’’ and therefore EPA 

would have considered Maryland ‘‘linked’’ to the 

same set of downwind receptors even if the Agency 

had treated Maryland’s contributions and the 

District of Columbia’s contributions separately. 

53The future retirement status of this D.C. facility 

was also supported by its inclusion on PJM’s future 

deactivation list. PJM further suggested that 

reliability issues related to their retirement are 

expected to be resolved by next year in time for its 

planned retirement date. (See PJM pending 

deactivation request in TR Docket.) 

TABLE VI.D–3—SO2 AND ANNUAL NOX STATE EMISSION BUDGETS FOR ELECTRIC GENERATING UNITS BEFORE

ACCOUNTING FOR VARIABILITY *—Continued 

[Tons] 

Group 

SO2 NOX

2012–2013 2014 and beyond 2012–2013 2014 and beyond 

Illinois ............................................................... 1 234,889 124,123 47,872 47,872 

Indiana ............................................................. 1 285,424 161,111 109,726 108,424 

Iowa .................................................................. 1 107,085 75,184 38,335 37,498 

Kansas ............................................................. 2 41,528 41,528 30,714 25,560 

Kentucky .......................................................... 1 232,662 106,284 85,086 77,238 

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

Michigan ........................................................... 1 229,303 143,995 60,193 57,812 

Minnesota ......................................................... 2 41,981 41,981 29,572 29,572 

Missouri ............................................................ 1 207,466 165,941 52,374 48,717 

Nebraska .......................................................... 2 65,052 65,052 26,440 26,440 

New Jersey ...................................................... 1 5,574 5,574 7,266 7,266 

New York ......................................................... 1 27,325 18,585 17,543 17,543 

North Carolina .................................................. 1 136,881 57,620 50,587 41,553 

Ohio .................................................................. 1 310,230 137,077 92,703 87,493 

Pennsylvania .................................................... 1 278,651 112,021 119,986 119,194 

South Carolina ................................................. 2 88,620 88,620 32,498 32,498 

Tennessee ....................................................... 1 148,150 58,833 35,703 19,337 

Texas ............................................................... 2 243,954 243,954 133,595 133,595 

Virginia ............................................................. 1 70,820 35,057 33,242 33,242 

West Virginia .................................................... 1 146,174 75,668 59,472 54,582 

Wisconsin ......................................................... 1 79,480 40,126 31,628 30,398 

Grand Total ............................................... ............................ 3,385,929 2,135,026 1,245,869 1,164,910 

Group 1 Total ............................................ ............................ 2,530,234 1,345,402 NA NA 

Group 2 Total ............................................ ............................ 855,695 789,624 NA NA 

Note: These state emission budgets apply to emissions from electric generating units covered by the Transport Rule Program. Group 1/Group 

2 designations are only relevant for SO2 emissions budgets. 

* The impact of variability on budgets is discussed in section VI.E. 

The District of Columbia is not 

covered by the final Transport Rule. As 

discussed in section V.D of this 

preamble and as done for the Transport 

Rule proposal, EPA combined 

contributions projected in the air quality 

modeling from Maryland and the 

District of Columbia to determine 

whether those jurisdictions collectively 

contribute to any downwind 

nonattainment or maintenance receptor 

in amounts equal to or greater than the 

1 percent thresholds. This modeling 

confirmed that the combined 

contributions exceed the air quality 

threshold at downwind receptors for the 

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

NAAQS considered. Both Maryland and 

the District of Columbia are therefore 

linked to these receptors.52 However, 

the District of Columbia is not included 

in the Transport Rule because, in the 

second step of EPA’s significant 

contribution analysis, we concluded 

that there are no emission reductions 

available from EGUs in the District of 

Columbia at the cost thresholds deemed 

sufficient to eliminate significant 

contribution to nonattainment and 

interference with maintenance of the 

NAAQS considered at the linked 

receptors. At the time of this 

rulemaking, EPA finds only one facility 

with units meeting the Transport Rule 

applicability requirements in the 

District of Columbia. EPA’s projections 

do not show any generation from this 

facility to be economic under any 

scenario analyzed (including the base 

case), and the facility’s owners have also 

announced plans to retire its units in 

early 2012.53 Therefore, this unit is 

projected to have zero emissions in 

2012. As such, the total SO2 and NOX

emissions in the District of Columbia for 

EGUs that meet the Transport Rule 

applicability requirements is also 

projected to be zero. It follows therefore, 

that EPA did not identify any emission 

reductions available at any of the cost 

thresholds considered in the final rule’s 

multi-factor analysis to identify 

significant contribution to 

nonattainment and interference with 

maintenance. For this reason, EPA 

concludes that no additional limits or 

reductions are necessary, at this time, in 

the District of Columbia to satisfy the 

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

with respect to the 1997 ozone, the 1997 

PM2.5 and the 2006 PM2.5 NAAQS. EPA 

is therefore neither establishing budgets 

nor finalizing any FIPs for the District 

of Columbia in this rule. 

TABLE VI.D–4—OZONE SEASON NOX

STATE EMISSION BUDGETS FOR

ELECTRIC GENERATING UNITS BEFORE ACCOUNTING FOR VARIABILITY * 

[Tons] 

2012–2013 2014 and 

beyond 

Alabama ................ 31,746 31,499 

Arkansas ............... 15,037 15,037 

Florida ................... 27,825 27,825 

Georgia ................. 27,944 18,279 

Illinois .................... 21,208 21,208 


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TABLE VI.D–4—OZONE SEASON NOX

STATE EMISSION BUDGETS FOR

ELECTRIC GENERATING UNITS BEFORE ACCOUNTING FOR VARIABILITY *—Continued 

[Tons] 

2012–2013 2014 and 

beyond 

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 

covered by the Transport Rule Program. 

Group 1/Group 2 designations are only relevant for SO2 emissions budgets. 

* The impact of variability on budgets is discussed in section VI.E. 

EPA notes that the NOX budgets for 

five states linked to downwind ozone 

receptors in the final Transport Rule are 

equal to their projected 2012 base case 

emissions. The five states are Arkansas, 

Indiana, Louisiana, Maryland, and 

Mississippi. These states are among 

those found to meet or exceed the 1 

percent contribution threshold for the 

1997 ozone NAAQS at downwind 

receptors and are thus ‘‘linked’’ to 

downwind receptors. EPA therefore 

evaluates, in the second step of its 

significant contribution analysis, what 

emission limits are necessary to ensure 

that all emissions that constitute the 

state’s significant contribution to 

nonattainment and interference with 

maintenance are prohibited. As 

explained above, EPA decided to 

require from all such states all 

reductions available at the $500/ton cost 

threshold. The five states identified 

above do not appear to show EGU 

ozone-season NOX reductions at the 

$500/ton cost threshold relative to the 

2012 base case projections (which do 

not take into account reductions to be 

made in other states as a result of this 

rule). Therefore, EPA conducted further 

analysis to evaluate whether such 

reductions were available in these states 

and whether emission limits are 

necessary to prohibit these states from 

significantly contributing to downwind 

nonattainment or interfering with 

maintenance of the 1997 ozone NAAQS 

in other states. (See the docket to this 

rulemaking for the IPM run titled 

TR_uncontrolled_ozone_states_Final.’’) 

Specifically, EPA projected those 

states’ ozone-season NOX emissions if 

all other linked states (but not these five 

states) were to make all available 

reductions at the $500/ton threshold. 

That analysis revealed that if emission 

limits were not established for these five 

states, ozone-season NOX emissions in 

each of the states would increase 

(beyond the 2012 base case emission 

projections), due to interstate shifts in 

electricity generation that cause 

‘‘emissions leakage’’ in uncovered 

states. These increases would result in 

each state’s emissions being above the 

level associated with the prohibition of 

all emissions that can be eliminated at 

the $500/ton threshold. EPA thus 

determined that it is necessary to 

establish emission limits for these states 

at the $500/ton level. These limits, 

although equal to the state’s 2012 

projected base case emissions, are 

necessary to prohibit all emissions that 

can be controlled at the $500/ton cost 

threshold. In other words, the 

significant contribution to 

nonattainment and interference with 

maintenance addressed by the ozone 

FIPs for these states is the difference 

between these states’ projected 

emissions if they were not covered 

under the Transport Rule (but other 

states were), and their emissions after 

all emissions that can be eliminated at 

$500/ton are prohibited. 

In addition, EPA notes that four of 

these five states (Arkansas, Indiana, 

Louisiana, and Mississippi) are linked 

to receptors in either the Houston or 

Baton Rouge areas, which are projected 

to continue facing nonattainment or 

maintenance concerns with the 1997 

ozone NAAQS, respectively. To allow 

these states to increase emissions above 

base case projections would erode the 

measurable progress toward eliminating 

significant contribution to 

nonattainment and interference with 

maintenance secured by achieving 

ozone-season NOX reductions in the 

other states linked to these receptors. 

Furthermore, as discussed in section III, 

EPA may require additional reductions 

in these states to fully address 

significant contribution to 

nonattainment and interference with 

maintenance with respect to the 1997 

ozone NAAQS in a future rulemaking to 

be proposed after finalizing 

reconsideration of the 2008 ozone 

NAAQS. 

b. Relationship of Group 1 and Group 2 

States for SO2 Control 

In the Proposal, EPA chose not to 

allow sources in Group 1 states to use 

Group 2 SO2 allowances for compliance, 

and likewise not to allow sources in 

Group 2 states to use Group 1 SO2

allowances for compliance at any time. 

The preamble clearly states, ‘‘With 

regard to interstate trading, the two SO2

stringency tiers would lead to two 

exclusive SO2 trading groups. That is, 

states in SO2 Group 1 could not trade 

with states in SO2 Group 2’’ (75 FR 

45216). No such distinction or 

limitation exists for NOX allowance 

trading. 

EPA received significant public 

comment both in support and 

opposition to the two distinct SO2

trading programs. Those in opposition 

noted that the variability limits imposed 

at the state level made the compliance 

restrictions between the two groups 

unnecessary. Commenters also noted 

that it may unfairly penalize sources 

that are part of the same airshed, but are 

on opposite sides of a state boundary. 

Those in favor of the separate SO2

compliance programs noted that it 

would reduce the probability of a state 

exceeding its variability limit. Allowing 

the use of Group 1 or Group 2 

allowances for compliance between the 

two SO2 programs would potentially 

encourage Group 1 states to purchase 

allowances instead of making 

reductions necessary to eliminate 

significant contribution. Group 1 states 

are states that need continued 

reductions (beyond the $500/ton 

threshold) to eliminate their significant 

contribution to nonattainment and 

interference with maintenance. Group 2 

states have already eliminated their 

significant contribution to 

nonattainment and interference with 

maintenance at the $500/threshold. So 

to allow Group 1 or Group 2 allowances 

to be used interchangeably for 

compliance between the two SO2 groups 

would be to allow the shifting of 

reductions from areas where they are 

needed to eliminate significant 

contribution to nonattainment and 

interference with maintenance to areas 

where they are not needed to eliminate 

the prohibited emissions. EPA also 

agrees that allowing for trading between 

the two groups in the remedy finalized 

in this action would increase risk of a 

state exceeding its variability limit. For 

these reasons, EPA is finalizing this 

rulemaking with the same prohibition 

on SO2 trading between Group 1 and 

Group 2 states that was defined in the 

proposal. Further, EPA clarifies that 

while trading of allowances (i.e., 


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buying, selling, and banking) is allowed 

without restriction, it is specifically the 

surrender of SO2 allowances for 

compliance that is limited. As 

mentioned earlier, a source in a Group 

1 state can only use SO2 allowances 

allocated to Group 1 states for 

compliance with the SO2 trading 

program. Likewise, a source in a Group 

2 state can only use SO2 allowances 

allocated to Group 2 states for 

compliance with the SO2 trading 

program. 

c. Ozone-Season Budgets 

EPA established the ozone-season 

NOX budgets in a similar manner to the 

annual NOX and SO2 budgets by using 

the state level emissions from the cost 

threshold that reflected the removal of 

significant contribution to 

nonattainment and interference with 

maintenance. Ozone-season budgets 

were based on the state level emissions 

from fossil-fuel-fired units greater than 

25 MW observed at this cost threshold. 

As described in section VI.B, all cost 

thresholds examined reflected the final 

Transport Rule geography and the 

marginal costs were applied 

accordingly. Therefore, for an ozoneonly state like Florida, the state level 

emissions would only reflect an ozoneseason cost threshold of $500/ton in the 

final cost curves for 2012 and 2014. For 

a state subject to both annual and ozoneseason programs, the marginal cost 

curves would reflect a $500/ton NOX

cost year round, a $500/ton SO2 cost in 

2012 and the $2,300/ton SO2 cost 

starting in 2014 if a Group 1 state. 

(1) Length of Ozone Season 

(a) Proposed Rule. For purposes of 

determining ozone-season budgets in 

the proposed rule, EPA defined the 

ozone season based on a 5 month period 

(May 1 through September 30). This 5 

month ozone season was consistent 

with the approach taken by the OTAG, 

the NOX SIP Call, and CAIR. EPA 

requested comment on whether EPA 

should base final rule budgets on a 

longer season, such as March through 

October. 

(b) Public Comments. Several 

commenters supported continuing with 

the May through September time period. 

One commenter supported continuing 

with this time period, but argued that 

EPA should consider lengthening the 

ozone season for future efforts. One 

commenter questioned the concept of 

ozone season budgets and 

recommended EPA focus on sources 

with greater emissions on high ozone 

days. 

(c) Final rule. For the final rule, EPA 

has retained the approach in the 

proposed rule, as commenters broadly 

supported the proposal’s ozone-season 

duration and ozone-season NOX

limitations. Notably, many Transport 

Rule states covered for PM2.5 reductions 

will have sources with annual NOX

controls that are likely to keep operating 

year round to address PM2.5 and ozone. 

EPA believes that experience from 

ozone-season NOX trading has 

consistently shown that the emission 

measures taken to comply with ozoneseason budgets provide emission 

reductions throughout the ozone-season, 

including the highest ozone days. (See 

NOX Budget Trading Program and CAIR 

Program progress reports in the docket 

to this rulemaking or at http:// 

www.epa.gov/airmarkets/progress/ 

nbp08.html and http://www.epa.gov/ 

airmarkets/progress/CAIR_09/ 

CAIR09.html.) However, EPA believes 

that there is merit in future Agency 

actions addressing ozone transport in 

considering strategies to target high 

ozone days more specifically. 

d. Summary of Cost Thresholds and 

Final Budgets for PM2.5 and Ozone 

Summary of methodology. In 

summary, EPA determined that SO2

emissions that could be reduced for 

$2,300/ton in 2014 should be 

considered a state’s significant 

contribution to nonattainment and 

interference with maintenance, unless 

EPA determined that a lesser reduction 

would fully resolve the nonattainment 

and/or maintenance problem for all the 

downwind receptors to which a 

particular state might be linked. For 

these Group 2 states EPA is determining 

that a lesser reduction of SO2, based on 

the amount of SO2 reductions that can 

be reasonably achieved by 2012 is 

appropriate. This level is defined by the 

reductions observed in the $500/ton 

cost threshold. EPA also determined 

that all states linked to downwind PM2.5

nonattainment and maintenance 

problems should be required to achieve 

those emission reductions that can be 

reasonably achieved by 2012. Finally, 

EPA determined that all states linked to 

downwind PM2.5 nonattainment and 

maintenance problems should, by 2012, 

remove all NOX emissions that can be 

reduced for $500/ton and run all 

existing controls in 2012. 

For ozone-season NOX, EPA 

determined that all states linked to 

downwind ozone and nonattainment 

and maintenance problems should be 

required to achieve those ozone-season 

emission reductions associated with a 

cost threshold of $500 per ton. 

Additionally, EPA examined final 2012 

and 2014 budgets based on state level 

emissions at $500 cost threshold. 

The budget formation methodology 

finalized in this action responds to 

concerns about state budgets expressed 

by commenters on the Transport Rule 

proposal. EPA requested comment on 

the four step approach used to 

determine significant contribution and 

determine budgets in the proposal. 

Some commenters noted that the state 

level emissions from the cost thresholds 

used to determine significant 

contribution to nonattainment and 

interference with maintenance did not 

match the state level emissions allowed 

by the final budgets. The concern was 

that the state level emissions that 

reflected the elimination of significant 

contribution in the AQAT analysis, in 

particular for NOX, were less than the 

emissions allowed by the final budgets. 

The result would be an implementation 

that did not quite fully eliminate the 

significant contribution to 

nonattainment and interference with 

maintenance defined in the rule. The 

proposed budgets not matching the 

levels reflected in the proposed costing 

runs were an artifact of the budget 

formation process that relied on a 

combination of historic and projected 

data. While EPA noted this process 

resulted in state budgets that ‘‘reflected’’ 

EGU emissions at $500/ton, it was not 

always consistent with the EGU 

emissions at $500/ton in the costing 

runs as the commenters noted. By using 

the cost curves to determine both 

significant contribution to 

nonattainment and interference with 

maintenance—and state budgets—in the 

final rule, EPA addresses the 

commenter’s concerns about any 

inconsistency between the two in the 

proposal. 

Some commenters expressed concern 

that the Transport Rule would result in 

state budgets that were in some cases 

higher than those established in CAIR. 

Commenters suggested that this would 

be inconsistent with requirements or the 

spirit of certain CAA provisions aimed 

at preventing backsliding, i.e., sections 

110(l), 172(e), and 193. However, the DC 

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 


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under CAIR, this does not violate either 

the letter or the spirit of CAA provisions 

aimed at backsliding. In particular, CAA 

section 110(l) provides that the 

Administrator may not approve a plan 

revision that would ‘‘interfere with any 

* * * applicable requirement’’ of the 

CAA. 42 U.S.C. 7410(l). Because the 

Court reversed and remanded CAIR 

with instructions to ‘‘remedy’’ the rule’s 

‘‘fundamental flaws’’ (including 

specifically the state budgets found to 

be unlawful (North Carolina, 550 F.3d 

1178), it is difficult to see how new state 

budgets replacing unlawful budgets and 

meeting section 110(a)(2)(D)(i)(I) 

requirements could be viewed as 

interfering with requirements of the 

CAA. Indeed, the commenters’ approach 

would severely limit EPA’s ability to 

meet the Court’s mandate to develop a 

new rule consistent with section 

110(a)(2)(D)(i)(I). See North Carolina, 

531 F.3d 921 (explaining that EPA may 

not require ‘‘some states to exceed the 

mark’’ of eliminating their significant 

contribution). Further, the other CAA 

sections cited by the commenters 

(section 172(e), addressing 

circumstances where the Administrator 

relaxes a NAAQS, and section 193, 

addressing the treatment of 

requirements promulgated before the 

November 15, 1990, enactment date for 

the 1990 Amendments to the Clean Air 

Act) are not applicable here. 

Additionally, while the CAIR budgets 

may have been tighter than Transport 

Rule state budgets for a couple of states, 

the sum of state budgets that were 

subject to both CAIR and the Transport 

Rule is lower under the Transport Rule 

for the annual programs. Moreover, the 

carryover of the large Title IV allowance 

bank in CAIR allowed for a great deal 

more emissions within any given state 

than is permitted under the Transport 

Rule. 

E. Approach to Power Sector Emission 

Variability 

1. Introduction to Power Sector 

Variability 

Variability is an inherent aspect of the 

production and delivery of electricity. It 

follows that variations in state 

emissions are not only a result of 

variations in the level of emission 

control, but also are caused by the 

inherent variability in power generation. 

The state budgets do not account for this 

latter source of variability at the state 

level. Emission variability is built into 

the design of power systems, which use 

a wide mix of power generation sources 

with varying use and emission patterns 

to ensure reliability in electric power 

generation. Variations in weather, 

demand due to changes in the level of 

economic activity, the portion of electric 

generation that is fossil-fuel-fired, the 

length and number of outages at power 

generation units, and other factors, can 

lead to significant variations in the load 

levels of different power generation 

sources. Variations in the load levels of 

sources in any given state cause 

variations in the level of emissions in 

that state. Thus, EPA believes it is 

appropriate, in this rule, to take into 

account the variations that are caused 

by inherent variability in power 

generation. More specifically, variations 

in these external variables can cause 

significant fluctuations in state 

emissions, even when action has been 

taken to prohibit all emissions within a 

state that significantly contribute to 

nonattainment or interfere with 

maintenance in another state. For this 

reason, EPA considers variability when 

determining the state specific 

requirements in this rule. EPA does so 

by developing variability limits and 

assurance levels for each state, as 

described in this section, that are 

consistent with the statutory mandate of 

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

Loads on a power system, and thus on 

power generation sources in a given 

state that are on the power system, vary 

over every time interval, changing not 

only in the short term and seasonally, 

but also annually. As noted above, load 

patterns and levels are determined by a 

multiplicity of factors, including 

weather, economic activity, the portion 

of electric generation that is fossil-fuelfired, and the length and number of 

outages at power generation units, 

which vary over time. In particular, 

weather obviously varies not just from 

season-to-season but also from year-toyear, and even small changes in annual 

weather patterns can affect how the 

power system and power generation 

sources on the power system operate 

during a year. For example, load, and 

the resulting use of generation sources 

on an interconnected grid to meet load, 

depend not only on how hot a summer 

day is, but also on where a heat wave 

occurs and how long it lasts. Similarly, 

a relatively cold winter that drives up 

winter load may also change what 

generation sources are used to address 

the increased demand for heat. Thus, 

the pattern of generation may shift 

geographically as a weather pattern 

moves across the country. Because 

weather and other factors affecting 

loads, and the patterns of generation 

used to meet loads, vary over time and 

from state to state, the resulting level of 

emissions also varies over time and 

from state to state. 

This variability in emissions is not a 

result of variation in emission rates, 

emission controls, or emission control 

strategies, but instead is a result of the 

inherent variability in power generation. 

Patterns of generation change to ensure 

demand for electricity is met and to 

ensure continued reliability of the 

power system. This results in temporal 

and geographic fluctuations in 

emissions. In the final Transport Rule, 

like the proposed rule, EPA explicitly 

takes account of these changing patterns 

of generation and the resultant 

variability in power sector emissions. 

As discussed previously, EPA 

identified a specific amount of 

emissions that must be prohibited by 

each state to meet the requirements of 

CAA section 110(a)(2)(D)(i)(I). EPA also 

developed state baseline emissions for 

power generation sources based on 

projections of state emissions in an 

average year before the elimination of 

prohibited emissions, and state budgets 

for power generation sources based on 

projections of state emissions in an 

average year after the elimination of 

such emissions. However, because of 

the inherent variability in state-level 

baseline emissions—resulting from the 

inherent variability in loads and power 

system and power generation source 

operations—state-level emissions will 

fluctuate from year-to-year even after all 

significant contribution to 

nonattainment and interference with 

maintenance that EPA identified in this 

final rule are eliminated. In an above 

average year, emissions may exceed the 

state budgets which are based on an 

analysis of projected emissions in an 

average year. EPA believes that, because 

baseline emissions are variable for 

reasons unrelated to the degree of 

emission control in a state and 

emissions after the elimination of all 

significant contribution to 

nonattainment and interference with 

maintenance are therefore also variable, 

it is appropriate to take this variability 

into account in developing the remedy 

for meeting the requirements of CAA 

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

limits and assurance levels in the final 

rule account for this inherent 

variability, while ensuring that 

emissions within each state that 

significantly contribute to 

nonattainment or interfere with 

maintenance in another state are 

prohibited. EPA believes this approach 

is both reasonable in that it reflects the 

operation of the power system 

generation in order to maintain electric 

reliability and consistent with the 

statutory mandate of CAA section 

110(a)(2)(D)(i)(I). For these reasons, EPA 


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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 above, the air qualityassured trading remedy’s state-specific 

budgets represent each state’s emissions 

in an average year after elimination of 

significant contribution to 

nonattainment and interference with 

maintenance. Because actual base case 

emissions are likely to vary from 

projected base case emissions, this 

remedy incorporates provisions that 

account for such variability. While the 

primary purpose of this remedy is to 

eliminate significant contribution and 

interference with maintenance, EPA 

believes variability limits also satisfy 

several other objectives. The remedy 

provides the flexibility to deal with realworld variability in the operation of the 

power system through air qualityassured trading and reduces costs of 

compliance with emission reduction 

requirements, while still providing 

assurance for downwind states that 

significant contribution to 

nonattainment and interference with 

maintenance by upwind states will be 

eliminated. EPA believes the limited 

fluctuation in state level emissions that 

this approach permits is consistent with 

the statutory mandate of section 

110(a)(2)(D)(i)(I) because some 

geographic and temporal shifting of 

emissions necessarily results from the 

inherent variability in power generation 

and is caused by factors unrelated to the 

degree of emission control, such as 

weather, economic activity, and unit 

availability. Far from excusing any state 

from addressing emissions within the 

state that significantly contribute to 

nonattainment or interfere with 

maintenance in other states, these 

variability limits ensure that the system 

can accommodate the inherent 

variability in the power sector while 

ensuring that each state eliminates the 

amount of emissions within the state, in 

a given year, that must be eliminated to 

meet the statutory mandate of section 

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

Moreover, the structure of the 

program, which achieves the required 

emission reductions through limits on 

the total number of allowances 

allocated, assurance provisions, and 

penalty mechanisms, ensures that the 

variability limits only allow the amount 

of temporal and geographic shifting of 

emissions that is likely to result from 

the inherent variability in power 

generation, and not from decisions to 

avoid or delay the installation of 

necessary controls. Under the remedy, 

an individual state can have emissions 

up to its budget plus the variability 

limit. However, the requirement that all 

sources hold allowances covering 

emissions, and the fact that those 

allowances are allocated based on statespecific 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. 

The focus of the analysis is on 

quantifying the magnitude of the 

inherent year-to-year variability in statelevel EGU emissions independent of 

measures taken to control those 

emissions (and thus due only to changes 

in electricity generation within each 

state). EPA used this analysis to set 

variability limits as part of the remedy 

to ensure that states are eliminating 

their significant contribution to 

nonattainment and interference with 

maintenance to protect air quality. 

As discussed in detail below, EPA is 

finalizing the Transport Rule with 1- 

year variability limits calculated using a 

modified approach from the one 

described in the proposal. EPA is not 

including the proposal’s 3-year 

variability limits in the final Transport 

Rule. EPA received comments that the 

3-year variability limits increased 

program costs and diminished 

compliance flexibility without 

delivering any additional air quality 

benefits. EGU owners and operators 

expressed concern that 3-year variability 

limits would be impracticable to 

implement and that the 1-year 

variability limits themselves would be 

adequately stringent to ensure 

elimination of significant contribution 

to nonattainment and interference with 

maintenance in each state. 

After further consideration, EPA has 

concluded that 3-year variability limits 

would be unnecessary, would be 

difficult to anticipate, and would not 

have a measurable impact on air quality 

benefits. EPA has determined that 

annual limits are sufficient to eliminate 

significant contribution to 

nonattainment and interference with 

maintenance in all upwind states while 

accommodating the historically 

observed year-to-year fluctuation in 

state-level EGU emissions even at the 

same rate of emissions control in a given 

state. 

In the proposal, EPA used statistical 

methods to derive the 3-year variability 

limit directly from the 1-year variability 

limit, meaning that the two are 

statistically equivalent in the long run 

under certain statistical assumptions. 

Primarily, these assumptions were that 

the variation in electric demand around 

the budget is random from year-to-year 

and that, when the annual emissions are 

averaged over a multi-year time period, 

the average emissions per year will 

equal the state’s budget. The first 

assumption was also made in the 

assessment of the historical year-to-year 

variation in heat input in developing the 

1-year limit (see section 2 of the ‘‘Power 

Sector Variability Final Rule TSD’’ for 

more details). Regarding the second 

assumption, since the state-by-state 

emission budgets are based on the 

availability of emission reductions at an 

equal marginal cost level, EPA expects 

the sources in each of the upwind states 

to make these cost-effective reductions 

and to meet the emission budgets each 

year, on average. 

Since the 3-year variability limit was 

based on average year-to-year variability 

over a longer time horizon, EPA notes 

that a random ordering of those years 

could yield 2 above-average years in a 

row. If, by chance, a third above-average 

year were to follow, the state could face 

violation of the 3-year limit, even if over 

a time period longer than 3 years, that 

state would never have exceeded the 

statistically-equivalent 1-year variability 

limit and its annual emissions would 

have averaged to the level of its budget. 

Effectively, this means that imposing a 

multi-year variability limit would erode 

the 1-year variability limit’s ability to 

accommodate historically observed 

year-to-year variability in state-level 

EGU emissions (due only to generation 

changes), and it would do so without 

providing any additional air quality 

benefits or protection for downwind 

areas (since the average emissions over 

the long time horizon equal the level of 

the budget). 

For more details about the 

relationship between the 1- and 3-year 

limits, see the discussions in section 3 

of the ‘‘Power Sector Variability’’ TSD 

from the proposed Transport Rule, 

which describes the derivation of the 3- 

year limit from the 1-year variability 

and section 3 of the ‘‘Power Sector 

Variability Final Rule TSD’’, which 

describes the results of a numerical 


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54The six states in the supplemental proposal for 

inclusion in the Transport Rule’s ozone-season NOX

program have measured historic ozone-season 

variability that would be adequately covered by this 

final rule’s ozone-season NOX variability level (21 

percent). Please see the ‘‘Power Sector Variability 

Final Rule TSD’’ for more details. 

simulation showing that the 1- and 3- 

year limits are statistically 

indistinguishable and, thus, redundant 

over the course of the program to 

accommodate year-to-year variability. 

While EPA expects the yearly 

emissions in each state, on average, to 

equal the level of the budgets, EPA also 

estimated the air quality impacts of 5, 

10, 15, and 20 percent emission 

variability using the air quality 

assessment tool, which is presented in 

section 4 of the ‘‘Power Sector 

Variability Final Rule TSD.’’ That 

analysis shows that year-to-year 

fluctuations of up to 20 percent in SO2

emissions from upwind states linked to 

a given downwind receptor do not 

undermine the ability of the Transport 

Rule programs to resolve nonattainment 

or maintenance concerns at that 

receptor. The analysis presented in the 

TSD focuses on SO2 emissions and was 

designed to examine the sensitivity of 

downwind air quality to upwind EGU 

emission levels. The share of total SO2

emitted by EGUs is significantly larger 

than the share of total NOX emitted by 

EGUs. For example, in the states for 

which EPA modeled base case 

contributions of these pollutants, EGUs 

accounted for 74 percent of total SO2, 14 

percent of total annual NOX, and 15 

percent of total ozone-season NOX

emissions. Therefore, when varying 

EGU emissions only, downwind air 

quality would be most sensitive to 

upwind variations in SO2, because 

relative variations in EGU SO2

emissions have a greater impact on total 

SO2 emissions than the same relative 

variation in EGU NOX emissions would 

have on total NOX emissions affecting 

downwind air quality. Because the 

Transport Rule only affects upwind 

emissions from EGU sources, downwind 

air quality would be more sensitive to 

variability in upwind state SO2

emissions under this rule than 

variability in upwind state NOX

emissions under this rule (given that the 

rule affects a smaller scope of total NOX

emissions compared to the scope 

affected of total SO2 emissions). Thus, 

EPA chose to analyze the ‘‘worst-case’’ 

potential downwind air quality impacts 

from year-to-year variability above 

upwind state SO2 budgets, and EPA 

therefore believes that its findings from 

this analysis are valid for ascertaining 

the potential downwind air quality 

impacts from variation at those levels in 

both SO2 and NOX under the Transport 

Rule programs. 

Furthermore, because the state 

budgets are based directly on IPM 

modeling of electric generation when 

cost-effective emission reductions have 

been achieved, sources within each state 

should have the same incentive to meet 

that budget, on average, in any given 

year. Additional EPA analysis supports 

the claim that states would be no more 

likely to exceed 1-year variability limits 

without the 3-year limits than with the 

3-year limits. See the ‘‘Power Sector 

Variability Final Rule TSD’’ for more 

details on this statistical analysis. 

Finally, because the state budgets (and 

thus the total amount of allowances 

available) are fixed and every covered 

source must hold allowances covering 

its emissions, it is not feasible for all, or 

even many, states to repeatedly exceed 

their budgets. 

The approach calculated the standard 

deviation in state-level heat input from 

units expected to be covered by the final 

Transport Rule over an 11-year time 

period (2000 through 2010), from which 

the 95th percent confidence level was 

calculated. EPA divided this value by 

the mean to get the percentage variation 

in heat input. The two-tailed 95th 

percent confidence level is the 

equivalent of the 97.5 percent upper 

(single-tailed) confidence level. This 

approach yielded an average year-toyear heat input variability for each state, 

as a proxy for historic year-to-year 

variability in state-level EGU emissions 

while holding emission rates constant. 

The result, expressed as a percentage, 

conveys the maximum degree to which 

EGU emissions at the state level may be 

expected with 95th percent confidence 

to vary around a given target (i.e., 

budget) from year-to-year, on average, 

based on the statistical analysis of 

historic heat input over the 2000 

through 2010 time period. 

From the state-by-state variability 

calculations, EPA identified a single 

variability level (percentage) for each of 

the annual and ozone-season programs 

based on the historic variability 

measured at units in covered states on 

an annual basis and an ozone-season 

basis, respectively. In the proposal, EPA 

‘‘identified a single set of variability 

levels * * * to apply to all states in 

order to make the application of the 

variability limits straightforward rather 

than developing state-by-state 

percentage variability values’’ (75 FR 

45293). In the final rule, EPA is taking 

the straightforward approach of 

identifying a single set of variability 

levels to apply to all states because EPA 

has determined that it is reasonable to 

afford all states under the Transport 

Rule programs the extent of measured 

historic variability experienced by any 

Transport Rule state during 2000 

through 2010. In the variability analysis 

for the final rule, EPA identified 

Tennessee as having the highest 

measured historic variability of annual 

heat input of 18 percent, and Virginia as 

having the highest measured historic 

variability of ozone-season heat input of 

21 percent. Because the percentage of 

variability in Tennessee on an annual 

basis and in Virginia on an ozoneseason basis are reasonably likely to 

occur in each of the other states in the 

future, EPA believes it is appropriate to 

apply an 18 percent annual variability 

limit to all states covered by the annual 

SO2 and NOX programs and a 21 percent 

ozone-season variability limit to all 

states covered by the ozone-season NOX

program.54

EPA’s analysis of historic heat input 

variability in multiple states over the 

2000 to 2010 baseline yields a range of 

potential year-to-year variability values 

for state-level EGU emissions. As 

discussed above, any one state’s 

measured variability (in this case, from 

2000 to 2010) is due to a multiplicity of 

factors. These factors include, but are 

not limited to, variation in weather, 

variation in demand due to increased or 

decreased level of economic activity, 

variation in the portion of electric 

generation that is fossil-fuel-fired, and 

variation in the length and number of 

outages at power generation units, and 

these individual factors may sometimes 

act in concert and may other times be 

offsetting. 

The mix and levels of factors present 

in a state from year-to-year can lead to 

variation of state-level emissions above 

and below the level for the state under 

average conditions. Because the levels 

of the various factors are difficult to 

predict on a year-to-year basis for an 

individual state, the resulting variability 

in state-level emissions is difficult to 

predict. Moreover, because the electric 

generation, transmission, and 

distribution system in the eastern half of 

the U.S. is highly integrated, year-toyear variation in these factors in one 

state can cause year-to-year variability 

in state-level emissions both in that 

state and in other states on the system. 

For example, increased demand due to 

extreme weather or increased economic 

activity in one state can be met through 

increased generation and emissions in a 

number of states. 

Because these factors can vary year-toyear in every state in ways that are 

difficult to predict and can affect other 

states, EPA maintains that the maximum 

variability measured in one state for a 

discrete period (2000–2010) is 


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reasonably likely to occur in the future 

in any of the states in the region. 

Consequently, EPA believes that it is 

reasonable to use the maximum historic 

percentage variability figure as a proxy 

for the percentage variability that any of 

the states is likely to experience in the 

future. Although EPA is therefore using 

a uniform percentage figure for 

variability, EPA applies that percentage 

figure to each state-specific budget so 

that variability in tons of emissions is 

determined on a state-specific basis. 

That state-specific number is used in 

determining whether the assurance 

provisions and penalty are triggered in 

the specific state. EPA also believes that 

it is appropriate to accommodate this 

potential future variability at the state 

level if and only if it can be 

accommodated without undermining 

the programs’ beneficial impacts on 

downwind air quality that eliminate 

significant contribution to 

nonattainment or interference with 

maintenance of the NAAQS assessed in 

this rulemaking (see the ‘‘Power Sector 

Variability Final Rule TSD’’ for more 

information on this analysis). The 

Transport Rule identifies and quantifies, 

on a state-by-state basis, the emissions 

in each state that significantly 

contribute to nonattainment or interfere 

with maintenance in another state. This 

is done by analyzing specific air 

pollution linkages between each 

upwind state and each downwind 

maintenance or nonattainment receptor. 

Nonetheless, it is clear from the air 

quality analyses that the air quality 

outcome at a given downwind receptor 

is a function of the cumulative 

emissions from all upwind states and 

the receptor’s home state. Once the 

Transport Rule emission reduction 

requirements are implemented in all 

states subject to the programs, EPA’s 

analysis shows that the impact on a 

downwind receptor of any single 

upwind state’s year-to-year fluctuation 

of up to 20 percent in SO2 emissions 

would be so limited as to not disturb 

that receptor’s ability to maintain or 

attain the NAAQS analyzed in this 

rulemaking. Therefore, to the extent that 

such variability has been measured in 

historic data in any state subject to the 

Transport Rule programs, it is 

reasonable to provide for potential 

future variability in Transport Rule 

states within the scope of what EPA’s 

analysis shows to preserve downwind 

air quality gains achieved by the 

Transport Rule programs. 

The approach to establishing 

variability limits in the final rule 

modifies the approach from the 

proposed rule in two ways. First, EPA 

is applying only a percentage variability 

limit to each budget in the final rule, 

whereas the proposed rule applied the 

greater of a percentage or an absolute 

tonnage variability limit to each budget. 

EPA explained in the proposal that it 

was necessary to impose both a 

percentage and a tonnage limit due to 

the inclusion of ‘‘states with small 

numbers of units where expected 

variability would be more pronounced 

in percentage terms’’ (75 FR 45293). 

However, the states with the smallest 

numbers of units included at proposal 

(such as Connecticut and the District of 

Columbia) are not covered by any of the 

final Transport Rule’s programs. In the 

final rule’s variability analysis, 

Tennessee has the highest measured 

annual variability percentage and 

Virginia has the highest measured 

ozone-season variability percentage. 

Both of these states have a sufficient 

number of units for the percentage 

variability findings to be representative 

of variability in all of the Transport Rule 

states; therefore, it is not necessary to 

impose a tonnage limitation in the final 

rule. 

Second, EPA has expanded the 

historic baseline of the variability 

analysis to consider heat input data 

from 2000 through 2010, as compared to 

2002 through 2008 at proposal, and EPA 

has also expanded the dataset to include 

all units expected to be covered by the 

final Transport Rule’s programs. EPA 

received a number of comments that the 

proposal’s variability limits were too 

stringent in part because they relied on 

too short a historical baseline that failed 

to capture the full extent of long-run 

year-to-year variability. EPA agrees with 

these comments and believes that the 

historic baseline modification described 

above supports variability limits in the 

final rule that are a better approximation 

of future potential year-to-year 

variability in state-level EGU emissions 

around the budgets as a function of 

inherent variability in baseline statelevel EGU operations. EPA believes the 

2000 through 2010 historic baseline 

supports a more accurate approximation 

of year-to-year variability in state-level 

EGU operations than previously 

measured on a 2002 through 2008 

baseline. 

Some commenters expressed the view 

that allowing variability limits in 

addition to state budgets undermines 

the requirements of CAA section 

110(a)(2)(D)(i)(I) to eliminate significant 

contribution to nonattainment and 

interference with maintenance of the 

NAAQS in downwind states. EPA 

disagrees with these comments. As 

explained above, EPA finds that year-toyear variability is an inherent 

characteristic of power sector emissions 

whether or not such emissions are 

controlled by state budgets; the future 

year-to-year variability is a component 

of the sector’s emissions baseline before 

emission reductions are required. As 

done for proposal, EPA has analyzed the 

impact of allowing emissions from 

upwind states in a given year to rise 

above the budgets but within the 

variability limits allowed in the final 

rule. This analysis shows that emission 

fluctuations around the budgets but 

within the variability limits will not 

undermine the downwind air quality 

gains achieved by the implementation of 

the Transport Rule budgets, and 

therefore the variability limits cannot be 

said to undermine the elimination of 

significant contribution to 

nonattainment or interference with 

maintenance achieved under the 

Transport Rule programs. Based on 

historical data and projected air quality 

impacts, the Agency believes that states 

will have sufficient flexibility and room 

to operate within the final rule’s 

variability limits while addressing all 

emissions identified as significantly 

contributing to nonattainment or 

interfering with maintenance in other 

states. 

F. Variability Limits and State Emission 

Budgets: State Assurance Levels 

As explained above, EPA applied the 

variability levels on a state-by-state 

basis to calculate specific emission 

budgets with variability limits. The state 

budget plus the variability limit is also 

called the ‘‘state assurance level.’’ Table 

VI.F–1 shows final state budgets, 

variability limits, and assurance levels 

by state for SO2 emissions. Table VI.F– 

2 shows final state budgets, variability 

limits, and assurance levels by state for 

annual NOX emissions. Table VI.F–3 

shows final state budgets, variability 

limits, and assurance levels by state for 

ozone-season NOX emissions. 


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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 38,886 38,386 254,919 251,644 

Georgia .................................................... 158,527 95,231 28,535 17,142 187,062 112,373 

Illinois ....................................................... 234,889 124,123 42,280 22,342 277,169 146,465 

Indiana ..................................................... 285,424 161,111 51,376 29,000 336,800 190,111 

Iowa .......................................................... 107,085 75,184 19,275 13,533 126,360 88,717 

Kansas ..................................................... 41,528 41,528 7,475 7,475 49,003 49,003 

Kentucky .................................................. 232,662 106,284 41,879 19,131 274,541 125,415 

Maryland .................................................. 30,120 28,203 5,422 5,077 35,542 33,280 

Michigan ................................................... 229,303 143,995 41,275 25,919 270,578 169,914 

Minnesota ................................................. 41,981 41,981 7,557 7,557 49,538 49,538 

Missouri .................................................... 207,466 165,941 37,344 29,869 244,810 195,810 

Nebraska .................................................. 65,052 65,052 11,709 11,709 76,761 76,761 

New Jersey .............................................. 5,574 5,574 1,003 1,003 6,577 6,577 

New York ................................................. 27,325 18,585 4,919 3,345 32,244 21,930 

North Carolina .......................................... 136,881 57,620 24,639 10,372 161,520 67,992 

Ohio .......................................................... 310,230 137,077 55,841 24,674 366,071 161,751 

Pennsylvania ............................................ 278,651 112,021 50,157 20,164 328,808 132,185 

South Carolina ......................................... 88,620 88,620 15,952 15,952 104,572 104,572 

Tennessee ............................................... 148,150 58,833 26,667 10,590 174,817 69,423 

Texas ....................................................... 243,954 243,954 43,912 43,912 287,866 287,866 

Virginia ..................................................... 70,820 35,057 12,748 6,310 83,568 41,367 

West Virginia ............................................ 146,174 75,668 26,311 13,620 172,485 89,288 

Wisconsin ................................................. 79,480 40,126 14,306 7,223 93,786 47,349 

Note: Budgets, limits, and assurance levels apply to each state’s emissions from covered sources, as defined by this final rule, only. 

TABLE VI.F–2—STATE BUDGETS, VARIABILITY LIMITS, AND ASSURANCE LEVELS FOR ANNUAL NOX EMISSIONS

Emission budget 

(tons) 

Emission variability 

limit (tons) 

State emissions 

assurance level (tons) 

2012–2013 2014 and 

beyond 2012–2013 2014 and beyond 2012–2013 2014 and beyond 

Alabama ................................................... 72,691 71,962 13,084 12,953 85,775 84,915 

Georgia .................................................... 62,010 40,540 11,162 7,297 73,172 47,837 

Illinois ....................................................... 47,872 47,872 8,617 8,617 56,489 56,489 

Indiana ..................................................... 109,726 108,424 19,751 19,516 129,477 127,940 

Iowa .......................................................... 38,335 37,498 6,900 6,750 45,235 44,248 

Kansas ..................................................... 30,714 25,560 5,529 4,601 36,243 30,161 

Kentucky .................................................. 85,086 77,238 15,315 13,903 100,401 91,141 

Maryland .................................................. 16,633 16,574 2,994 2,983 19,627 19,557 

Michigan ................................................... 60,193 57,812 10,835 10,406 71,028 68,218 

Minnesota ................................................. 29,572 29,572 5,323 5,323 34,895 34,895 

Missouri .................................................... 52,374 48,717 9,427 8,769 61,801 57,486 

Nebraska .................................................. 26,440 26,440 4,759 4,759 31,199 31,199 

New Jersey .............................................. 7,266 7,266 1,308 1,308 8,574 8,574 

New York ................................................. 17,543 17,543 3,158 3,158 20,701 20,701 

North Carolina .......................................... 50,587 41,553 9,106 7,480 59,693 49,033 

Ohio .......................................................... 92,703 87,493 16,687 15,749 109,390 103,242 

Pennsylvania ............................................ 119,986 119,194 21,597 21,455 141,583 140,649 

South Carolina ......................................... 32,498 32,498 5,850 5,850 38,348 38,348 

Tennessee ............................................... 35,703 19,337 6,427 3,481 42,130 22,818 

Texas ....................................................... 133,595 133,595 24,047 24,047 157,642 1 57,642 

Virginia ..................................................... 33,242 33,242 5,984 5,984 39,226 39,226 

West Virginia ............................................ 59,472 54,582 10,705 9,825 70,177 64,407 

Wisconsin ................................................. 31,628 30,398 5,693 5,472 37,321 35,870 

Note: Budgets, limits, and assurance levels apply to each state’s emissions from covered sources, as defined by this final rule, only. 


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TABLE VI.F–3—STATE BUDGETS, VARIABILITY LIMITS, AND ASSURANCE LEVELS FOR OZONE-SEASON 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 ................................................... 31,746 31,499 6,667 6,615 38,413 38,114 

Arkansas .................................................. 15,037 15,037 3,158 3,158 18,195 18,195 

Florida ...................................................... 27,825 27,825 5,843 5,843 33,668 33,668 

Georgia .................................................... 27,944 18,279 5,868 3,839 33,812 22,118 

Illinois ....................................................... 21,208 21,208 4,454 4,454 25,662 25,662 

Indiana ..................................................... 46,876 46,175 9,844 9,697 56,720 55,872 

Kentucky .................................................. 36,167 32,674 7,595 6,862 43,762 39,536 

Louisiana .................................................. 13,432 13,432 2,821 2,821 16,253 16,253 

Maryland .................................................. 7,179 7,179 1,508 1,508 8,687 8,687 

Mississippi ................................................ 10,160 10,160 2,134 2,134 12,294 12,294 

New Jersey .............................................. 3,382 3,382 710 710 4,092 4,092 

New York ................................................. 8,331 8,331 1,750 1,750 10,081 10,081 

North Carolina .......................................... 22,168 18,455 4,655 3,876 26,823 22,331 

Ohio .......................................................... 40,063 37,792 8,413 7,936 48,476 45,728 

Pennsylvania ............................................ 52,201 51,912 10,962 10,902 63,163 62,814 

South Carolina ......................................... 13,909 13,909 2,921 2,921 16,830 16,830 

Tennessee ............................................... 14,908 8,016 3,131 1,683 18,039 9,699 

Texas ....................................................... 63,043 63,043 13,239 13,239 76,282 76,282 

Virginia ..................................................... 14,452 14,452 3,035 3,035 17,487 17,487 

West Virginia ............................................ 25,283 23,291 5,309 4,891 30,592 28,182 

Note: Budgets, limits, and assurance levels apply to each state’s emissions from covered sources, as defined by this final rule, only. 

See section VII.E for the discussion of 

how variability limits and state 

assurance levels are used in the 

implementation of assurance provisions 

for the air quality-assured trading 

programs. 

G. How the State Emission Reduction 

Requirements Are Consistent With 

Judicial Opinions Interpreting the Clean 

Air Act 

The methodology described in this 

notice quantifies states’ significant 

contribution to nonattainment and 

interference with maintenance in a 

manner that is consistent with the 

decisions of the DC Circuit. As 

discussed previously, the DC Circuit has 

issued two significant decisions 

addressing the requirements of 

110(a)(2)(D)(i)(I). The first opinion 

largely upheld the NOX SIP Call, 

Michigan, 213 F.3d 663, and the second 

found significant flaws in CAIR, North 

Carolina, 531 F.3d. 896. In both cases, 

the Court considered aspects of the 

methodology used by EPA to identify 

emissions that, pursuant to section 

110(a)(2)(D)(i)(I), must be eliminated 

due to their impact on air quality in 

downwind states. EPA believes that the 

methodology used in this final rule is 

consistent with both opinions and 

rectifies the flaws the North Carolina 

court identified with the methodology 

used in CAIR. The methodology used 

for this rule relies on state-specific data 

to analyze each individual state’s 

significant contribution, uses air quality 

considerations in addition to cost 

considerations to identify each state’s 

significant contribution, and gives 

independent meaning to the 

‘‘interference with maintenance’’ prong. 

This methodology is then applied in a 

reasonable manner consistent with the 

relevant judicial opinions. 

In North Carolina, the Court held that 

EPA’s approach to evaluating significant 

contribution was inadequate because, by 

evaluating only whether emission 

reductions were highly cost effective ‘‘at 

the regional level assuming a trading 

program’’, it failed to conduct the 

required state-specific analysis of 

significant contribution. See id. at 907. 

EPA, the Court concluded, ‘‘never 

measured the ‘significant contribution’ 

from sources within an individual state 

to downwind nonattainment areas.’’ Id. 

The Court did not, however, disturb the 

air-quality-based methodology used by 

EPA to identify the states with 

contributions large enough to warrant 

further consideration. 

For this rule, EPA uses a first step 

similar to that used in CAIR to identify 

the states with relatively large 

contributions. However, in contrast to 

CAIR, it then uses a state-specific 

analysis. Instead of identifying a single 

emission level that could be achieved by 

the application of highly cost effective 

controls in the region, EPA determines, 

on a state-by-state basis, what 

reductions could effectively be achieved 

by sources in each state. EPA’s new 

approach does not, as the CAIR 

methodology did, establish a regional 

cap on emissions that is then divided 

into state budgets that set the emission 

reduction requirements for each state. 

Instead, EPA develops, for each covered 

state, emission budgets based on the 

reductions achievable at a particular 

cost per ton in that particular state, 

taking into account the need to ensure 

reliability of the electric generating 

system. The selected cost/ton levels 

reflect consideration of both cost factors 

and air quality factors including the 

estimated impact of upwind states’ 

emissions on each downwind receptor. 

In addition, in developing this 

approach, EPA was guided by the 

Court’s holdings regarding the use of 

cost to identify significant contribution. 

Specifically, the Court held in Michigan 

that EPA could ‘‘in selecting the 

‘significant’ level of ‘contribution’ under 

section 110(a)(2)(D)(i)(I), choose a level 

corresponding to a certain reduction in 

cost.’’ North Carolina, 531 F.3d at 917 

(citing Michigan, 213 F.3d at 676–77). 

This holding also supported the Court’s 

conclusion in Michigan that it was 

acceptable for EPA to apply a uniform 

cost-criterion across states. See 

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

case, the Court rejected EPA’s analysis, 

not because it relied on cost 

considerations to identify significant 

contribution, but because it found that 

EPA had failed to draw the significant 

contribution line at all. See North 

Carolina, 531 F.3d at 918 (‘‘* * * here 

EPA did not draw the [significant 

contribution] line at all. It simply 

verified sources could meet the SO2

caps with controls EPA dubbed ‘highly 


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55Alabama, Arkansas, Florida, Georgia, Illinois, 

Indiana, Iowa, Kansas, Kentucky, Louisiana, 

Maryland, Michigan, Minnesota, Mississippi, 

Nebraska, New Jersey, New York, North Carolina, 

Ohio, Pennsylvania, South Carolina, Tennessee, 

Texas, Virginia, West Virginia, and Wisconsin. As 

discussed in section III, in a separate notice, EPA 

is proposing to include Iowa, Kansas, Michigan, 

Missouri, Oklahoma, and Wisconsin in the ozoneseason NOX requirements. 

cost-effective.’ ’’). The holdings in 

Michigan regarding the use of cost and 

a uniform cost-criterion across states 

were left undisturbed. See, e.g., North 

Carolina, 531 F.3d at 917 (explaining 

that in Michigan the Court held that 

‘‘EPA may ‘after [a state’s] reduction of 

all [it] could * * * cost-effectively 

eliminate[],’ consider ‘any remaining 

contribution insignificant’’). In fact, the 

Court acknowledged that, based on the 

Michigan holdings, the measurement of 

a state’s significant contribution need 

not ‘‘directly correlate with each state’s 

individualized air quality impact on 

downwind nonattainment relative to 

other upwind states.’’ North Carolina, 

531 F.3d at 908. 

For these reasons, EPA determined 

that it was appropriate in this 

rulemaking to consider the cost of 

controls to determine what portion of a 

state’s contribution is its ‘‘significant 

contribution.’’ However, EPA also 

heeded the North Carolina Court’s 

warning that ‘‘EPA can’t just pick a cost 

for a region, and deem ‘significant’ any 

emissions that sources can eliminate 

more cheaply.’’ North Carolina,, 531 

F.3d at 918. Thus, in this rulemaking, 

EPA departs from the practice used in 

the NOX SIP Call and in CAIR of 

evaluating, based solely on the cost of 

control required in other regulatory 

environments, what controls would be 

considered ‘‘highly-cost-effective.’’ 

Instead, as part of its determination of 

a reasonable cost per ton for upwind 

state control, EPA evaluates the air 

quality impact of reductions at various 

cost levels and considers the 

reasonableness of possible cost 

thresholds as part of a multi-factor 

analysis. 

In addition, the methodology used in 

this rulemaking gives independent 

meaning to the interfere with 

maintenance prong of section 

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

Court concluded that CAIR improperly 

‘‘gave no independent significance to 

the ‘interfere with maintenance’ prong 

of section 110(a)(2)(D)(i)(I) to separately 

identify upwind sources interfering 

with downwind maintenance.’’ North 

Carolina, 531 F.3d at 910. EPA rectified 

this flaw in this rulemaking by 

separately identifying downwind 

‘‘nonattainment sites’’ and downwind 

‘‘maintenance sites.’’ EPA decided to 

consider upwind states’ contributions 

not only to sites that EPA projected 

would be in nonattainment, but also to 

sites that, based on the historic 

variability of their emissions, EPA 

determined may have difficulty 

maintaining the relevant standards. The 

specific mechanism EPA used to 

implement this approach is described in 

detail in section V.C, previously. For 

annual PM2.5, this approach identified 

16 maintenance sites in addition to the 

32 nonattainment sites identified in the 

analysis of nonattainment receptors. For 

24-hour PM2.5 this approach identified 

38 maintenance sites in addition to the 

92 nonattainment sites identified in the 

analysis of nonattainment receptors. For 

ozone it identified 16 maintenance sites 

in addition to the 11 ozone 

nonattainment sites identified. 

EPA applied this methodology using 

available information and data to 

measure the emissions from states in the 

eastern United States that significantly 

contribute to nonattainment or interfere 

with maintenance in downwind areas 

with regard to the 1997 and 2006 PM2.5

NAAQS and the 1997 ozone NAAQS. 

Although EPA has not completely 

quantified the total significant 

contribution of these states with regard 

to all existing standards, EPA has 

determined, on a 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 significant contribution to 

nonattainment and interference with 

maintenance. 

VII. FIP Program Structure To Achieve 

Reductions 

A. Overview of Air Quality-Assured 

Trading Programs 

EPA is finalizing an air qualityassured trading remedy that is 

substantially similar to the preferred 

trading remedy presented in the 

proposal. Key differences from the 

preferred trading remedy in the 

proposal include: 

• Recalculated state budgets and 

variability limits (i.e., state assurance 

levels) based on updated modeling; 

• Simplified variability limits for 

1-year application only; 

• Revised allocation methodology for 

existing and new units and revised new 

unit set-asides for new units in 

Transport Rule states and new units 

potentially locating in Indian country; 

• Changed start of assurance 

provisions to 2012 and increased 

assurance provision penalties; and 

• Removed opt-in provisions. 

In the final rule, as in the proposed 

rule, EPA is promulgating FIPS to 

require SO2 and NOX reductions from 

power plants in jurisdictions 55 that 

contribute significantly to 

nonattainment in, or interfere with 

maintenance by, a downwind area with 

respect to the 1997 ozone NAAQS, the 

1997 annual PM2.5 NAAQS, and/or the 

2006 24-hour PM2.5 NAAQS. These FIPs 

establish state-specific emission control 

requirements using state budgets 

starting in 2012, with a second phase of 

SO2 reductions in some states in 2014. 

Section IV explains EPA’s authority to 

issue FIPs. 

The air quality-assured trading 

remedy in the final rule allows 

interstate trading to account for 

variability in the electricity sector, but 

also includes assurance provisions to 

ensure that the necessary emission 

reductions occur within each covered 

state. The assurance provisions restrict 

EGU emissions within each state to the 

state’s budget plus the variability limit 

and ensure that every state is making 

reductions to eliminate the significant 

contribution to nonattainment and 

interference with maintenance that EPA 

has identified. While EPA proposed to 

impose these assurance provisions 

starting in 2014, the final rule 

implements these provisions starting in 

2012 (see section VII.E of this 

preamble). Additionally, the final FIPs 

include penalty provisions adequate to 

ensure that the state budget with the 

variability limit will not be exceeded. 

In the final rule, as in the preferred 

trading remedy discussed in the 

proposed rule, state-specific emission 

budgets without the variability limits 

are used to determine the number of 

emission allowances allocated to 

sources in each state. An EGU source is 

required to hold one SO2 or one NOX

allowance, respectively, for every ton of 

SO2 or NOX emitted during the control 

period. Banking of allowances for use or 

trading in future years is allowed. 

The final rule establishes four 

interstate trading programs, each 

starting in 2012: two for annual SO2, 

one for annual NOX, and one for ozoneseason 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 


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the SO2 trading program. A source in a 

Group 2 state can only use SO2

allowances allocated to Group 2 states 

for compliance with the SO2 trading 

program. For compliance in the annual 

NOX and ozone-season NOX trading 

programs respectively, sources may use 

annual NOX and ozone-season NOX

allowances allocated for any state, even 

if that state is in a different group for 

SO2 than the source’s state. Four sets of 

new emission allowances based on the 

new state-specific budgets without 

variability are allocated to sources, one 

set for each of the four trading programs. 

Each state has the option of replacing 

these FIPs with state rules. EPA believes 

that this remedy meets the concerns 

raised by the Court in the 2008 North 

Carolina decisions which remanded 

CAIR to EPA. 

In the proposed rule, EPA took 

comment on all aspects of the preferred 

trading remedy and on two alternative 

regulatory options: (1) intrastate trading; 

and (2) direct control. EPA also took 

comment on a trading ratios approach. 

Comments on the Preferred Trading 

Remedy: The great majority of public 

comments supported the preferred 

trading remedy. Most of these 

commenters voiced their support for the 

broadest possible trading mechanism 

because it allows for the most costeffective implementation of any 

emission controls. Commenters noted 

that flexibility is always needed in the 

early years of new programs. Further, 

commenters favoring the preferred 

remedy agreed with EPA that, by using 

state-specific control budgets and 

allowing for interstate trading, the 

preferred remedy provided electricity 

generators the flexibility to undertake 

the most cost-effective reductions while 

assuring that the resulting reductions 

occur within the individual states. 

Some commenters that supported the 

preferred remedy felt that, while not 

ideal, the interstate trading remedy was 

preferable to the alternative options of 

intrastate trading or direct control. 

Many commenters that supported the 

preferred remedy felt that the intrastate 

trading remedy and direct control 

remedy options offer minimal flexibility 

from a compliance perspective. They 

stated that this lack of flexibility would 

unnecessarily increase the cost of 

emission reductions. 

Other commenters who generally 

support the preferred remedy cited 

concerns about the level of complexity 

in the assurance provisions. One 

commenter surmised that the preferred 

option creates significant risk where a 

company could unexpectedly find itself 

in a noncompliance situation due to the 

after-the-fact variability analysis. 

Another said that the rule’s features 

needlessly reduce the system’s 

efficiency and increase complexity. 

These commenters generally preferred 

unlimited trading, noting that EPA has 

proven success with Title IV, the NOX

SIP Call, and CAIR unlimited interstate 

trading programs and that allowing 

unrestricted interstate trading would 

increase flexibility to meet reduction 

goals and minimize increases in power 

costs. 

EPA is finalizing the preferred trading 

remedy for the following reasons. EPA 

believes this approach is the most costeffective and practical way to comply 

with the Court decision in North 

Carolina to ensure that all emissions in 

a given state that EPA has identified as 

significantly contributing to downwind 

nonattainment or interfering with 

maintenance are eliminated. The vast 

majority of public commenters agree. In 

addition, this approach provides the 

most flexibility for sources while 

meeting the Clean Air Act requirements 

and protecting public health. As a 

result, potential innovations and 

resulting cost savings are more likely to 

be found and implemented. Based on 

historical experience (see the Transport 

Rule proposal, 75 FR 45315), EPA has 

shown that the results offered by a 

flexible trading approach (e.g., flexible 

compliance choices, incentives to 

reduce emissions early and in the 

highest emitting areas, 100 percent 

compliance with requirements) are 

substantial. A large number of 

commenters have corroborated this 

assessment. As summarized in the 

proposal, EPA believes that the 

preferred trading remedy will allow 

source owners to choose among several 

compliance options to achieve required 

emission reductions in the most costeffective manner, such as installing 

controls, changing fuels, reducing 

utilization, buying allowances, or any 

combination of these actions. Interstate 

trading with assurance provisions 

provides additional regulatory 

flexibility that promotes the power 

sector’s ability to operate as an 

integrated, interstate system and to 

provide electric reliability. 

Comments on Intrastate Trading: A 

few commenters favored the first 

alternative, intrastate trading. One 

commenter who favored intrastate 

trading stated that many power plants 

have avoided investment in pollution 

controls by buying allowances from 

other plants, affecting local air quality 

improvement. EPA notes that this 

Transport Rule aims to address 

emissions from one state that 

significantly contribute to 

nonattainment or interfere with 

maintenance of certain NAAQS in other 

states. Local air quality issues are 

directly addressed by other provisions 

in the Clean Air Act. 

Several commenters raised concerns 

about the intrastate trading approach. 

Some stated, as EPA noted in the 

proposal, that the intrastate trading 

option would be more resource 

intensive, more complex, less flexible, 

and potentially more susceptible to 

market manipulation than the other 

options. In addition, some commenters 

felt that this alternative would provide 

less flexibility to ensure electric 

reliability than the preferred approach, 

resulting in greater private costs to the 

power sector and greater social costs for 

consumers. 

EPA is not finalizing the intrastate 

trading option for the following reasons. 

As EPA expressed in the proposal and 

as commenters have agreed, the 

intrastate trading option would be more 

resource intensive (both for EPA and for 

sources), more complex, less flexible, 

and potentially more susceptible to 

market manipulation than the preferred 

trading approach that EPA is finalizing. 

The intrastate trading option would be 

more costly and less transparent due to 

the large number of trading programs 

that would be operated simultaneously 

and the large number of annual auctions 

that would be held every year to address 

the issues of market power within 

states. This option would also result in 

a greater burden for participants 

operating EGUs in multiple states. 

Comments on Direct Control Option: 

Several commenters favored the second 

alternative, direct control. One 

commenter stated that direct control— 

allowing no trading—was the option 

best aligned with the 2008 Court 

decisions. EPA disagrees with this 

comment for the reasons given below 

and because, as explained in this rule, 

EPA believes the air quality-assured 

trading remedy finalized today is 

consistent with the decisions of the DC 

Circuit in North Carolina. 

Some commenters, who support 

direct control, voiced concerns that the 

other emission trading approaches 

would disadvantage poor and minority 

communities or allow increased 

emission impacts in neighborhoods near 

power plants. EPA notes that a direct 

control approach would not require 

controls on all plants in a state, but only 

on a sufficient number to address the 

transport requirements under section 

110(a)(2)(d)(i)(I) that this rule addresses, 

and therefore would not necessarily 

mandate controls on each neighborhood 

power plant. 

In addition, EPA has conducted an 

analysis of the effects of the Transport 


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56See 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 

Rule on environmental justice and other 

vulnerable communities. We concluded 

that, similar to our experience with the 

Acid Rain Program,56 many 

environmental justice communities are 

expected to see large health benefits, 

and none are expected to experience 

any disbenefits, from implementing an 

air quality-assured trading program. The 

results of this analysis are presented in 

section XII of this preamble and Chapter 

5 of the RIA for this rule. In addition, 

the CAA provides flexibility for state 

and local authorities to impose stricter 

limits on sources to address specific 

local air quality concerns. Such limits 

are independent of the requirements in 

this rule, and compliance with 

Transport Rule requirements in no way 

excuses a source from complying with 

other CAA or state law requirements. 

Several commenters raised concerns 

with the direct control approach. One 

commenter felt that issues with 

electricity market reliability could occur 

during high electricity demand periods 

if sources ceased operations due to 

approaching their emission rate 

limitations under a direct control 

remedy. Another commenter was 

concerned that applying emission rates 

under a direct control remedy to small 

municipal units would cause 

disproportionate impacts on power 

plants where pollution control is more 

expensive. Other commenters cited 

concerns that EPA’s proposed withinstate 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 air quality-assured 

trading remedy. EPA analysis indicates 

that it is not necessary to implement a 

direct control approach in order to 

protect vulnerable and sensitive 

populations or environmental justice 

communities. Also, the direct control 

approach would result in fewer 

compliance options because a direct 

control approach would directly 

regulate individual sources by setting 

unit-level emission rate limits. This lack 

of flexibility could lead to potential 

increases in reliability risks in the 

electric power system and fewer 

opportunities for potential technological 

innovations that reduce emissions 

further and/or lower costs. For these 

reasons, EPA believes that this approach 

is inferior to the air quality-assured 

trading remedy. 

Other Comments: A handful of 

commenters mentioned the trading 

ratios approach, though none favored it 

as a viable alternative. One commenter 

said the trading ratios approach was not 

consistent with CAA section 

110(a)(2)(D) requirements that 

reductions in emissions occur in 

particular geographic locations. Other 

commenters agreed that it was 

administratively unworkable and would 

be difficult to implement due to the 

complexity and variety of 

meteorological conditions. EPA 

generally concurs with the commenters. 

In the proposal, EPA noted that it would 

not be possible under this approach, as 

contemplated, to include enforceable 

legal requirements to ensure that a 

specific state’s emissions remain below 

a specified level or to ensure that a 

specific amount of reductions occur 

within a particular state. EPA 

specifically requested comment on 

whether a ratios trading program could 

be designed to provide such legal 

assurances. Of the few comments 

received, none offered such a solution. 

For these reasons, EPA is not finalizing 

this approach. 

Some commenters offered additional 

suggestions, such as: unrestricted 

trading; using different authorities in 

the CAA to address interstate transport 

such as section 110(k)(5) and section 

126; and an approach that would 

replace the assurance provisions by a 

system using both emission allowances 

usable (as well as bankable) in any state 

and assurance allowances usable (but 

not bankable) in only the state for which 

they would be issued. While EPA 

appreciates the thoughtful and 

constructive comments, we did not find 

any of these suggestions improved our 

ability to address interstate transport 

under CAA section 110(a)(2)(D)(i)(I), in 

line with the Court decision, in an 

administratively practical way. 

Several commenters liked the idea of 

establishing unit-by-unit short-term and 

long-term performance standards/ 

emission rates but suggested adding an 

overlaid cap and trade program. EPA 

believes the air quality-assured trading 

remedy finalized today is consistent 

with the decisions of the Court in North 

Carolina and will ensure the reductions 

necessary to meet statutory 

requirements. 

For the 2012–2013 period, EPA took 

comment on whether the assurance 

provisions are needed, since the statespecific budgets would be based on 

known air pollution controls and the 

penalty provisions would be adequate to 

ensure that the budget, including a 

variability limit, would not be exceeded. 

Further, EPA proposed to use two 

variability limits: a 1-year limit, based 

on the year-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 plus the variability 

limitation in order to comply with the 

Court’s opinion. Further, commenters 

stated that the 3-year variability limit 

increased costs and unnecessarily 

complicated the trading programs. As 

explained in section VI.E.2, EPA is 

finalizing the 1-year variability limit 

starting in 2012, but not the 3-year limit. 

B. Applicability 

The applicability provisions in the 

final rule are, except as discussed 

herein, essentially the same as in the 

proposed rules and for each of the 

Transport Rule trading programs. 

Under the general applicability 

provisions of the proposed rule, the 

Transport Rule trading programs would 

cover fossil-fuel-fired boilers and 

combustion turbines serving—on any 

day starting November 15, 1990 or 

later—an electrical generator with a 

nameplate capacity exceeding 25 MWe 

and producing power for sale, with the 

exception of certain cogeneration units 

and solid waste incineration units. 

EPA requested comment on whether a 

more recent year should be used 

instead. The proposed use of the 

November 15, 1990 date was consistent 

with the use of 1990 as the beginning of 

the historical period for which owners 

and operators would generally be 

required to have information about their 

units for purposes of determining 

whether the units were covered by the 

Transport Rule trading programs. 

Because unit information is generally 

compiled and retained on a calendar 

year basis, EPA believes that, for the 

general applicability provisions, it is 

preferable to use January 1, rather than 

November 15. In determining which 


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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 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-fuelfired’’ unit as one that combusts any 

amount of fossil fuel in 2005 or later. 

EPA notes that the final Transport 

Rule allows a state to submit a SIP 

revision (an abbreviated or full SIP) 

under which the state may—in addition 

to making certain types of changes 

concerning allowance allocations in the 

Transport Rule trading programs— 

expand the general applicability 

provisions of the Transport Rule NOX

Ozone Season Trading Program to cover 

fossil-fuel-fired boilers and combustion 

turbines serving—at any time starting 

January 1, 2005 or later— a generator 

with a nameplate capacity as low as 15 

MWe producing power for sale. The 

exemptions, discussed below, for 

cogeneration units and solid waste 

incineration units still will continue to 

apply. 

Cogeneration unit exemption. Under 

the final rule (as well as the proposed 

rule) certain cogeneration units or solid 

waste incinerators are exempt from the 

FIP requirements. In particular, the final 

rule includes an exemption for a unit 

that qualifies as a cogeneration unit 

throughout the later of 2005 or the first 

12 months during which the unit first 

produces electricity and continues to 

qualify through each calendar year 

ending after the later of 2005 or that 12- 

month period and that meets the 

limitation on electricity sales to the grid. 

In order to meet the definition of 

‘‘cogeneration unit’’ in the final rules, a 

unit (i.e., a fossil-fuel-fired boiler or 

combustion turbine) must be a toppingcycle or bottoming-cycle that operates as 

part of a ‘‘cogeneration system,’’ which 

is defined as an integrated group of 

equipment at a source (including a 

boiler, or combustion turbine, and a 

steam turbine generator) designed to 

produce useful thermal energy for 

industrial, commercial, heating, or 

cooling purposes and electricity through 

the sequential use of energy. A toppingcycle unit is a unit where the sequential 

use of energy results in production of 

useful power first and then, through use 

of reject heat from such production, in 

production of useful thermal energy. A 

bottoming-cycle unit is a unit where the 

sequential use of energy results in 

production of useful thermal energy first 

and then, through use of reject heat from 

such production, in production of 

useful power. In order to qualify as a 

cogeneration unit, a unit also must meet 

certain efficiency and operating 

standards. 

In the proposed rule, a unit would 

have to qualify as a cogeneration unit 

and meet the limitation on electricity 

sales starting the later of 1990 or the 

year when the unit begins operating. 

EPA requested comment on whether a 

more recent year should be used. For 

the reasons discussed above concerning 

the reference year used in the general 

applicability provisions and in order to 

have a consistent reference year in all 

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. Consequently, the final 

rule provides that the requirements to 

qualify as a cogeneration unit and to 

meet the electricity sales limitation start 

no earlier than 2005. 

In the final rule, EPA also clarifies 

that the electricity sales limitation 

under the exemption is applied in the 

same way whether a unit serves only 

one generator or serves more than one 

generator. In both cases, the total 

amount of electricity produced annually 

by a unit and sold to the grid cannot 

exceed the greater of one-third of the 

unit’s potential electric output capacity 

or 219,000 MWhr. This is consistent 

with the approach taken in the Acid 

Rain Program (40 CFR 72.7(b)(4)), where 

the cogeneration unit exemption 

originated. EPA believes that this 

clarification is needed to ensure that a 

unit serving, for example, two 

generators would not have a limit on 

sales of electricity to the grid that would 

be different (i.e., twice as high) from the 

limit for a unit serving only one 

generator with the same total nameplate 

capacity as the first unit’s two 

generators. 

EPA also took comment on whether 

efficiency standards should be applied 

on a system-wide basis to bottomingcycle units (where useful thermal 

energy is produced before useful power 

is produced), as they are for toppingcycle 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 a year, the unit 

would not produce any useful thermal 


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energy or useful power and therefore 

could not meet the minimum output 

requirements in the operating and 

efficiency standards, but the unit also 

would not have any emissions. For 

these reasons, the final rule expressly 

provides that the operating and 

efficiency standards do not have to be 

met for a calendar year throughout 

which a unit did not operate at all. 

Solid waste incineration unit 

exemption. The final rule also includes 

an exemption for a unit that qualifies as 

a solid waste incineration unit during 

the later of 2005 or the first 12 months 

during which the unit first produces 

electricity, that continues to qualify 

throughout each calendar year ending 

after the later of 2005 or that 12-month 

period each year thereafter, and that 

meets the limitation on fossil-fuel use. 

In contrast, the exemption for solid 

waste incineration units in the proposed 

rule distinguished between units 

commencing operation before January 1, 

1985 and those commencing operation 

on or after that date. A unit commencing 

operation before January 1, 1985 would 

be exempt if it qualified as a solid waste 

incineration unit starting the later of 

1990 or the year when it began 

producing electricity and its average 

annual fuel consumption of non-fossil 

fuels exceeded 80 percent of total heat 

input during 1985–1987 and during any 

three consecutive calendar years after 

1990. A unit commencing operation on 

or after January 1, 1985 would be 

exempt if it qualified as a solid waste 

incineration unit starting the later of 

1990 or the year when it began 

producing electricity and its average 

annual fuel consumption of non-fossil 

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 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 throughout 

each calendar year ending after the later 

of 2005 or that 12-month period, and 

must meet the limitation on fossil-fuel 

use on a 3-year average basis during the 

first 3 years of operation starting no 

earlier than 2005 and every 3 years of 

operation thereafter. 

Opt-in units. EPA is not finalizing the 

opt-in provisions that were discussed in 

the Transport Rule proposal. EPA 

proposed opt-in provisions to allow 

non-covered units to voluntarily opt in 

to any of the proposed Transport Rule 

trading programs and receive allocations 

reflecting 70 percent of the unit’s 

emissions before opting in. These 

allowances were above the state-specific 

budgets developed under the Transport 

Rule to eliminate a state’s significant 

contribution to nonattainment and 

interference with maintenance. In 

theory, an opt-in unit that makes 

reductions below its baseline and sells 

the freed-up allowances is effectively 

substituting its new, lower-cost 

reductions for higher-cost reductions 

otherwise required by a covered EGU, 

with the result that the state’s 

significant contribution is still 

eliminated but at a lower total program 

cost. 

EPA notes that theoretical benefits 

anticipated from allowing opt-ins did 

not materialize in prior trading 

programs with opt-in provisions. The 

Acid Rain Program has about 23 opt in 

units; the NOX Budget Trading Program 

had five opt-in units; and no units opted 

into the CAIR programs. As a group, 

these opt-in units neither eased the 

achievement of required emission 

reductions in past trading programs, nor 

reduced overall program costs. 

In the proposal, EPA requested 

comment on the opt-in provisions, 

specifically regarding: What are the 

benefits of and concerns about 

including opt-in provisions; how to 

ensure units are not credited for 

emission reductions the units would 

have made anyway; whether the 

proposed 30 percent reduction (i.e., 

application of the 70 percent multiplier 

to baseline emissions) or some other 

percentage reduction, or no reduction, 

should be applied to the baseline 

emission rate used in determining 

allocations; and whether any additional 

percentage reduction (such as 45 

percent) should be applied to SO2

Group 1 opt-in units in Phase II to 

reflect the stricter limits for covered 

units. 

Some commenters argued that 

increasing the Transport Rule budgets 

for opt-ins would undermine the goal of 

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

eliminate a state’s significant 

contribution to nonattainment and 

interference with maintenance. One 

commenter stated that it does not favor 

allowing sources that are not subject to 

the emission reduction requirements to 

be issued allowances that would 

increase the overall state emission 

budgets, due to the 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 nonEGUs to choose voluntarily to be 

covered by opting in. 

As mentioned previously, the final 

Transport Rule does not include any 

opt-in provisions either in the FIPs or in 

the provisions allowing modification or 

replacement of the FIPs through 

submission of trading program 

provisions in SIPs. EPA has several 

reasons for not adopting provisions to 

allow opt-in units. First, as mentioned 

above, historically, very few units have 

opted in. As of 2010, 28 units out of 

more than 4,700 covered units (23 units 

out of a total of about 3,600 covered 

units in the Acid Rain Program and 5 

units out of a total of about 2,600 

covered units in the NOX SIP Call) have 

opted in to EPA trading programs over 

the past 15 years. In the Acid Rain 

Program, 3 of the units opted in and 


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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 nonattainment and 

interference with maintenance 

identified by EPA is addressed. If EPA 

were to allow opt-ins, and if any opt-in 

unit were to receive an allocation of 

allowances for emissions that would be 

reduced even if the units did not opt in, 

then the inclusion of that opt-in unit in 

the program would allow the sources 

covered by the Transport Rule to emit 

in excess of the budget plus variability 

limit with no new, offsetting reduction 

in emissions. For example, after a unit 

would opt in, process or fuel changes 

made for economic reasons (rather than 

due to any regulatory requirements), or 

installation of new emission controls or 

fuel-switching conducted to meet 

future, non-Transport Rule regulatory 

requirements, could result in emission 

reductions that would have occurred 

‘‘anyway’’ (i.e., even if the unit had not 

opted in), and the opt-in unit would be 

allocated allowances for the portion of 

its baseline emissions that would be 

removed by these ‘‘anyway’’ reductions. 

Allocations above the cap to opt-in units 

making ‘‘anyway’’ emission reductions 

would convert these reductions into 

extra allowances (i.e., authorizations to 

emit) usable by covered EGUs to meet 

their requirements to hold allowances 

for emissions. Because the extra EGU 

emissions authorized by these extra 

allowances would not be offset by any 

new emission reductions by the opt-in 

units, this could threaten a state’s ability 

to eliminate the significant contribution 

to nonattainment and interference with 

maintenance identified by EPA in the 

final rule. Also, opt-in units, which are 

allocated allowances outside the state 

budget for covered units, could increase 

the possibility that a state’s total 

emissions would exceed the state 

budget plus variability and thus that the 

assurance provisions would be 

triggered. 

This problem of allocating allowances 

for emissions that would have been 

reduced anyway is illustrated by the 

recent promulgation of the final rule, 

National Emission Standards for 

Hazardous Air Pollutants for Major 

Sources: Industrial, Commercial, and 

Institutional Boilers and Process Heaters 

(76 FR 15608 (March 21, 2011)) (‘‘final 

Boiler MACT rule’’), which requires 

certain industrial, commercial, and 

institutional boilers to meet maximum 

achievable control technology (MACT) 

standards for emissions of specified 

hazardous air pollutants, such as 

hydrogen chloride (HCL) and mercury 

(Hg). Some of the control technologies 

that can be used to meet these standards 

will also provide significant reductions 

of SO2 emissions. For example, a boiler 

may use a wet scrubber or the 

combination of a dry sorbent injection 

system and a fabric filter (among other 

options) to meet the applicable HCL 

standard or may use a wet scrubber or 

a combination of activated carbon 

injection and a fabric filter (among other 

options) to meet the applicable Hg 

standard. See 76 FR 15614 (describing 

testing and compliance requirements 

when such controls are used to meet 

these standards); and Memo from Brian 

Shrager to Amanda Singleton and 

Graham Gibson, Revised Methodology 

for Estimating Cost and Emissions 

Impacts for Industrial, Commercial and 

Institutional Boilers and Process Heaters 

National Emissions Standards for 

Hazardous Air Pollutants—Major 

Source (February 11, 2011), Document 

ID EPA–HQ–OAR–2009–0491–4036 

(section 3.1, describing control options 

for HCL and Hg control). In fact, EPA 

estimated that the new standards would 

result in emission reductions of not only 

the hazardous air pollutants directly 

subject to the standards, but also in 

other air pollutants such as SO2.

Specifically, EPA projected that 

compliance with the final Boiler MACT 

rule standards will result in about 

431,000 tons of annual SO2 reductions 

from existing boilers subject to the final 

Boiler MACT rule. This will comprise 

on average about a 46 percent reduction 

in SO2 emissions for this group of 

boilers. Coal- and oil-fired boilers— 

which are the boilers likely to have the 

most uncontrolled SO2 emissions and so 

would be the most likely types of units 

to consider opting into the Transport 

Rule trading programs if opting-in were 

allowed—are projected to reduce about 

409,000 tons of annual SO2 as a result 

of complying with the final Boiler 

MACT rule, or about a 50 percent 

reduction in SO2 emissions. See Memo 

from Brian Shrager to Amanda 

Singleton and Graham Gibson, 

Appendix B–1, (where column CE 

represents baseline SO2 emissions and 

column CH represents SO2 reductions 

resulting from the final Boiler MACT 

rule compliance). The amount of 

offsetting SO2 increases projected to 

result from final Boiler MACT rule 

compliance, e.g., from additional fuel 

being combusted to generate electricity 

to operate emission controls, is minor. 

See 76 FR 15651 (Table 4) and 15653 

(showing projected total SO2 reductions 

for all boilers and process heaters of 

about 442,000 tons and net SO2

reductions of about 440,000 tons). 

Consequently, a boiler subject to the 

final Boiler MACT rule may install a 

wet acid gas scrubber or a bag house in 

order to meet the HCL or Hg standard 

applicable to boilers under the final 

Boiler MACT rule and thereby achieve 

SO2 emission reductions. If that boiler 

were to opt in to one of the Transport 

Rule SO2 trading programs during the 

year before installing these controls to 

comply with the final Boiler MACT 

rule, then the boiler would be allocated 

allowances for the unit’s current tons of 

SO2 emissions and would not need to 

use these allowances for compliance 

under the Transport Rule once the final 

Boiler MACT-related controls were 

installed. The allowances allocated to 

the boiler would be additional 

allowances above the Transport Rule 

trading budget for the state where the 

boiler was located. As a result, the 

boiler would have freed-up allowances 

above the state trading budget that 

represent reductions that the boiler 

would have made anyway (i.e., even if 

the boiler had not opted 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 


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57For the annual programs, sources are required 

to have, by March 1, 2013, sufficient allowances in 

their accounts to cover their 2012 emissions. For 

the ozone-season program, they must have 

allowances in their accounts by December 1, 2012 

to cover 2012 ozone-season emissions. The state 

budgets which determine the number of allowances 

allocated to units in each state become more 

stringent for some states in 2014. 

58Section 172(a)(2) of the Clean Air Act provides 

that the attainment dates for areas designated 

nonattainment with a NAAQS shall be the date by 

which attainment can be achieved as expeditiously 

as practicable, but no later than 5 years from the 

date of designation. This section also allows the 

Administrator to extend the attainment date to the 

extent she determines appropriate, for a period no 

greater than 10 years from the date of designation 

as nonattainment, considering the severity of 

nonattainment and the availability and feasibility of 

pollution control measures. Designations for the 

1997 PM2.5 NAAQS became effective on April 5, 

2005. Designations for the 2006 24-hour PM2.5

NAAQS became effective on December 14, 2009. 

compromise the integrity of the EGU 

emission reductions. 

For the reasons explained above, EPA 

agrees with the latter commenter. 

Further, EPA notes that none of the 

commenters supporting adoption of the 

opt-in provisions suggested any revision 

to the proposed opt-in provisions that 

would address this problem. While the 

proposed opt-in provisions would limit 

an opt-in unit’s allocation for a control 

period by calculating the allocation 

using the lesser of the unit’s pre-opt-in 

SO2 emission rate or the most stringent 

SO2 emission rate applicable in that 

control period, this would not address 

SO2 rate reductions that are not directly 

required by the final Boiler MACT rule 

but that are a secondary result of using 

and operating certain emission controls 

installed to comply with the HCL or Hg 

standards under the final Boiler MACT 

rule. Because the secondary SO2

reductions will vary depending on the 

type of controls installed and on the 

extent to which the controls are used, 

and a boiler may use a combination of 

emission controls and other approaches 

to reduce HCL or Hg emissions (such as 

fuel switching), EPA believes that it is 

highly unlikely that opt-in provisions 

could prevent allocation for ‘‘anyway’’ 

emission reductions resulting from 

compliance with the final Boiler MACT 

rule. EPA therefore believes that the 

final Boiler MACT rule provides a 

concrete example of why adoption of 

opt-in provisions could undermine the 

rule’s objective of addressing emissions 

in each state that significantly 

contribute to nonattainment or interfere 

with maintenance in other states. EPA 

notes that the final Boiler MACT rule, 

of course, is simply one example of how 

allocations for ‘‘anyway’’ reductions 

could occur and undermine the 

statutory requirements of the Transport 

Rule. 

C. Compliance Deadlines 

1. Alignment With NAAQS Attainment 

Deadlines 

The compliance dates in the final 

Transport Rule are aligned with the 

attainment deadlines for the relevant 

NAAQS and consistent with the charges 

given to EPA by the Court in North 

Carolina. EPA proposed to require, and 

the final rule requires, compliance by 

2014 with an initial phase of reductions 

in 2012.57 Sources are required to 

comply with annual SO2 and NOX

requirements by January 1, 2012 and 

January 1, 2014 for the first and second 

phases, respectively. Similarly, sources 

are required to comply with ozoneseason NOX requirements by May 1, 

2012, and by May 1, 2014. In selecting 

these dates, EPA was mindful of the 

NAAQS attainment deadlines which 

require reductions as expeditiously as 

practicable and no later than specified 

dates (see 42 U.S.C. 7502(a)(2)(A) 

(general attainment dates); 42 U.S.C. 

7511(a)(1) (attainment dates for ozone 

nonattainment areas)), and also mindful 

of the court’s instruction to ‘‘decide 

what date, whether 2015 or earlier, is as 

expeditious as practicable for states to 

eliminate their significant contributions 

to downwind nonattainment.’’ North 

Carolina, 531 F.3d at 930. 

1997 PM2.5 NAAQS Attainment 

Deadlines. For all areas designated as 

nonattainment with respect to the 1997 

PM2.5 NAAQS, the deadline for attaining 

that standard is as expeditious as 

practicable but no later than April 2010 

(5 years after designation), with a 

possible extension to no later than April 

2015 (10 years after designation).58

Many areas have already come into 

attainment by the April 2010 deadline 

due in part to reductions achieved 

under CAIR. The fact that the 2010 

deadline will have passed before the 

Transport Rule is finalized emphasizes 

the importance of obtaining reductions 

as expeditiously as practicable. In 

addition, reductions achieved in 

upwind states by the 2014 emissions 

year will help downwind states 

demonstrate attainment by the April 

2015 deadline. 

2006 PM2.5 NAAQS Attainment 

Deadlines. For all areas designated as 

nonattainment with respect to the 2006 

24-hour PM2.5 NAAQS, the attainment 

deadline must be as expeditious as 

practicable but no later than December 

2014. Areas that fail to meet that 

deadline can request an extension to as 

late as December 2019. 

Upwind emission reductions 

achieved by the 2014 emissions year 

will help meet the December 2014 

attainment deadline. In addition, the 

first phase of reductions in 2012 will 

help many areas attain in a more 

expeditious manner. 

Further, a deadline of January 1, 2014 

also provides adequate and reasonable 

time for sources to plan for compliance 

with the Transport Rule and install any 

necessary controls. EPA believes that 

this deadline is as expeditious as 

practicable for the installation of the 

controls, if any, needed for compliance 

with the 2014 state emission budgets. 

(See further discussion in section 

V.C.2.) 

1997 Ozone NAAQS Attainment 

Deadlines. Ozone nonattainment areas 

must attain permissible levels of ozone 

‘‘as expeditiously as practicable,’’ but no 

later than the date assigned by EPA in 

the ozone implementation rule. 40 CFR 

51.903. The areas designated 

nonattainment in 2004 with respect to 

the 1997 8-hour ozone NAAQS in the 

eastern United States were assigned 

maximum attainment dates effectively 

corresponding to the end of the 2006, 

2009, and 2012 ozone seasons. The 

maximum attainment deadlines for the 

1997 standard run from the June 15, 

2004 effective date of designation for 

that standard. The time periods are 

based on the time periods provided for 

these classifications in section 181 of 

the Act, 45 U.S.C. 7511(a). However, 

instead of running from the 1990 date of 

enactment of the CAA as specified in 

section 181, our regulation provides that 

they run from the date of designation. 

An area’s maximum attainment date is 

based on its nonattainment 

classification—that is, whether it is 

classified as a marginal, moderate, 

serious, severe, or extreme ozone 

nonattainment area. Marginal areas have 

three years from designation to attain 

the standard. Moderate, serious, severe, 

and extreme areas have 6, 9, 15, and 20 

years, respectively. The maximum 

attainment deadlines associated with 

the 1997 ozone standards are June 15, 

2007 for marginal areas, June 15, 2010 

for moderate areas, and June 15, 2013 

for serious areas. Because the actual 

deadline occurs in the middle of an 

ozone season, data from that ozone 

season is not considered when 

determining whether the area has 

attained by the deadline. Thus, these 

maximum attainment deadline dates 

effectively correspond with the end of 

the 2006, 2009, and 2012 ozone seasons. 

Reductions achieved or air quality 

improvements realized after those dates 

will not help the areas meet their 

maximum attainment deadlines. 

Many areas have already attained the 

standard due in part to CAIR, federal 


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mobile source standards, and other 

local, state, and federal measures. Other 

areas, however, have been reclassified to 

a higher classification either because 

they failed to attain by their attainment 

date or because the state requested 

reclassification to avoid missing an 

attainment date. Those that have not yet 

attained the standard now have 

maximum attainment dates ranging 

from June 2011 (these are the moderate 

areas that have been granted a 1-year 

extension due to clean data for the 2009 

ozone season) to June 2024. The areas 

classified as ‘‘serious’’ nonattainment 

areas have a June 2013 maximum 

attainment deadline. Areas that missed 

their earlier deadlines and have been 

reclassified as ‘‘severe’’ or ‘‘extreme’’ 

nonattainment areas now have 

maximum nonattainment deadlines of 

June 2019 and June 2024 respectively. 

As explained above, an area with a June 

2013 deadline would need to attain 

based on ozone data from the 2010– 

2012 ozone seasons, an area with a June 

2019 deadline would need to attain 

based on ozone data from the 2016– 

2018 ozone seasons, and an area with a 

June 2024 deadline would need to attain 

based on ozone data from the 2021– 

2023 ozone seasons. 

The Transport Rule’s first phase of 

reductions in 2012 will help the 

remaining areas with June 2013 

maximum attainment deadlines attain 

the 1997 8-hour ozone NAAQS by their 

deadline. If EPA determines that an area 

failed to attain by the 2013 deadline, the 

area would be reclassified to severe and 

would be subject to the more stringent 

emission control requirements that 

apply to the severe classification. The 

reductions will also help areas with 

later deadlines attain as expeditiously as 

practicable and improve air quality in 

those areas. 

2012 Interim Compliance Deadline. 

EPA is requiring an initial phase of 

reductions starting in 2012. These 

reductions are necessary to ensure that 

significant contribution to 

nonattainment and interference with 

maintenance are eliminated as 

expeditiously as practicable and in time 

to help states meet their attainment 

deadlines. As the court emphasized in 

North Carolina, the significant 

contribution to nonattainment and 

interference with maintenance from 

upwind states must be eliminated as 

expeditiously as practicable to help 

downwind states to achieve attainment 

as expeditiously as practicable as 

required by the CAA. Further, 

reductions are needed by 2012 to help 

states attain before the June 2013 

maximum attainment date for ‘‘serious’’ 

ozone nonattainment areas, to ensure 

states attain as soon after the original 

April 2010 attainment deadline for the 

1997 PM2.5 NAAQS, and to help states 

attain before the December 2014 

attainment deadline for the 2006 PM2.5

NAAQS. 

In addition, because this final rule 

will replace CAIR, EPA could not 

assume that after this rule is finalized, 

EGUs would continue to emit at the 

reduced emission levels achieved by 

CAIR. Instead, it is the emission 

reduction requirements in the proposed 

FIPs that will determine the level of 

EGU emissions in the eastern United 

States. For this reason also, EPA 

concludes that it is appropriate to 

require an initial phase of reductions by 

2012 to ensure that existing and 

planned SO2 and NOX controls operate 

as anticipated. 

Addressing the Court’s Concern about 

Timing. As directed by the Court in 

North Carolina, 531 F.3d 896, and as 

described previously, EPA established 

the compliance deadlines in the 

Transport Rule based on the respective 

NAAQS attainment requirements and 

deadlines applicable to the downwind 

nonattainment and maintenance sites. 

The 2012 deadline for compliance 

with the limits on ozone-season NOX

emissions is necessary to ensure that 

states with June 2013 maximum 

attainment deadlines get the assistance 

needed from upwind states to meet 

those deadlines. The 2012 deadline for 

compliance with the limits on annual 

NOX and annual SO2 emissions is 

necessary to ensure attainment as 

expeditiously as practicable in areas 

which failed to attain by the 2010 

attainment deadline for the 1997 PM2.5

NAAQS and had to request an extension 

to 2015. 

Similarly, the 2014 deadline for 

compliance with the limits on annual 

NOX and annual SO2 emissions is 

necessary to ensure that downwind 

states get the benefit of upwind 

reductions prior to the December 2014 

maximum attainment deadline for the 

2006 PM2.5 NAAQS. It is also necessary 

to ensure reductions occur in time to 

assist with attainment in downwind 

areas that received the maximum 5-year 

extension of the 5-year attainment 

deadline for the 1997 PM2.5 NAAQS 

(taking into account the need for 

reductions by 2014 to demonstrate 

attainment by April 2015). 

The 2012 compliance deadline for the 

first-phase of annual NOX and annual 

SO2 emission reductions will assure the 

reductions are achieved as 

expeditiously as practicable. A 

significant amount of the emissions 

identified as significantly contributing 

to nonattainment or interfering with 

maintenance in other states can be 

eliminated by 2012. EPA believes it is 

appropriate to do so in light of the 

court’s direction to EPA to ensure states 

eliminate such emissions as 

expeditiously as practicable. North 

Carolina 531, F.3d at 930. Given the 

time needed to design and construct 

scrubbers at a large number of facilities, 

EPA believes the 2014 compliance date 

is as expeditious as practicable for the 

full quantity of SO2 reductions 

necessary to fully address the significant 

contribution to nonattainment and 

interference with maintenance. 

Requiring reductions in transported 

pollution as expeditiously as 

practicable, as well as within maximum 

deadlines, helps to promote attainment 

as expeditiously as practicable. This is 

consistent with statutory provisions that 

require states to adopt SIPs that provide 

for attainment as expeditiously as 

practicable and within the applicable 

maximum deadlines. 

b. Public Comments and EPA Responses 

EPA received numerous comments on 

the proposed compliance dates. A 

number of commenters supported EPA’s 

compliance schedule and rationale. 

Other commenters supported extending 

the compliance deadlines to later dates. 

Many commenters questioned the 

technical feasibility of achieving the 

required reductions by the 2012 and 

2014 dates. EPA’s responses to those 

comments are discussed below in 

section VII.C.2. 

Other commenters provided policy 

and legal arguments for allowing states 

to develop SIP alternatives to the FIP, 

and to build time for that SIP 

development and review process into 

the compliance schedule. For example, 

some commenters asserted that the 

requirement in the CAA for providing 

reductions ‘‘as expeditiously as 

practicable’’ must be balanced with 

CAA provisions allowing states to 

develop state implementation plans 

prior to EPA imposing FIPs. EPA 

responses to those comments are 

discussed in section X. 

Some commenters suggested that EPA 

had the ability to leave CAIR in place 

for a transition period, and by doing this 

EPA could allow for a longer 

compliance period for this rule. EPA 

does not believe it would be 

appropriate, in light of the Court’s 

decision in North Carolina, to establish 

a lengthy transition period to the rule 

that will replace CAIR. Although the 

Court decided on rehearing to remand 

CAIR without vacatur, the Court 

stressed its prior decision that CAIR was 

deeply flawed and EPA’s obligation to 

remedy those flaws. North Carolina, 550 


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59 GW: Gigawatts of capacity retrofitted; FGD: 

Flue gas desulfurization (SO2 control); DSI: Dry 

sorbent injection (SO2 control); SCR: Selective 

catalytic reduction (NOX control); LNB/OFA: LowNOX burner and/or overfire air (NOX controls). 

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 advance of the 2014 

attainment date. In light of the 2014 

five-year attainment date for the 2006 

PM2.5 NAAQS (with a possible 

extension to 2019), and the possible 

extension to April 2015 for the 1997 

PM2.5 NAAQS, these commenters 

believed EPA’s 2012 emission reduction 

requirements for annual PM2.5 and NOX

were not necessary. EPA disagrees with 

these commenters, for a number of 

reasons. First, EPA notes (supported by 

commenters) that there is a clear 

statutory obligation to attain ‘‘as 

expeditiously as practicable.’’ Second, 

EPA notes that there are feasible 

reductions available by 2012. Third, 

EPA believes that the substantial health 

and environmental benefits achieved by 

the rule underscore the importance of 

achieving the reductions as soon as 

possible. 

With respect to ozone, some 

commenters noted that the proposed 

rule required ozone reductions by 2012 

for states impacting areas which EPA’s 

analysis shows will attain the 1997 

ozone NAAQS by 2014 without further 

controls. Those commenters questioned 

the importance of getting reductions in 

such states and whether the 2012 

deadline is necessary. EPA disagrees 

with those comments. Except for 

Houston, all ozone areas within the 

region addressed by this rule have 

attainment dates no later than 2013. In 

effect, this means that emission 

reductions needed to attain the 1997 

ozone NAAQS must be in place by the 

2012 ozone season. EPA believes that if 

there are reductions available by 2012, 

and those emission reductions have in 

fact been identified, it is appropriate 

and necessary to ensure that those 

reductions are in place. 

2. Compliance and Deployment of 

Pollution Control Technologies 

The power industry will undertake a 

diverse set of actions to comply with the 

Transport Rule at the start of 2012 and 

another set of actions when companies 

in Group 1 states comply with more 

stringent SO2 budgets at the start of 

2014. In 2012, the industry will largely 

meet the rule’s NOX requirements by: 

Operating an extensive existing set of 

combustion and post-combustion 

controls on fossil fuel-fired generators; 

dispatching lower emitting units more 

often; and installing and operating a 

limited amount of relatively simple NOX

pollution controls in states not 

previously subject to CAIR. For the SO2

requirements, EPA anticipates at a 

minimum that coal-fired generators will 

operate the substantial capacity of 

advanced pollution controls already in 

place or scheduled for 2012 use; some 

units will also elect to burn lower-sulfur 

coals; and the fleet will increase 

dispatch from lower-sulfur-emitting 

units as well as from natural gas-fired 

generators. EPA provides a more 

detailed explanation below of how fuel 

switching to lower sulfur coals factored 

in to the design of the final Transport 

Rule. 

By 2014, EPA’s budgets under the 

Transport Rule will sustain previous 

NOX and SO2 reductions as well as 

account for reductions from additional 

advanced NOX and SO2 controls that are 

driven by other state and federal 

requirements. In addition to these 

reductions, companies in Group 1 states 

are also projected to add a limited 

amount of advanced SO2 controls in 

2014 that will be discussed below. 

EPA’s expectations are supported by 

the IPM analysis reported in this rule’s 

RIA (see Chapter 7). Notably, since EPA 

has established a cap and trade control 

system for lowering NOX and SO2

emissions, individual owners and 

operators of covered units have some 

flexibility in meeting the program’s 

requirements as needed and are free to 

find alternative ways to comply. The 

RIA clearly shows a viable known 

pathway for owners and operators to 

comply at reasonable costs, although it 

is not the only compliance pathway 

possible under this flexible regulation 

that could deliver the emission 

reductions required under the rule. 

Notably, by 2014 and beyond, the power 

industry may also augment the 

projected compliance efforts with 

programs aimed at improving energy 

efficiency. 

Table VII.C.2–1—shows EPA’s 

projection of the amount of existing 

coal-fired generating capacity in 

gigawatts (GW) that may retrofit various 

systems for compliance with this rule. 

TABLE VII.C.2–1—PROJECTED POTENTIAL AIR POLLUTION CONTROL (APC) RETROFITS FOR TRANSPORT RULE 59

Capacity retrofitted by Wet FGD Dry FGD DSI SCR LNB/OFA 

improvements 

January 1, 2012 ............................................................. ......................... ......................... ......................... ......................... 10 GW 

January 1, 2014 ............................................................. 5.7 GW ........... 0.2 GW ........... 3.0 GW ........... 0 GW.

EPA received proposal comments 

expressing a concern about the 

feasibility of deploying retrofit air 

pollution control (APC) technologies in 

the time frames available between the 

final date of this rule and the 

compliance dates. As discussed below, 

EPA believes that it is feasible for the 

electric power sector and its APC 

supply chain to either make most of the 

projected retrofits in time to meet the 

2012 and 2014 compliance deadlines, or 

to comply by other means. 

a. 2012 Power Industry Compliance 

EPA’s analysis of emission reductions 

available in 2012 assumes year-round 

operation of existing post-combustion 

pollution controls in states covered for 

PM2.5 and ozone-season operation of 

NOX post-combustion controls in states 

covered for ozone. EPA also modeled 

emission reductions available in 2012 at 

the $500/ton threshold for SO2, $500/ton 

for annual NOX, and $500/ton for ozoneseason NOX. 

For SO2, EPA believes that reductions 

associated with the following methods 

of control are available and will be used 


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60 David L. Wojichowski, SNCR System—Design, 

Installation, and Operating Experience http:// 

www.netl.doe.gov/publications/proceedings/02/scrsncr/wojichowski-1.pdf. 

as compliance strategies to meet the 

2012/2013 budgets: (1) Operation of 

existing controls year-round in PM2.5

states, (2) operation of scrubbers that are 

currently scheduled to come online by 

2012, (3) some sources switching to 

lower-sulfur coal (see section VII.C.2.c 

that follows), and (4) changes in 

dispatch and generation shifting from 

higher emitting units to lower emitting 

units. EPA modeling and selection of a 

$500/ton cost threshold includes all 

existing and planned controls operating 

year round (items 1 and 2). It also 

reflects an amount of coal switching and 

generation shifting that can be achieved 

for $500/ton. This set of expected 

actions was confirmed in the detailed 

modeling of EPA’s final remedy in the 

RIA and can be reviewed there. 

The power sector is already strongly 

positioned to achieve the Transport 

Rule state budgets presented in section 

VI.D through at least three distinct 

strategies. First, the sector will optimize 

its use of the large proportions of 

advanced pollution controls already 

present throughout the fleet. Second, 

the sector will take advantage of the 

substantial new pollution control 

technology that is already on the way 

for deployment by 2012. Third, the 

remainder of the fleet will flexibly adopt 

the most economic low-emitting fuel 

mix available at each unit to deliver 

cost-effective emission reductions 

complementing the reductions achieved 

from optimized use of the fleet’s 

pollution control technology. The state 

maps in Chapter 7 of this rule’s 

Regulatory Impact Analysis demonstrate 

how these emission reduction strategies 

for 2012 will build off of the sector’s 

historic trend toward cleaner generation 

profiles. Also, the detailed unit-level 

projection files from EPA’s IPM power 

sector modeling of the Transport Rule 

remedy (found in the docket for this 

rulemaking) show how EGUs adopt 

these strategies to not only reach the 

2012 budgets, but in fact in many states 

overcomply with the budgets and build 

up a bank of allowances under the 

programs for future flexibility. 

The following paragraphs illustrate 

the degree to which the existing fleet is 

already prepared to adopt these 

emission reductions in 2012 in order to 

attain the required emission reductions 

for SO2, annual NOX, and ozone-season 

NOX under the Transport Rule. More 

specifically, the illustrative paragraphs 

demonstrate emission reduction 

pathways for coal capacity to optimize 

or increase operation of existing control 

technology, timely implement existing 

plans to bring additional control 

technology on line, and to costeffectively make use of lower-emitting 

fuel alternatives. 

Of the 240 GW of coal capacity in the 

Transport Rule region covered for fine 

particles, approximately 110 GW—more 

than 45 percent—had existing advanced 

pollution control for SO2 already in 

place in 2010, including scrubbers 

(FGD), dry sorbent injection (DSI), or 

circulating fluidized bed boilers. Of this 

controlled coal capacity, EPA expects a 

significant portion will improve 

emission rates through either increased 

use of control technology and/or 

additional fuel switching. EPA notes 

that an additional 39 GW of advanced 

SO2 controls in the region are scheduled 

to come online over the 2010–2012 

timeframe and will also assist in 

meeting 2012 emission reduction 

requirements. Thus, by 2012 more than 

half of affected coal capacity—152 

GW—will be operating with advanced 

SO2 control equipment. Additionally, 

EPA expects approximately 40 GW of 

uncontrolled coal capacity in the region 

to take advantage of the existing coal 

supply infrastructure, possibly 

switching coal use or coal blending 

behaviors to make cost-effective 

reductions in SO2 emission rates where 

economic to respond to the Transport 

Rule 2012 emission reduction 

requirements. 

EPA notes that approximately 136 GW 

of the 240 GW—more than 56 percent— 

of coal capacity in the Transport Rule 

region covered for fine particles had 

existing advanced pollution control for 

NOX already in place in 2010, including 

selective catalytic reduction (SCR), 

selective non-catalytic reduction 

(SNCR), or circulating fluidized bed 

boilers. Of this capacity, EPA 

anticipates a significant portion will 

improve their NOX emission rate 

through increased operation of these 

existing controls. Additionally, EPA 

notes that an additional 21 GW of SCR 

and 4 GW of enhanced combustion 

controls (including low-NOX burners 

and overfire air) are scheduled to come 

online in the region during the 2010– 

2012 timeframe, bringing the total 

region’s coal capacity operating with 

NOX emission reduction technology to 

158 GW (more than 65 percent of total 

coal capacity in the Transport Rule fine 

particle region). EPA also projects that 

approximately 13 GW of coal capacity 

will make some reduction in their NOX

emission rates by enhancing 

performance of existing combustion 

controls or SNCR, or by fuel switching. 

In the Transport Rule states covered 

under the ozone-season program, 

approximately 145 GW of the 260 GW 

(more than 55 percent) of coal capacity 

had existing NOX control technology in 

place in 2010. EPA expects a significant 

portion of that capacity to achieve 

emission reductions during the 2012 

ozone-season through improved 

operation of SCR. Additionally, in the 

Transport Rule ozone region there will 

be approximately 21 GW of additional 

advanced NOX control installations and 

7 GW of additional combustion control 

improvements or installations coming 

online during the 2010 to 2012 time 

frame. EPA projects that 17 GW of coal 

capacity in the Transport Rule ozone 

region will reduce NOX emission rates 

by enhancing performance of existing 

combustion controls or SNCR or by fuel 

switching. 

For NOX, EPA has also concluded that 

it is appropriate to require reductions 

through a limited amount of combustion 

control improvements, and in some 

cases, retrofits such as low-NOX burners 

(LNB) and/or overfire air (OFA). EPA 

recognizes that the 6-month time frame 

between rule finalization and start of the 

first compliance period would not allow 

for the installation of a major postcombustion NOX control such as SCR. 

Assumed improvements and retrofits for 

the January 1, 2012 deadline for annual 

NOX reductions therefore only involve 

the much simpler LNB/OFA control 

modifications or installations. 

Alternatively, some plant owners might 

choose to achieve NOX reductions in a 

similar time period through an even 

simpler retrofit—SNCR.60

Although the improvements, and in 

some cases, installation of combustion 

controls would be an economic means 

of achieving emission reductions, these 

specific controls are not required for 

compliance purposes under the final 

Transport Rule remedy. Individual 

sources may comply through other 

measures (such as purchasing additional 

allowances) in the event that it takes 

more than 6 months for installation of 

a given combustion control. The vast 

majority of covered sources already 

have combustion controls installed; 

therefore, the NOX reductions associated 

with these incremental control 

improvements and installations are 

small. 


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61Technical Support Document (TSD) for the 

Transport Rule, Docket ID No. EPA–HQ–OAR– 

2009–0491, Installation Timing for Low NOX

Burners (LNB). 

62R. Pearce, J. Grusha, Reliant Energy Tangential 

Low NOX System at Limestone Unit 2 Cuts Texas 

Lignite, PRB and Pet Coke NOX, http:// 

www.fwc.com/publications/tech_papers/files/ 

tp_firsys_01_02.pdf. 

63B. 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. 

64M. O’Donnell, Babcock & Wilcox Company, 

(personal communication with EPA staff, February 

22, 2011). 

65N.C Widmer, et al., Coal Power, October 8, 

2009, http://www.coalpowermag.com/ops_and_

maintenance/Zonal-Combustion-Tuning-SystemsImprove-Coal-Fired-Boiler-Performance_226.html. 

Based on the Transport Rule’s 

geography, EPA estimates that 

approximately 10 GW of coal-fired units 

may improve, and in some cases, install 

LNB/OFA specifically in reaction to the 

Transport Rule NOX caps. EPA reflects 

the effects of these installations in the 

2012 annual and ozone-season NOX

budgets, which would yield reductions 

of approximately 28,000 tons of annual 

NOX and 14,000 tons of ozone-season 

NOX. EPA assumes these controls are 

cost effective at $500/ton and that they 

should be incentivized through budgets 

given the 2013 attainment deadline for 

ozone areas classified as ‘‘serious.’’ 

Once installed, LNB/OFA operates any 

time the boiler is fired and thus yields 

NOX reductions beyond the ozone 

season alone. 

In the proposal’s LNB technical 

support document,61 EPA observes that 

LNB and/or OFA installations, burner 

modifications, or other NOX reduction 

controls would likely have to be 

installed during fall 2011 or spring 2012 

outages in order to achieve significant 

reductions for 2012. While this 6-month 

schedule is aggressive, industry has 

shown that it can be met. For example, 

Limestone Electric Generating Station 

Unit 2, an 820 MW tangentially-fired 

lignite unit, was retrofitted with Foster 

Wheeler’s Tangential Low NOX (TLN3) 

system in less than six months, 

including engineering, fabrication, 

delivery and installation.62 Harlee 

Branch Unit 4, a 535 MW cell-fired unit, 

was retrofitted with Riley Power’s lowNOX Dual Air Zone CCV burners on a 

similar schedule.63 These are 

tangentially-fired and wall-fired units, 

respectively, representative of the unit 

types that might make LNB/OFA 

improvements for compliance with this 

rule. Although such 6-month schedules 

can be achieved on some units, under 

favorable circumstances, historical 

projects suggest a more typical schedule 

would be 12 to 16 months for the 

contractor’s portion of the work.64 A 

plant owner’s project planning and 

procurement work in advance of a 

contract award would typically involve 

several additional months. On the other 

hand, there are other approaches that 

can also be implemented in a short time 

frame to achieve significant NOX

reduction. As mentioned above, 

relatively simple SNCR systems can be 

installed quickly; and the re-tuning or 

upgrading of existing combustion 

control systems can often provide 

significant NOX reductions and can be 

performed quickly.65

As stated above, EPA believes that 

LNB/OFA modifications or retrofits 

would be possible during the 6-month 

interim between rule signature and the 

start of the first compliance period, 

particularly for those ‘‘early movers’’ 

who have initiated LNB projects based 

on the proposed rule. However, as 

shown in Table VII.C.2–2, below, even 

if all LNB modifications or installations 

are delayed until the beginning of the 

2012 ozone season, the reductions only 

represent 1 percent of most covered 

states’ annual NOX budgets, and no 

more than 11 percent of any affected 

state’s annual NOX budget. Under such 

a scenario, these delayed reductions 

would still be well within the 18 

percent variability limit applied to each 

state’s annual NOX budget. In light of 

this limited consequence and the 

supporting material above, EPA 

includes LNB-driven NOX reductions in 

both annual and ozone-season NOX

budgets for 2012. 

TABLE VII.C.2–2—EARLIEST REDUCTIONS ASSUMED FROM LNB INSTALLATIONS IN THE TRANSPORT RULE STATES

SUBJECT TO THE ANNUAL NOX PROGRAM * 

NOX reductions 

from LNB 

operation from 

January–April 

(tons) 

Annual NOX

state budget 

(tons) 

Percent of budget met by earliest 

LNB reductions 

(percent) 

Georgia ............................................................................................................................ 646 62,010 1 

Iowa ................................................................................................................................. 567 38,335 1 

Kansas ............................................................................................................................. 2,131 30,714 7 

Minnesota ........................................................................................................................ 2,303 29,572 8 

Nebraska .......................................................................................................................... 3,008 26,440 11 

Region-wide Total ..................................................................................................... 8,656 1,245,869 1 

* Based on EPA IPM Analysis of Final Transport Rule. 

b. 2014 Power Industry Compliance 

EPA projects that compliance with 

2014 requirements for NOX will result 

largely from operation of existing and 

future controls required by state and 

other federal requirements, as well as 

the appropriate dispatch of the electric 

generation fleet. EPA does not project 

additional NOX pollution control 

retrofits aside from about 10 GWs of 

combustion control improvements or 

retrofits projected for the 2012 

compliance period. To comply with the 

rule’s SO2 requirements, EPA projects 

that the power industry will rely on 

existing controls, operate newly 

installed advanced controls necessary 

for other binding state and federal 

requirements, rely more on relatively 

lower sulfur coals, and dispatch loweremitting 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. 

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 


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66Nearly 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). 

67As noted elsewhere in this preamble, the 

projected impacts of this final rule presented in the 

preamble do not reflect minor technical corrections 

to SO2 budgets in three states (KY, MI, and NY) and 

assumed preliminary variability limits that were 

smaller than the variability limits finalized in this 

rule. EPA conducted sensitivity analysis factoring 

in these corrections; the results of this analysis 

include a small increase of about 700 MW of 

additional wet FGD retrofit projected for 2014. This 

projected additional retrofitting capacity is already 

required to retrofit under a consent decree and 

should therefore have already conducted advanced 

retrofit planning. EPA therefore believes that this 

incremental projected retrofit behavior (factoring in 

the technical corrections made after the main 

impact analyses were conducted) is feasible by 2014 

for the same reasons presented in this section 

regarding the projected retrofit behavior from the 

main analysis of the final rule. 

68EPA, Engineering and Economic Factors 

Affecting the Installation of Control Technologies 

for Multipollutant Strategies; EPA–600/R–02/073 

October 2002. 

69Best Coal-fired Projects, Springerville Unit 3 

Expansion Project, Power Engineering, November 

2006, http://www.powergenworldwide.com/index/

display/articledisplay/282547/articles/powerengineering/volume-111/issue-1/features/projectsof-the-year.html. 

70http://www.cwlp.com/electric_division/

generation/Dallman%204%20Power%20Plant%20

of%20the%20Year.pdf. 

71http://www.epa.gov/compliance/resources/

decrees/civil/caa/americanelectricpower-cd.pdf. 

72http://www.businesswire.com/news/home/2006

0731005193/en/Contractors-Selected-InstallEmissions-Control-System-Pennsylvania. 

73http://www.epa.gov/Compliance/resources/

complaints/civil/caa/homercity-cp.pdf. 

for compliance with the Transport 

Rule.66 67 EPA’s schedule assumptions 

for these larger more complex projects 

were developed in an earlier study and 

mentioned in the proposal: 27 months 

for retrofitted wet FGD and 21 months 

for SCR.68 Note that a dry FGD system, 

due to its relatively simpler 

configuration and lesser cost, would 

typically take somewhat less time to 

retrofit than wet FGD. 

As discussed below, EPA believes that 

its schedule assumptions remain 

reasonable expectations for sources that 

have completed most of their 

preliminary project planning and can 

quickly make commitments to proceed. 

These schedules do not include the 

extensive time that some plant owners 

might spend in making a decision on 

whether or not to retrofit. They do 

include the time needed to make a final 

confirmation of the type of technology 

to be used at a particular site, to prepare 

bid requests, award contracts, perform 

engineering, obtain construction and 

operating permits (in parallel with 

project activities), perform construction, 

tie-in to the existing plant systems, and 

perform integrated systems testing. 

EPA received comments on the 

proposed rule indicating that some past 

single-unit APC retrofits had 

considerably longer schedules, with a 

few exceeding 48 months. EPA 

engineering staff have extensive 

experience with power plant and APC 

system design, construction, and 

operation. Based on that experience, 

EPA can observe that in the absence of 

a compelling deadline or major 

economic incentive, many large project 

schedules are considerably longer than 

necessary. Given further observations as 

explained below, EPA believes it is 

reasonable to expect that almost all 

future APC retrofits can be completed 

far more quickly than they were in 

recent history. EPA’s perspective on this 

matter derives in part from a 

comparison of longer APC schedules (as 

provided by some commenters) to the 

project schedule for an entire new coalfired unit, including its APC systems. 

Springerville Unit 3, for example, is a 

new 400 MW subbituminous coal-fired 

unit with SCR and dry FGD that became 

operational in July 2006, some 33 

months after the turnkey engineeringconstruction contractor was given a 

notice to proceed with engineering.69

Springerville was clearly on an 

accelerated schedule, as its original 

planned schedule was about 38 months. 

Another example is Dallman Unit 4, a 

high-sulfur bituminous coal-fired 200 

MW unit with SCR, fabric filter, wet 

FGD, and wet ESP. Dallman Unit 4 was 

first synchronized in May 2009, several 

months ahead of schedule, and about 36 

months after its turnkey contractor 

placed initial major equipment orders.70

The main point here is that recent APC 

project schedules, and those of large 

complex power projects, can be 

significantly accelerated. Because the 

scope and complexity of the work 

involved for an entire new coal unit and 

its APC systems is perhaps five times 

greater than that of a retrofit wet FGD 

system alone, EPA believes it is 

reasonable to expect that even the most 

complex retrofit APC project can be 

significantly accelerated as well. 

Additional factors are discussed below 

that further support the feasibility of 

installing by 2014 the 5.9 GW of FGD 

retrofits projected for this rule. 

Although IPM modeling provides 

reliable estimates on a regional basis, 

and cannot be as accurate at the level of 

individual plants or units, it is 

informative and relevant to consider 

IPM’s plant level projections in this 

case. Although the IPM-projected 

retrofits named below may not actually 

occur, IPM projects that they would be 

economic and would allow industry to 

meet the tighter SO2 emission standards 

in Group 1 states in 2014. EPA notes 

that the owners of the particular plants 

mentioned below (Duke Energy, AEP, 

Edison International) are large, 

experienced, versatile utilities that have 

done considerable advance planning 

and should also have above-average 

flexibility to comply with state budgets 

across their fleets. EPA would expect 

such owners to have relatively little 

difficulty in permitting and financing 

FGD retrofits. 

Of the Transport Rule-related FGD 

retrofits, 0.2 GW is projected to use dry 

FGD, which EPA expects to be simpler 

and quicker to install than wet FGD. 

Half of the 5.9 GW (Muskingum, 

Rockport) has already been committed 

under consent decrees to add controls or 

retire; 71 and EPA reasonably believes 

that significant preliminary project 

planning work has already been done 

for those projects. An additional 1,200 

MW (Homer City) had completed 

project planning and was ready to 

proceed in 2007, before putting the 

project on hold.72 The latter plant is 

now facing EPA legal action and the 

possibility of a required expeditious 

FGD retrofit.73 Thus, of the 5.9 GW of 

projected FGD retrofits resulting from 

this rule, nearly 75 percent appears to 

be in good position for an early start of 

construction, and over 3 GW of that 

would be bringing forward already 

committed compliance start dates. 

Any of the above mentioned potential 

retrofits or any other unit that might 

choose to retrofit FGD for a January 

2014 compliance date will likely have to 

use various methods to accelerate the 

project schedule. Such methods could 

include the use of parallel permitting, 

overtime and/or two-shift work 

schedules during construction, and 5- or 

6-day work weeks instead of the 4-day 

× 10-hour schedules often used to 

minimize cost when time is not of the 

essence. Increased use of offsite 

modularization and pre-fabrication of 

APC components could also shorten 

schedules and reduce job hours. 

EPA believes that the January 1, 2014 

compliance date is as expeditious as 

practicable for the sources installing 

large, complex control systems. The 

following additional observations 

support EPA’s expectation that the 

limited 5.9 GW of FGD retrofits can be 

realized in the 30 month interim 

between rule signature and the start of 

2014: 

• There are documented instances of 

large, complex wet FGD retrofits being 

deployed in less than 30-months 

(excluding the time for owners’ project 


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74Black & Veatch, http://www.bv.com/News_3_

Publications/News_Releases/2005/0503.aspx (start), 

http://www.bv.com/wcm/press_release/07252007_

9767.aspx (completion). 

75PowerGenWorldwide, Projects of the Year, 

January 1, 2007, http://www.powergenworldwide.

com/index/display/articledisplay/282547/articles/

power-engineering/volume-111/issue-1/features/

projects-of-the-year.html. 

76 ICAC letter to Senator Carper, November 3, 

2010, http://www.icac.com/files/public/ICAC_

Carper_Response_110310.pdf. 

77Assessment 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. 

planning). Examples are Killen Station 

Unit 2,74 and Asheville Unit 1.75

• In 2009 the APC supply chain 

deployed more than six times more GW 

capacity of FGD and SCR controls than 

the 5.9 GW of FGD that would be 

deployed by 2014 under this Rule. 

• The APC supply chain has seen a 

2-year decline in deployments since its 

peak in 2009, but in 2011 is nonetheless 

putting into service about three times 

more GW capacity of FGD and SCR 

controls than the 5.9 of FGD that would 

be deployed under this Rule. 

• Because the supply chain has been 

in decline, but remains quite active, 

there are now adequate supply chain 

resources available that can be quickly 

reengaged to support a rapid 

deployment of 5.9 GW of FGD. 

EPA recognizes that the installation of 

any amount of scrubbers in this short 

time frame will require aggressive action 

by plant owners and that the owners 

who can meet this schedule will already 

have done their project planning and 

will be ready to place orders. An 

example of such ‘‘early movers’’ was 

seen in the power sector’s anticipation 

of CAIR. EPA data indicate that solely 

CAIR-driven FGD and SCR deployments 

of about 6 GW occurred within two and 

one-half years after CAIR’s finalization 

in mid-2005, showing that at least 20 

percent of the total CAIR-only controls 

effort through a 2010 compliance date 

was sufficiently planned for installation 

to start before or immediately upon 

finalization of the rule. EPA reasonably 

expects that similar advance planning 

has already been done for units that 

would retrofit under this rule. 

In the event that a particular control 

installation requires additional time into 

2014 to come online, EPA believes 

compliance would not be jeopardized 

given the ability of sources to purchase 

allowances during that time. This 

approach could be supported by some 

sources with FGD that have the ability 

to increase their SO2 removal above 

historic rates, perhaps through relatively 

low cost upgrades to improve scrubber 

effectiveness, or by operating scrubbers 

at higher chemistry ratios. The ability of 

sources to temporarily or permanently 

substitute dry DSI for FGD serves as 

another backstop for any feasibility 

issues regarding FGD. Note that the 

updated modeling for this rule projects 

the addition by 2014 of about 3 GW of 

DSI for SO2 control using trona or other 

sorbent. DSI is a relatively low capital 

cost technology that readily can be 

installed in the time frame available for 

compliance.76 77

It should also be noted that most APC 

retrofits will involve a source outage for 

final ‘‘tie-in’’ of retrofitted systems to 

existing systems, during which time 

emissions from the affected units are 

zero. For some sources, the duration of 

this tie-in outage may effectively extend 

the deadline by which all of the 

projected emission reductions need to 

occur. 

Although EPA believes that 

installation of 5.9 GW of FGD at 

facilities by January 1, 2014 is feasible, 

EPA also conducted an IPM sensitivity 

analysis to examine a scenario in which 

FGD retrofitting by 2014 is not allowed. 

Results of EPA’s ‘‘no FGD build in 

2014’’ analysis indicate that if the power 

industry were subjected to the 

requirements of this rule without an 

FGD retrofit option for compliance until 

after 2014, covered units would still be 

able to meet the Transport Rule 

requirements in every state while 

respecting each state’s assurance level. 

(See the docket to this rulemaking for 

the IPM run titled ‘‘TR_No_FGD_ 

in2014_Scenario_Final.’’) 

In this scenario without the 

availability of new FGD by 2014, 

sources in covered states complied with 

the Transport Rule budgets by using 

moderate additional amounts of DSI 

retrofits, switching to larger shares of 

sub-bituminous coal, and dispatching 

larger amounts of natural gas-fired 

generation in lieu of the FGD retrofits 

that are projected as being most 

economic under modeling of the 

Transport Rule remedy. Because new 

FGD capacity is included in EPA’s 

projection of the least-cost set of SO2

emission reductions required in Group 

1 states, the ‘‘no FGD’’ sensitivity 

scenario did project higher system costs, 

although these costs were still 

substantially lower than the remedy 

EPA modeled in the Transport Rule 

proposal. 

The ‘‘no FGD’’ analysis indicates that 

while the ability of Group 1 states to 

meet their 2014 SO2 budgets is 

facilitated by FGD retrofits, they are by 

no means required, nor is Transport 

Rule compliance jeopardized by their 

absence. Even under a scenario in 

which sources fail to complete FGD 

retrofits by 2014, sources in the affected 

states would have other compliance 

options available at reasonable cost to 

meet the state’s budget requirements. 

This analysis shows that Group 1 states 

would be able to comply with their 2014 

SO2 budgets by relying on other 

emission reduction opportunities that 

do not require FGD retrofits. EPA 

analysis confirms that those alternatives 

are feasible both in terms of cost and 

timing. 

Finally, EPA recognizes that, when 

finalized later this year as currently 

scheduled, the Mercury and Air Toxics 

Standards (MATS) will require 

significant retrofit activity at covered 

sources in the power sector with a 2015 

compliance date for that rule. EPA’s 

projections of retrofit activity under the 

final Transport Rule are highly 

compatible with its projections of 

retrofit activity under the proposed 

MATS (which included the proposed 

Transport Rule in its baseline). EPA 

therefore anticipates that the Transport 

Rule’s projected retrofit activity will not 

only be the least-cost compliance 

pathway to meeting state budgets in 

2014 but will also accelerate emission 

reductions subsequently required by the 

effective date of MATS. The final 

Transport Rule’s projected 2014 retrofit 

installations will also further 

incentivize the power sector to ramp up 

its retrofit installation capabilities to 

achieve broader deployment of the 

projected pollution control retrofits 

under the proposed MATS. 

Considering all the reasons given 

above, EPA has concluded that the 2014 

requirements for SO2 emissions in the 

states covered by the Transport Rule are 

reasonable and can be met by the power 

industry by a variety of means. 

c. Coal Switching for SO2 Compliance in 

2012 and 2014 

Coal switching is another mechanism 

which can be used along with operating 

pollution controls in 2012 for 

compliance. It will be a complementary 

activity by many coal-fired units 

alongside of operating pollution 

controls and the addition of more 

scrubbers and DSI in 2014. 

In the proposal, EPA noted that coal 

switching could serve as a compliance 

mechanism for 2012. EPA requested 

comment on the reasonableness of 

EPA’s assumption that coal switching 

will have relatively little cost or 

schedule impact on most units. EPA 

received substantial comment 

suggesting that the coal switching and 

coal blending projected by EPA 

modeling are not feasible for all units, 


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78Assessment 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. 

and that, if feasible, would often incur 

a cost through the derating of the unit 

associated with the switch to a lower 

sulfur coal or coal blend. Additionally, 

sources indicated that coal switching by 

2012 would not always be possible in 

the six month window between final 

rule signature and start of compliance. 

These feasibility concerns stemmed 

from restrictions included in existing 

coal supply contracts and from boiler 

design constraints that may hinder coal 

switching within a 6 month window. 

EPA agrees with these concerns and 

revised its IPM modeling to limit coal 

switching capability in 2012 for 

particular units that may have trouble 

switching coals or coal blends in a six 

month time frame. A cost adder was 

also included in the IPM modeling for 

coal switching to capture the potential 

cost burden of deratings that might 

accompany switching to a very low 

sulfur subbituminous coal or coal blend. 

A particular commenter concern 

regarding switching to lower sulfur 

within the eastern bituminous coals 

related to a possible impact on the 

performance of a cold-side electrostatic 

precipitator (ESP). Some ESPs that 

operate at acceptably high collection 

efficiency when using a high- or 

medium-sulfur bituminous coal may 

experience some loss in collection 

efficiency when a lower sulfur coal is 

used. Whether this occurs on a specific 

unit, and the extent to which it occurs, 

would depend on the design margins 

built into the existing ESP, the 

percentage change in coal sulfur 

content, and other factors. In any case, 

industry experience indicates that 

relatively inexpensive practices to 

maintain high ESP performance on 

lower sulfur bituminous coals are 

available and can be used successfully 

where necessary. These include a range 

of upgrades to ESP components and flue 

gas conditioning.78 EPA therefore 

assumes that it will not be necessary for 

units that switch from higher to lower 

sulfur bituminous to make a costly 

replacement of the ESP. 

Coal switching as a SO2 compliance 

option might also include switching 

from bituminous to subbituminous coal. 

EPA’s analysis does not assume that a 

unit designed for bituminous can switch 

to (very low sulfur) subbituminous coal 

unless the unit’s historical data 

demonstrate that capability in the past. 

EPA assumes that units with that 

demonstrated capability have already 

made any investments needed to handle 

a switch back to the use of 

subbituminous coal at a similar 

percentage of its heat input as in the 

past. For IPM analysis in the final rule 

EPA also introduced a coal switching 

option that assumes that units can 

increase a historically low percentage 

use of subbituminous to a ‘‘maximum’’ 

level, if economic. This option includes 

an appropriate derate in output, 

increase in heat rate, and additional 

capital and operating costs. Details of 

this and other IPM updates for this rule 

are provided in the IPM Modeling 

Documentation in the docket for this 

rulemaking (‘‘Documentation 

Supplement for EPA Base Case 

v.4.10_FTransport—Updates for Final 

Transport Rule’’). 

Some commenters also expressed 

concern with the assumption that coalswitching from lignite to subbituminous 

is a cost-effective or feasible emission 

reduction strategy, particularly at Texas 

EGUs. EPA carefully considered these 

comments and adjusted its modeling of 

cost-effective reductions to address this 

concern. Specifically, EPA made 

adjustment in the model so that it 

assumes coal-switching is not a 

compliance option at the specific units 

where commenters identified technical 

barriers to subbituminous coal 

consumption. The Transport Rule 

emission budgets are based on this 

adjusted modeling which does not 

assume any infeasible coal-switching 

from lignite to subbituminous. In 

addition, EPA’s analysis of cost-effective 

reductions in each state presented in 

section VI.B shows that Texas is capable 

of cost-effectively meeting its Transport 

Rule emission budgets; however, EPA 

also conducted sensitivity analysis that 

shows Texas can also achieve the 

required cost-effective emission 

reductions even while maintaining 

current levels of lignite consumption at 

affected EGUs. More details regarding 

this analysis, including a table 

comparing key parameters between the 

main Transport Rule remedy analysis 

and this Texas lignite sensitivity, can be 

found in the response to comments 

document and the IPM model output 

files included in the docket for this 

rulemaking. 

D. Allocation of Emission Allowances 

Under the final rule, EPA distributes 

a number of SO2, annual NOX, and 

ozone-season NOX emission allowances 

to covered units in each state equal to 

the SO2, annual NOX, and ozone-season 

NOX budgets for those states. These 

budgets are addressed in section VI.D of 

this preamble. This section discusses 

the methodology EPA uses to allocate 

allowances to covered units in each 

state. 

As discussed later in section VII.D.2, 

EPA is setting aside a base 2 percent of 

each state’s budgets for allowance 

allocations for new units, with 5 percent 

of that 2 percent, or 0.1 percent of the 

total state budget being set aside for new 

units located in Indian country. To this 

base 2 percent, EPA is setting aside an 

additional percentage on a state-by-state 

basis, ranging from 0 to 6 percent 

(yielding total set asides of 2 percent to 

8 percent), for units planned to be built. 

The remainder of the state budget is 

allocated to existing units. Tables VI.D.– 

3 and VI.D.–4 in this preamble show the 

SO2, annual NOX, and ozone-season 

NOX budgets for each covered state 

(without the variability limits). In 

allocating allowances to existing and 

new units, EPA distributes four discrete 

types of emission allowances for four 

separate programs: SO2 Group 1 

allowances, SO2 Group 2 allowances, 

annual NOX allowances, and ozoneseason NOX allowances. 

In the SO2 Group 1 and SO2 Group 2 

programs, each SO2 allowance 

authorizes the emission of one ton of 

SO2 in that vintage year or earlier and 

is usable for compliance only in the 

program for which the allowance was 

issued. In the annual NOX program, 

each annual NOX allowance authorizes 

the emission of one ton of NOX in that 

vintage year or earlier in that program. 

In the ozone-season NOX program, each 

ozone-season NOX allowance authorizes 

the emission of one ton of NOX during 

the regulatory ozone season (May 

through September for this final rule) in 

that vintage year or earlier for that 

program. 

In each of the four trading programs, 

a covered source is required to hold 

sufficient allowances (issued in the 

respective trading program) to cover the 

emissions from all covered units at the 

source during the control period. EPA 

assesses compliance with these 

allowance-holding requirements at the 

source (i.e., facility) level. 

This section explains how, in this 

final rule, EPA allocates a state’s budget 

to existing units and new units in that 

state. This section also describes the 

new unit set-asides and Indian country 

new unit set-asides in each state, 

allocations to units that are not 

operating, and the recordation of 

allowance allocations in source 

compliance accounts. 

1. Allocations to Existing Units 

This subsection describes the 

methodology EPA will use in the FIPs 

finalized in this action to allocate to 


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79 In this rule, existing units are defined as 

covered units that commenced commercial 

operation prior to January 1, 2010. As explained in 

greater detail in Section VII.B. of this preamble, 

EPA decided to use this definition to ensure that 

EPA would have at least 1 full year of qualityassured data on which to base a unit’s allocation. 

existing units.79 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 

constrains the heat input-based 

allocations from exceeding any unit’s 

maximum historic emissions. Further 

detail on the implementation of this 

approach is provided in section 

VII.D.1.c below as well as in the 

Allowance Allocation Final Rule TSD in 

the docket for this rulemaking. All 

existing-unit allocations for 2012 will be 

made pursuant to the FIPs. However, as 

described in section X, states may 

submit SIPs or abbreviated SIPs to use 

different allocation methodologies for 

allowances of vintage year 2013 and 

later. 

a. Summary of Allocation 

Methodologies and Comments 

EPA took comment on three distinct 

allocation methodologies for existing 

units. The first—an emissions-based 

option—was presented in the original 

Transport Rule proposal (75 FR 45309). 

The second and third—heat input 

option 1 and heat input option 2—were 

presented in a Notice of Data 

Availability (76 FR 1113). EPA received 

numerous comments on all three 

options. 

i. Emission-Based Allocation 

Methodology 

The emission-based option presented 

in the original Transport Rule proposal 

would base allowance allocations to 

existing units on each covered unit’s 

calculated emission ‘‘share’’ of that 

state’s budget for a given pollutant 

under the Transport Rule. The proposed 

rule stated that ‘‘for 2012, each existing 

unit in a given state receives allowances 

commensurate with the unit’s emissions 

reflected in whichever total emissions 

amount is lower for the state, 2009 

emissions or 2012 base case emissions 

projections. In either case, the allocation 

is adjusted downward, if the unit has 

additional pollution controls projected 

to be online by 2012. * * * For states 

with lower SO2 budgets in 2014 (SO2

Group 1 states), each unit’s allocation 

for 2014 and later is determined in 

proportion to its share of the 2014 state 

budget, as projected by IPM’’ (75 FR 

45309). 

Many commenters objected to this 

projected emission allocation 

methodology. Commenters offered two 

principle objections. First, they argued 

EPA should not use unit-level model 

projections to allocate allowances. 

Second, they argued the use of any 

emission-based allowance methodology 

is improper. Many of these commenters 

argued that instead of an emission-based 

allocation methodology, EPA should use 

a heat-input-based allocation 

methodology. 

Commenters’ objections to the use of 

unit level model projections focused 

primarily on the accuracy of such 

projections. While many commenters 

supported the use of modeling 

projections in determining state 

emission budgets, they argued that the 

unit-level model projections were not 

sufficiently accurate to use as a basis for 

allocating allowances to individual 

units. Among other things, they argued 

that the modeling used for the proposal 

did not recognize certain non-economic 

factors that may cause individual units 

to operate differently than the model 

projects. Commenters also argued that 

EPA’s modeling does not capture all upto-date contracts and other economic 

arrangements made at the unit-level 

which may affect operational decisionmaking. Some of these commenters 

continued to support the use of an 

emission-based allocation approach, but 

urged EPA to use more up-to-date and 

specific unit-level data in its modeling 

projections. Others opposed the use of 

any emission-based allocation approach. 

EPA acknowledges that the model 

may not, at this time, capture all 

relevant operational decision factors for 

each individual unit. EPA also 

recognizes that there are unit-level 

details of operational decision-making 

and economic arrangements (such as 

certain contracts for electricity sales) 

that are private and thus unavailable to 

EPA on an ongoing basis for modeling 

purposes. EPA believes these potential 

omissions would not have a significant 

impact on EPA’s determination of 

significant contribution at the state 

level; however, EPA recognizes they 

could conceivably have a significant 

impact on projections at the individual 

unit level. EPA thus agrees with 

commenters that the unit-level emission 

projections from its modeling may not 

reflect all possible operational decisions 

at a given unit and are therefore not an 

appropriate proxy measure to use as a 

basis for allocating allowances to 

individual units. 

Many commenters also argued that, 

even if the emission projections could 

be adjusted to capture all known and 

up-to-date unit-level operational factors, 

EPA should not use any emission-based 

allocation approach. They argued that 

an emission-based approach should not 

be used because it is not fuel-neutral. 

That is to say, the type of fuel consumed 

significantly affects the emissions from, 

and therefore the allocation to, a given 

unit under an emission-based approach. 

Commenters argued that an approach 

that is not fuel-neutral effectively 

awards higher-emitting units. 

Commenters also argued that a projected 

emission-based approach should not be 

used because it is not control-neutral. In 

other words, whether or not a unit has 

installed controls would significantly 

affect the allocation for a given unit 

under an emission-based approach. 

Under an emission-based approach, 

controlled units receive significantly 

fewer allowances than uncontrolled 

units. Such an approach, commenters 

pointed out, effectively penalizes 

sources who have taken action to reduce 

emissions. 

EPA acknowledges that an emissionbased approach would not be fuelneutral or control-neutral. EPA notes 

that the DC Circuit rejected the fuel 

adjustment factors that were used in 

CAIR to adjust state budgets based on 

the type of fuel burned at each covered 

unit. North Carolina, 531 F.3d 918–21 

(rejecting use of fuel adjustments in 

setting state NOX budgets). While the 

proposal’s allocation methodology did 

not explicitly adopt ‘‘fuel adjustment 

factors’’ for allocation purposes, EPA 

recognizes that an emission-based 

allocation methodology effectively 

advantages or disadvantages units based 

on the type of fuel they combust. 

In addition, several commenters 

argued that the proposal’s emissionbased methodology would 

inappropriately reward the highest 

emitters under the program with more 

allowances than their lower-emitting 

counterparts would receive. EPA 

acknowledges that such a methodology 

would allocate more allowances to units 

whose emissions make up a larger share 

of the proposed Transport Rule 

programs’ state budgets. EPA notes that 

because any allocation patterns under 

the Transport Rule FIPs would be 

established in advance of covered 

sources’ compliance decisions (i.e., 

decisions regarding how much to emit 

under the programs), covered sources 


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cannot be ‘‘rewarded’’ by adjusting their 

future emissions. However, EPA notes 

commenters’ observations that the 

proposal’s methodology would reduce 

allocations to units that previously 

installed pollution control technology or 

invested in cleaner forms of generation 

in anticipation of CAIR. EPA concluded 

in review of these comments that the 

proposed Transport Rule’s allocation 

methodology unintentionally yielded 

this distributional outcome. EPA 

therefore considered alternative 

allocation methodologies described 

below. 

A substantial portion of the 

commenters who objected to the 

proposal’s emission-based allocation 

option urged EPA to consider historic 

heat input based approaches. EPA 

agreed it should accept comment on the 

use of historic heat input-based 

approaches and published a NODA to 

provide an opportunity for comment on 

two specific heat input options and the 

allocations that would result from 

application of those options to the 

proposed Transport Rule state budgets. 

ii. Heat Input Allocation Option 1 

The first heat input option presented 

by EPA in the NODA (‘‘Option 1’’) 

allocates allowances to units based 

solely on their historic heat input. 

Under this option, EPA would establish 

a 5-year historic heat input baseline for 

each covered unit and allocate 

allowances to sources at levels 

proportional to the each unit’s share of 

the total historic heat input at all 

covered units in that state. 

Numerous commenters supported the 

use of a heat-input based allocation 

methodology. These commenters stated 

that basing allocations on historic heat 

input has the following advantages over 

the proposal’s emission-based allocation 

methodology: 

(A) For certain types of units, historic 

heat input data may offer a better 

representation of unit-level operation 

than model projections of unit-level 

emissions; furthermore, for all units, 

historic heat input is typically 

represented by quality-assured data 

reported by sources from continuous 

emission monitoring systems, which 

strengthens its accuracy. 

(B) Historic heat input data are 

generally fuel-neutral in that they do not 

generally yield higher allocations for 

units burning or projected to burn 

higher emitting fuels. 

(C) Historic heat input data are 

generally emission-control-neutral in 

that they do not generally yield reduced 

allocations for units that installed or are 

projected to install pollution control 

technology. 

Many commenters also argued that a 

heat input-based allocation 

methodology should be used because, 

unlike the proposal’s emission-based 

methodology, a heat-input based 

methodology would be generally fuelneutral 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 

highest-quality 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 recreated 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 0.15 

lb/mmBtu)). In addition, commenters 

supported the reliance of heat input 

option 1 on continuous emission 

monitoring system (CEMS) data that are 

reported to EPA and certified by the 

source’s designated representative (DR) 

as accurate and complete. In addition, 

many commenters supported EPA’s use 

of historic data without further 

transformation by any calculation 

factors created by EPA. 

From a policy perspective, 

commenters highlighted the fuel 

neutrality and emission-control 

neutrality aspects of heat input option 1. 

They noted that this option does not, in 

contrast to the proposal’s emissionbased methodology, penalize a source, 

through a reduced allowance allocation, 

for having chosen a generation 

technology or emission control 

technology that was more favorable to 

public health and the environment. EPA 

agrees with these observations. The 

allocation pattern associated with this 

option does not advantage or 

disadvantage units based on either the 

fuel consumed or the presence or 

absence of a pollution control 

technology. In this respect, it is a 

neutral approach that does not ‘‘reward’’ 

high-emitting units or ‘‘penalize’’ lowemitting units, including, for example, 

those units on which pollution control 

technology was installed in anticipation 

of CAIR. 

EPA agrees with the aforementioned 

arguments from these commenters 

regarding the technical and policy 

merits of this heat input-based 

allocation methodology. EPA believes 

that the 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 

individual unit’s share of this historic 

heat input data is a straightforward, 

clear, and simple calculation to perform, 

such that EPA’s calculated allowance 

allocations under this approach can be 

relatively easily replicated. 

EPA also agrees with commenters that 

such data has previously supported 

allowance allocation procedures for 

highly successful program 

implementation of the ARP and the NOX

Budget Trading Program (NBP). Notably, 

Congress chose a heat input-based 

allocation approach when authorizing 

the ARP in title IV of the Clean Air Act, 

suggesting that Congress viewed heat 

input as a reasonable basis for 

allocation. Additionally, EPA’s selection 

of a heat input-based approach for the 

NBP was not legally challenged, 

implying that stakeholders generally 

saw a heat input-based approach as 

reasonable. 

EPA also agrees with comments 

observing that allocations made under 

this heat input approach do not 

advantage or disadvantage units based 

on their choice of fuel combustion or 

pollution control technology, and that 

allocations under this approach would 

thus be ‘‘fuel-neutral’’ and ‘‘controlneutral.’’ EPA also agrees with 

commenters that unlike the proposed 

rule’s emission-based methodology, this 

heat input methodology does not yield 

lower allocation to units that reduced 

emissions in advance of the Transport 

Rule relative to units that did not make 

such emission reductions. 

Other commenters objected to the use 

of a heat-input based allocation 

methodology. These commenters argued 

that the allocation pattern associated 

with a heat-input allocation 

methodology would yield ‘‘windfall 

profits’’—in the form of allowance 

allocations greatly in excess of likely 

emissions—for certain units, 

particularly with regard to SO2

allowance allocations for units 

combusting natural gas. EPA disagrees 

with the characterization of the excess 

allowances as ‘‘windfall profits.’’ 

Allocations based on heat-input alone 

are fuel-neutral and control-neutral. The 

characterization of the heat-input 

allocation methodology as creating 

‘‘windfall profits’’ for any unit is based 

on the assumption that all units should 


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80CAA section 302(y) defines the term ‘‘Federal 

implementation plan’’ as ‘‘a plan (or portion 

thereof) promulgated by the Administrator to fill all 

or a portion of a gap or otherwise correct all or a 

portion of an inadequacy in a State implementation 

plan, and which includes enforceable emission 

limitations or other control measures, means or 

techniques (including economic incentives, such as 

marketable permits or auctions of emissions 

allowances), and provides for attainment of the 

relevant national ambient air quality standard.’’ 

be allocated allowances based on 

emissions, not heat input. In arguing the 

heat-input approach creates a 

‘‘windfall’’ for some units, commenters 

are assuming that the allocation of 

allowances above a unit’s projected 

emissions constitutes a ‘‘windfall’’—a 

conclusion EPA does not accept. EPA 

believes that under market-based 

regulatory programs, it is appropriate to 

base initial allowance allocations on a 

neutral factor and allow the market to 

determine the least-cost pattern of 

emission reductions in each state to 

achieve the reductions that address the 

state’s significant contribution and 

interference with maintenance under 

the final Transport Rule programs. EPA 

disagrees that future allowance 

transactions (following a neutral-factor 

initial allocation) in response to these 

market forces can be characterized as 

‘‘windfall profits.’’ As explained above, 

EPA believes it is appropriate to allocate 

allowances based on a neutral factor. 

Commenters appear to ask EPA, instead 

of allocating based on a neutral factor, 

to consider the unit-level distributional 

impacts of each allocation methodology 

and to select an allocation methodology 

on the basis of equity. EPA does not 

believe it would be appropriate for the 

agency to pick an allocation 

methodology to achieve any particular 

distributional outcome as such 

considerations are not related to the 

statutory mandate of CAA section 

110(a)(2)(D)(i)(I). Instead, EPA believes 

it is appropriate to allocate allowances 

to sources covered by its trading 

programs based on a neutral factor. 

Furthermore, CAA section 

110(a)(2)(D)(i)(I) requires prohibition of 

certain emissions within a state (i.e., a 

state’s significant contribution and 

interference with maintenance). It does 

not direct EPA to use any particular 

methodology for allocating allowances 

under a trading program designed to 

ensure all such emissions are 

prohibited. As such, EPA believes it is 

appropriate to allocate allowances based 

on a neutral factor representing fossil 

energy content used to produce 

electricity. Detailed considerations of 

equity, as the DC Circuit reminded EPA, 

are not related to the statutory mandate 

of section 110(a)(2)(D)(i)(I). North 

Carolina, 531 F.3d 921. 

Some commenters objected to the use 

of a heat input-based approach by 

arguing that higher-emitting units 

would not receive an initial allocation 

sufficient to cover their emissions. EPA 

does not believe it is reasonable to 

expect initial allocations to cover each 

unit’s emissions under a trading 

program aimed at producing meaningful 

emission reductions. In its 

administration of prior trading programs 

such as the ARP and the NBP, EPA has 

made initial allowance allocations using 

a heat input-based approach, and 

virtually all covered sources have 

successfully complied at the end of each 

compliance period by making costeffective emission reductions, 

purchasing additional allowances 

through robust markets to cover 

emissions, or undertaking both types of 

activities. EPA disagrees with 

commenters’ arguments that allowance 

allocations should be used to 

compensate units with higher 

emissions. 

iii. Heat Input Allocation Methodology 

Option 2 

The second heat input option 

presented by EPA for public comment 

also would use historic heat input but 

would apply a constraint to unit-level 

allocations under certain circumstances. 

Specifically, under this option unitlevel allocations would not be allowed 

to exceed what EPA determines, based 

on historic emissions and other factors, 

to be the units’ ‘‘reasonably foreseeable 

maximum emissions.’’ 

To apply this constraint, EPA first 

would determine whether the allocation 

to a unit under an unconstrained heatinput methodology would exceed that 

unit’s maximum historic emissions of 

the relevant pollutant since 2003 ‘‘in 

order to reflect unit-level emissions 

before and after the promulgation of the 

CAIR’’ (76 FR 1115). Using this baseline 

would enhance the neutrality of the 

maximum historic emissions data 

because it would capture the highest 

emissions of the unit during that period 

regardless of what fuels it combusted or 

what pollution control devices were 

installed and used at any particular time 

during that period. In other words, a 

unit’s allocation would not be reduced 

due to a recent decision to switch fuels 

or install pollution controls. 

Second, for this option, EPA then 

would adjust that maximum historic 

emissions data by applying a ‘‘wellcontrolled 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. 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 ‘‘well-controlled 

emission rates.’’ Commenters also 

criticized the complexity of these 

modification factors in heat input 

option 2. While EPA believes both 

options represent viable approaches, the 

Agency agrees with commenters that the 

application of these factors increase the 

complexity of allocation determinations 

and would adjust unit-specific historic 

data by applying EPA-created factors 

generically determined for broad 

categories of units. 

Some commenters suggested that 

EPA’s application of these modification 

factors could also represent legal 

vulnerabilities for the Transport Rule. In 

particular, they were concerned that the 

capacity factors and well controlled 

emission rates presented as part of heat 

input option 2 could be perceived as 

arbitrary. While EPA does not agree that 

these modification factors are arbitrary, 

the Agency does recognize that 

application of such EPA-created generic 

factors in determining unit-specific 

allocations increases the complexity of 

the allocation approach and raises 

issues regarding whether such generic 

factors are appropriately applied to each 

individual unit. 

iv. General Comments on EPA’s 

Authority To Allocate Allowances 

Numerous commenters also noted 

that EPA has generally broad authority 

in selecting an allocation methodology 

under CAA sections 110(a)(2)(D)(i)(I) 

and 302(y).80 EPA agrees with 

commenters that the Agency has broad 

discretion in this area. Neither the CAA 

nor the D.C. Circuit Court’s opinion in 

North Carolina specifies a particular 

methodology that EPA must use to 

allocate allowances to individual units. 


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

prohibition of emissions ‘‘within the 

state’’ that significantly contribute to 

nonattainment or interfere with 

maintenance and gives states broad 

discretion to develop a control program 

in a SIP that achieves this objective. 

EPA has similarly broad discretion 

when issuing a FIP to realize this 

objective. Moreover, while the 

definition of FIP in CAA section 302(y) 

clarifies that a FIP may include 

‘‘enforceable emission limitations or 

other control measures, means or 

techniques (including economic 

incentives, such as marketable permits 

or auctions of emissions allowances),’’ 

this section does not require EPA to use 

any particular methodology to allocate 

allowances under a FIP trading program. 

In light of this lack of direction in the 

CAA concerning allowance allocation, 

EPA has broad discretion to select an 

allocation methodology that is 

reasonable and consistent with the goals 

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

The body of public comment makes it 

clear that no allocation option could be 

deemed satisfactory from the 

perspective of all stakeholders. Public 

comments from most states and 

industrial stakeholders with a 

substantial interest in how EPA 

allocates allowances under the 

Transport Rule FIPs expressed support 

for an historical heat input-based 

approach as opposed to the proposal’s 

emission-based approach. Most 

commenters favored this historical heat 

input data basis as the most sound and 

offered technical data corrections, 

which EPA considered and generally 

used in the final rule. EPA believes it is 

reasonable to select a heat input-based 

approach for the final Transport Rule 

because this approach is consistent with 

the rule’s statutory objectives and has 

been found, when implemented in prior 

trading programs, to be a credible, 

workable allocation approach. 

b. Final FIP Allocation Methodology 

After consideration of all comments, 

EPA decided to allocate allowances to 

individual units based on that units’ 

share of the state’s historic heat-input, 

but to ensure that no unit’s allocations 

exceed that unit’s historic emissions. 

EPA decided to use the allocation 

methodology originally presented as 

heat input option 2, modified in 

response to public comments. EPA 

decided to use heat input option 2 but 

without the application of the 

‘‘reasonable 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 existing-unit 

allowance allocation under the 

Transport Rule should not generally 

advantage or disadvantage units based 

on the selection of fuels consumed or of 

pollution controls installed at a given 

unit in anticipation of either the Clean 

Air Interstate Rule or the Transport 

Rule, i.e., fuel or control decisions taken 

from 2003 onward. An approach that 

does not advantage or disadvantage 

units in this way avoids allocating in a 

way that would effectively penalize 

units that have already invested in 

cleaner fuels or other pollution 

reduction measures that will continue to 

deliver important emission reductions 

under this rulemaking. The approach 

selected in the final rule generally does 

not penalize such units and is thus 

generally fuel-neutral and controlneutral in its allocation determinations. 

• EPA finds that the selected 

approach maximizes transparency and 

clarity of allowance allocations. EPA 

has already made public the historic 

heat input and historic emissions data 

on which this approach is based, and its 

application to calculate unit-level 

allocations in each state under that 

state’s emission budgets finalized in this 

Transport Rule can be relatively easily 

replicated. 

• EPA finds that quality-assured 

historic CEMS-quality data used to 

implement this approach represent the 

most technically superior data available 

to EPA at the time of this rulemaking for 

calculating unit-level allocations. The 

selected approach relies on unmodified 

historic data reported directly by the 

vast majority of covered sources, whose 

designated representatives have already 

attested to the validity and accuracy of 

this data. EPA agrees with commenters 

that allowance allocations should be 

based on quality-assured data to the 

maximum extent possible. This 

approach uses the most accurate data 

currently available to EPA. 

• Heat-input based approaches were 

used to allocate allowances under both 

the NOX Budget Trading Program and 

the Acid Rain Program. Allocation 

under these programs was readily and 

easily administered, and the programs 

achieved or exceeded their 

environmental goals. The selected 

approach’s use of heat input as a basis 

for allocations builds on prior legislative 

and administrative approaches to 

allowance allocations for trading 

programs. 

• EPA also finds that the selected 

approach’s addition of a constraint to 

heat input-based allocations where such 

allocations would otherwise exceed a 

unit’s maximum historic emissions is a 

reasonable extension of a heat inputbased allocation approach. The 

Transport Rule trading programs are 

established to achieve overall emission 

reductions in each covered state. As a 

group, covered sources within each state 

must make the necessary reductions 

under these programs. In light of each 

program’s goal to reduce each state’s 

overall emissions, it is logical and 

consistent with that goal that the 

starting point for each source under 

these programs—i.e., the initial 

allocations of shares of the state budget 

to covered units—be an amount of 

allowances no greater than each unit’s 

maximum historic emissions. Under the 

trading programs, any source may emit 

a ton of SO2 or NOX for which it holds 

a corresponding allowance, which it 

may acquire either by initial allocation 

or by subsequent purchase, to the extent 

consistent with the assurance provisions 

(discussed elsewhere in this preamble) 

that ensure achievement of the requisite 

overall reductions in each state. 

Consequently, the initial allocations to 

the units at each source are the starting 

point for each source’s efforts to comply 

with the allowance-holding and 

assurance provision requirements, but 

do not determine the source’s strategies 

for compliance and ultimate level of 

emissions. EPA believes that a starting 

point of unit-level heat input-based 

allocations constrained not to exceed 

each specific units’ maximum historic 

emissions is reasonable and consistent 

with the program goals of reducing 

overall emissions in each state: Each 

existing unit is allocated an amount that 

either reflects reduced unit emissions or 

does not exceed historic emissions, and, 

from that starting point, the units, as a 

group, reduce overall emissions to the 

level required for each state. Conversely, 

EPA believes that a starting point 

allocating some units more than they 

have ever emitted would be illogical in 

programs aimed at reducing overall 

emissions. 

EPA believes that this selected 

allocation methodology for the final 

Transport Rule FIPs is within its 

authority under the Clean Air Act. 

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


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requires that emissions ‘‘within a state’’ 

that significantly contribute to 

nonattainment or interfere with 

maintenance in another state be 

prohibited. In the final Transport Rule, 

EPA analyzed each individual state’s 

significant contribution and interference 

with maintenance and calculated 

budgets that represent each state’s 

emissions after the elimination of 

prohibited emissions in an average year. 

The methodology used to allocate 

allowances in a state budget to 

individual units in the state has no 

impact on that state’s budget or on the 

requirement that the state’s emissions 

not exceed that budget plus variability. 

Regardless of the allocation 

methodology used, the state’s 

responsibility for eliminating its 

significant contribution and interference 

with maintenance remains unchanged. 

This is reflected by the fact that 

allocations under each state’s budget, 

regardless of how they are made, cannot 

change that state’s budget. In sum, the 

allocation methodology has no impact 

on the final rule’s ability to satisfy the 

statutory mandate of CAA section 

110(a)(2)(D)(i)(I) to eliminate significant 

contribution to nonattainment and 

interference with maintenance. 

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, consistency with 

program goals, and successful 

experience in previous trading programs 

are reasonable factors on which to base 

the selection of an allowance allocation 

methodology for existing units for the 

final Transport Rule. EPA believes that 

the transparency and clarity of this 

allocation approach builds credibility 

with the public that the government is 

distributing a public resource—i.e., 

allowances—precisely as stated in this 

rulemaking, with clear execution that 

can be relatively easily verified. 

EPA also believes that the final 

Transport Rule’s heat input-based 

approach for existing units is consistent 

with the goals of the Clean Air Act 

because it allocates allowances to 

existing units on the basis of a neutral 

factor that does not advantage or 

disadvantage a unit based on what fuel 

the unit burns or whether or not a unit 

has installed controls in anticipation of 

these regulations. In contrast, 

allocations under the proposal’s 

emission-based methodology would 

give a greater share of allowances to 

units with higher emission rates, which 

are generally responsible for a greater 

share of a state’s total emissions. 

Because these higher-emitting rate units 

are generally responsible for a greater 

share of emissions, it follows that they 

are also responsible for a greater share 

of a state’s significant contribution to 

nonattainment and interference with 

maintenance. The proposal’s emissionbased allocation methodology would 

disadvantage one of two otherwise 

identical existing units if it invested in 

emission reductions in anticipation of 

the Clean Air Interstate Rule or this final 

Transport Rule. 

The heat-input allocation 

methodology selected for the final 

Transport Rule does not have this flaw. 

In contrast to the proposal’s emissionbased allocation approach, the heat 

input allocation methodology selected 

by EPA yields a smaller proportion of 

allowances relative to emissions to 

higher-emission-rate units and a higher 

proportion of allowances relative to 

emissions to lower-emission-rate units. 

For example, assume that in a state with 

two units and in a baseline year, Unit 

A combusts 100 mmBtu of heat input 

and emits 1,000 tons while Unit B 

combusts 100 mmBtu of heat input and 

emits only 500 tons. Assume also that 

this state’s future Transport Rule 

emissions budget for this pollutant is 

only 500 tons. Because Units A and B 

each make up an even share of historic 

heat input for the state, the final rule’s 

heat input-based approach would 

allocate the same share of allowances 

(250 tons) to each unit. In this example, 

Unit A’s initial allocation of 250 is a 

smaller proportion of its historic 

emissions (25 percent of its baseline 

1,000-ton emissions), while Unit B’s 

initial allocation of 250 is a larger 

proportion of its historic emissions (50 

percent of its baseline 500-ton 

emissions). Therefore, Unit B’s ability to 

emit fewer tons per mmBtu of heat 

content used for generating electricity 

(as compared with Unit A) results in 

Unit B receiving a larger proportion of 

its historic emissions as an initial 

allocation share than Unit A receives. 

This relative distributional pattern 

yielded is consistent with the goals of 

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

under this distribution, higher-emitting 

units, which are responsible for a 

greater share of the state’s significant 

contribution to nonattainment and 

interference with maintenance, would 

require relatively more allowances in 

order to cover their pre-existing 

emissions than would lower-emitting 

units. EPA believes this initial 

allocation pattern is an appropriate 

reflection of the goals of CAA section 

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

The heat input-based allowance 

methodology selected by EPA is fuelneutral, 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 inputbased allocation methodology in this 

rule. 

In addition, this allocation 

methodology is similar to an outputbased allocation approach, which would 

base allocations on the quantity of 

electricity generated (rather than energy 

content combusted) and would also be 

fuel-neutral, control-neutral, and able to 

reward generation units that operate the 

most efficiently. Many state and 

industry commenters advocated using 

an output-based approach due to its 

reported strong value in promoting 

efficiency. However, at this time EPA 

does not have access to unit-level 

output 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 inputbased approach under the Transport 

Rule in part due to its ability to serve 

as a reasonable proxy for an outputbased standard using the most qualityassured data that EPA has to date. 

In the NODA, EPA noted that final 

state budgets and allocations may differ 

from the proposed budgets and 

allocations because EPA was still in the 

process of updating its emission 

inventories and modeling in response to 

public comments, including comments 

on IPM. Thus, unit-level allocations in 

the NODA provided an indication of the 

proportional share of a state’s budget 

that would be allocated to individual 

existing units if the alternative 

methodologies were used. The 

allocations made final today are based 

on budgets that reflect the updated 

modeling and comments received 

during the comment period. 

c. Calculation of Existing Unit 

Allocations Under the Final Transport 

Rule FIPs 

Allocations under this final 

methodology for each existing unit are 

determined by applying the following 

steps. 

1. For each unit in the list of potential 

existing Transport Rule units, annual 

heat input values for the baseline period 

of 2006 through 2010 are identified 

using data reported to EPA or, where 

EPA data is unavailable, using data 

reported to the Energy Information 

Administration (EIA). For a baseline 

year for which a unit has no data on 

heat input (e.g., for a baseline year 

before the year when a unit started 

operating), the unit is assigned a zero 

value. (Step 2 explains how such zero 

values are treated in the calculations.) 

The allocation method uses a 5-year 


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81Existing- or new-unit allocations drawn from 

the budget of the relocated unit’s original state are 

replaced by new unit set-aside allocations from the 

budget of the unit’s relocation state in order to 

generally ensure that allocations are drawn from the 

correct state budget. 

baseline to approximate a unit’s normal 

operating conditions over time. 

2. For each unit, the three highest, 

non-zero annual heat input values 

within the 5-year baseline are selected 

and averaged. Selecting the three 

highest, non-zero annual heat input 

values within the five-year baseline 

reduces the likelihood that any 

particular single year’s operations 

(which might be negatively affected by 

outages or other unusual events) would 

determine a unit’s allocation. If a unit 

does not have three non-zero heat input 

values during the 5-year baseline 

period, EPA averages only those years 

for which a unit does have non-zero 

heat input values. For example, if a unit 

has only reported data for 2008 and 

2009 among the baseline years and the 

reported heat input values are 2 and 4 

mmBtus, respectively, then the unit’s 

average heat input used to determine its 

pro-rata share of the state budget is 

(2+4)/2 = 3. 

3. Each unit is assigned a baseline 

heat input value calculated as described 

in step 2, above, referred to as the ‘‘3- 

year average heat input.’’ 

4. The 3-year average heat inputs of 

all covered existing units in a state are 

summed to obtain that state’s total ‘‘3- 

year average heat input.’’ 

5. Each unit’s 3-year average heat 

input is divided by the state’s total 3- 

year average heat input to determine 

that unit’s share of the state’s total 3- 

year average heat input. 

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

3-year average heat input is multiplied 

by the existing-unit portion of the state 

budget (i.e., the state budget minus the 

state’s new unit set-aside and, if 

applicable, minus the Indian country 

new unit set-aside) to determine that 

unit’s initial allocation. 

7. An 8-year (2003–2010) historic 

emissions baseline is established for 

SO2, NOX, and ozone-season NOX based 

on data reported to EPA or, where EPA 

data is unavailable, based on EIA data. 

This approach uses this 8-year historic 

emissions baseline in order to capture 

the unit-level emissions before and after 

the promulgation of CAIR. 

8. For each unit, the maximum annual 

historic SO2 and NOX emissions are 

identified within the 8-year baseline. 

Similarly, the maximum ozone season 

NOX emissions from the 8-year baseline 

for each unit are identified. These 

values are referred to as the ‘‘maximum 

historic baseline emissions’’ for each 

unit. 

9. If a unit has an initial historic heatinput based allocation (as determined in 

step 6) that exceeds its maximum 

historic baseline emissions (as 

determined in step 8), then its allocation 

equals the maximum historic baseline 

emissions for that unit. 

10. The difference (if positive) under 

step 9 between a unit’s historic heatinput-based allocation and its 

‘‘maximum historic baseline emissions’’ 

is reapportioned on the same basis as 

described in steps 1 through 6 to units 

whose historic 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 

ton using conventional rounding. 

Table VI.D–1 below provides an 

illustrative application of the steps 1–10 

in a hypothetical state. 

TABLE VI.D–1—DEMONSTRATION OF ALLOCATIONS USING FINAL ALLOCATION METHODOLOGY IN A THREE-UNIT STATE

WITH AN 80-TON STATE BUDGET

Steps 1–6 Steps 7, 8, 9 Steps 1–9 

reiterated 

Step 10 

Initial historic 

heat inputbased 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. A ‘‘new unit’’ may be any of the 

following: (1) A covered unit 

commencing commercial operation on 

or after January 1, 2010; (2) any unit that 

becomes a covered unit by meeting 

applicability criteria subsequent to 

January 1, 2010; (3) any unit that 

relocates into a different state covered 

by the Transport Rule; 81 and (4) any 

existing covered unit that stopped 

operating for 2 consecutive years but 

resumes commercial operation at some 

point thereafter. 

The proposed Transport Rule would 

have required that owners and operators 

initially request allowances from the 

new unit set-aside when the unit first 

became eligible for an allocation. EPA 

now believes that it can identify which 

units become eligible and when they 

become eligible, based on information 

provided in other submissions (e.g., 

certificates of representation, 

monitoring system certifications, and 

quarterly emissions reports) that the 

final rule already requires such units to 

make to EPA. EPA concludes that 

requiring owners and operators to 

submit requests of new unit set-aside 

allocations would impose an 

unnecessary burden on the owners and 

operators, as well as on EPA, and 

therefore EPA has removed this 

requirement in the final rule. 

The following sections describe the 

methodology in the final Transport Rule 

for allocating to new units, how EPA 

determined the size of new unit setasides in the final rule, and how EPA 

has provided for allocations to new 

units that locate in Indian Country. 

a. New Unit Allocation Methodology 

The proposal’s new unit allocation 

methodology did not provide any 

allocation for a new unit’s first control 

period of commercial operation. Some 

commenters expressed concern about 

the lack of new unit allocations the first 

year of commercial operation. In order 

to address this concern, EPA is 

modifying the new unit allocation 

methodology in this final rule to include 

allocations to new units for the first 

control period in which the units are in 

commercial operation, as well as for 

control periods in subsequent years. 


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The final rule’s allocation to new 

units is performed in two ‘‘rounds.’’ The 

first round is the same as the new unit 

allocation procedures in the proposal 

(except for elimination of the 

requirements that owners and operators 

request the allocations) and occurs 

during the control period for which the 

allocations are made. These first round 

allocations are based on new unit 

emissions during the prior control 

period and are recorded in allowance 

accounts in the Allowance Management 

System for the units by August 1 of each 

control period. For example, for the 

2012 vintage year, ‘‘first-round’’ 

allocations would be made to new units 

by August 1, 2012 based on their 

emissions in the 2011 control period (as 

monitored and reported in accordance 

with Part 75 of the Acid Rain Program 

regulations). If the new unit set-aside is 

insufficient to accommodate first round 

allocations reflecting all new units’ 

prior control period emissions, the first 

round allocations are made pro rata to 

new units based on their share of total 

new unit emissions in the prior control 

period. 

The second round of allocations 

accommodates new units that come 

online during the control period for 

which the allocations are made and did 

not therefore receive any allocation in 

the first round. The second round also 

accommodates new units that come 

online partway into the prior control 

period and therefore received an 

allocation in the first round that did not 

extend to cover operations in a full 

control period. This second round of 

new unit allocation is therefore 

applicable only to new units coming 

online either during the control period 

of the allocation or during the control 

period immediately prior. New units 

coming online earlier than the previous 

control period only receive first-round 

allocations from the new unit set-asides, 

as first-round allocations to those units 

are based on operational data spanning 

an entire control period. 

Second-round allocations are based 

on new unit emissions during the same 

control period as the vintage year of the 

allowances allocated. For example, for 

the 2012 vintage year, ‘‘second-round’’ 

allocations are based on the difference 

between the new unit’s emissions in the 

2012 control period and the new unit 

allocation (if any) that the unit received 

in the first round of allocations. For a 

unit coming online in 2012, this amount 

equals its total emissions during the 

2012 control period. For a unit coming 

online in 2011, this amount equals its 

incremental emissions in 2012 beyond 

its emissions in 2011, as such a unit 

would have already received a firstround allocation from the new unit setaside based on its emissions in 2011. 

Second-round allocations are recorded 

in allowance accounts by November 15 

for the NOX ozone season trading 

program (ahead of the December 1 

compliance deadline) and by February 

15 of the following calendar year for 

NOX and SO2 annual trading programs 

(ahead of the March 1 compliance 

deadline). 

This methodology only allocates in 

the second round whatever allowances 

remain in the new unit set-asides after 

the first-round allocations have been 

recorded. If the new unit set-aside 

available for second round allocations is 

insufficient to accommodate allocations 

based on the difference between control 

period emissions and any first round 

allocations for the units involved, then 

the second round allocations are made 

pro rate to the new units based on their 

share of the total of such differences. 

b. Determination of New Unit SetAsides 

The proposed Transport Rule 

identified new units using a threshold 

online date of January 1, 2012, whereas 

the final Transport Rule uses a 

threshold online date of January 1, 2010. 

As explained above, EPA adjusted this 

cutoff date because the final Transport 

Rule’s allocation methodology for 

existing units requires that EPA possess 

at least 1 full year of historic data in 

order to calculate allocations. As a 

consequence, EPA recognizes that the 

proposal’s methodology to determine 

the size of the new unit set-asides based 

only on new EGUs forecast by the model 

would fail to account for known EGUs 

that have come online, or are planned 

to come online, after January 1, 2010. 

Therefore, EPA has modified its 

approach to determining the size of the 

new unit set-asides in the final rule to 

account for both ‘‘potential’’ units (i.e., 

those that are not yet planned or under 

construction but are projected by 

modeling to be built) and ’’planned’’ 

units (i.e., those that are known units 

with planned online dates after January 

1, 2010). EPA uses the distinction 

between ‘‘potential’’ and ‘‘planned’’ 

new units to determine the ultimate size 

of each state’s new unit set-aside (as a 

percentage of that state’s budgets for 

each pollutant covered); however, the 

new unit allocation methodology 

described above applies the same to 

‘‘potential’’ and ‘‘planned’’ new units. 

The first step of EPA’s analysis to 

determine the new unit set-asides 

accounts for likely future emissions 

from potential units, and its 

methodology is taken directly from the 

Transport Rule proposal but reflects 

updated modeling (see ‘‘Allowance 

Allocation to Existing and New Units 

Under the Transport Rule Federal 

Implementation Plans’’ TSD for detailed 

findings). This analysis informed EPA’s 

decision to establish a minimum new 

unit set-aside size of 2 percent of each 

state’s budget for each pollutant that is 

configured to accommodate future 

emissions from potential units. 

For the final rule, EPA augmented its 

new unit set-aside determination to 

account for ‘‘planned’’ units through an 

additional step. Because the location of 

these ‘‘planned’’ units is known and 

identified in EPA modeling, this second 

step is a state-specific modification of 

the size of the new unit set-asides. That 

is, EPA only increased new unit setasides above the 2 percent minimum 

established in the first step for states 

that had additional known units coming 

online between January 1, 2010, and 

January 1, 2012. 

The increases made to the new unit 

set-asides for these planned units reflect 

the projected emissions from these 

units. Therefore, if the expected 

emissions of a given pollutant from all 

‘‘planned’’ new units in a given state 

were equal to 3 percent of that state’s 

budget for that pollutant, then EPA 

added that amount to the base 2 percent 

new unit set-aside (creating a 

hypothetical new unit set-aside of 5 

percent for that pollutant in that state). 

See ‘‘Allowance Allocation to Existing 

and New Units Under the Transport 

Rule Federal Implementation Plans’’ 

TSD for detailed results showing how 

EPA determined the size of each new 

unit set-aside reflecting the application 

of both of the steps described above. 

This approach to determining the size of 

state new unit set-asides is a logical 

outgrowth of the proposal, the NODA on 

allowance allocations, and updated 

modeling results. In fact, EPA received 

comments that using a January 1, 2010 

cutoff date for distinguishing between 

existing and new units would result in 

the new unit set-aside, as proposed, 

being insufficient to meet the needs of 

units already under construction. EPA 

believes that the approach adopted in 

the final rule results in new unit setasides that reasonably accommodate the 

foreseeable emissions from both 

planned and potential new units in each 

state. 

The new unit allocation percentages 

for each state are shown in Table 

VII.D.2–1. 


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TABLE VII.D.2–1—PERCENTAGE OF STATE EMISSION BUDGETS FOR ALLOWANCES IN STATE NEW UNIT SET-ASIDES

Annual SO2 Annual NOX Ozone-season 

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% 

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% ........................

c. Procedures for Allocating New Unit 

Set-Asides 

For the first round of new unit setaside allocations, the Administrator will 

promulgate a notice of data availability 

informing the public of the specific new 

unit allocations and provide an 

opportunity for submission of objections 

on the grounds that the allocations are 

not consistent with the requirements of 

the relevant final rule provisions. A 

second notice of data availability will 

subsequently be promulgated in order to 

make any necessary corrections in the 

specific new unit allocations. As 

discussed elsewhere in this preamble, 

the final rule establishes a different 

schedule for promulgation of these 

notices of data availability than the 

proposed rule. In particular, a single set 

of deadlines (i.e., for the first notice in 

the first round of allocations, June 1 of 

the year for which the new unit 

allocations are described in the notice 

and, for the second notice of the first 

round, August 1 of that year) for 

promulgation of the notices is 

established for all of the Transport Rule 

trading programs. EPA believes that 

these deadlines will provide sufficient 

time for EPA to obtain final emissions 

data for the prior year for the units 

involved and to calculate the allocations 

and promulgate the notices. Further, the 

approach of using the same deadline for 

all of the Transport Rule trading 

programs will simplify EPA’s 

implementation and reduce the 

complexity of the process for source 

owners and operators. 

For the second round of new unit setaside allocations, the Administrator will 

also promulgate two notices of data 

availability. However, the deadlines for 

the notices differ for the NOX ozone 

season trading program and for the SO2

and NOX annual trading programs 

because control period emissions data 

(used in making second round 

allocations) become available sooner, 

and the compliance deadline for 

holding allowances covering emissions 

is sooner, in the NOX ozone season 

trading program. The control period in 

the NOX ozone season program ends on 

September 30, and fourth quarter 

emissions reports must be submitted to 

EPA by October 30, while the control 

periods in the SO2 and NOX annual 

programs end on December 31 and 

fourth quarter emission reports are due 

by January 30. Further, in order for the 

second round allocations to be available 

to be used for compliance with the 

allowance-holding requirement, the 

second round needs to be completed 

before the compliance dates, which are 

December 1 in the NOX ozone season 

program and March 1 in the SO2 and 

NOX annual programs. Consequently, 

for the NOX ozone season program the 

Administrator will promulgate by 

September 15 a notice of data 

availability identifying the units eligible 

for second round allocations and by 

November 15 a second NODA of the list 

of eligible units and their second round 

allocations, which will also be recorded 

in the allowance accounts by that date. 

The comparable deadlines for the SO2

and NOX annual programs are December 

15 and February 15. EPA believes that 

these deadlines will provide sufficient 

time for EPA to identify the units and 

obtain their needed emissions data and 

to calculate the allocations and 

promulgate the notices. 

d. Addition of Allowances to New Unit 

Set-Asides 

As discussed elsewhere in this 

preamble, EPA proposed that, if a unit 

with an existing-unit allocation does not 

operate for 3 consecutive years, the 

allowances that would otherwise have 

been allocated to that unit, starting in 

the seventh year after the first year of 

non-operation, would be allocated to the 

new unit set-aside for the state in which 

the retired unit is located. EPA is 

retaining this provision in the final rule 

but is changing the time of nonoperation to 2 years and the time of 

allowance allocation to a non-operating 

unit to 4 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 


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encourage the operation of new units. 

One commenter suggested that 

allowance allocations should cease after 

3 years of non-operation because the 

financial incentive gained from 

receiving allowances beyond the 3-year 

period is insignificant relative to 

operating and fuel costs. Another 

commenter said that providing 

allowances to non-operating units is 

unnecessary and distorts the market. 

In addition to increasing the size of 

the new unit set-aside in this final rule, 

as described above, EPA is terminating 

existing unit allocations starting in the 

fifth year after the unit does not operate 

for 2 consecutive years and reallocating 

to the new unit set-aside the allowances 

that the unit otherwise would have 

received for the fifth and subsequent 

years in order to make them available 

for new units in the state. This approach 

allows the new unit set-asides to grow 

over time. 

e. Allocations to New Units Locating in 

Indian Country 

EPA received several comments on 

the proposed rule that it did not 

explicitly address the distribution of 

allowances to potential new units built 

in Indian country. EPA recognized this 

concern and requested comment on this 

topic in the January 7, 2011 NODA. 

In the final rule, EPA is providing a 

mechanism to make allowances 

available in the future for new units 

built in Indian country. The final rule 

establishes an Indian country new unit 

set-aside for each pollutant in each state 

whose borders encompass Indian 

country (i.e., Florida, Iowa, Kansas, 

Louisiana, Michigan, Minnesota, 

Mississippi, Nebraska, New York, North 

Carolina, South Carolina, Texas, and 

Wisconsin). EPA will retain 

administration of these Indian country 

new unit set-asides as part of the 

Transport Rule trading programs 

whether or not a Transport Rule state 

elects to modify or replace the Transport 

Rule FIPs through approved SIP 

revisions. EPA does not create Indian 

country new unit set-asides for states 

lacking Indian country within their 

borders. 

EPA determined the size of each 

Indian country new unit set-aside by 

calculating the ratio of square mileage of 

Indian country to the square mileage of 

the state within whose borders Indian 

country is located. This calculation 

yielded a maximum percentage of 5 

percent when assessing all of the states 

encompassing Indian country subject to 

the final Transport Rule; this is referred 

to as the ‘‘5 percent Indian country 

factor’’ below. To determine the 

maximum percentage, EPA used the 

American Indian Reservations/Federally 

Recognized Tribal Entities dataset, 

which contains data for the 562 

federally recognized tribal entities in the 

contiguous U.S. and Alaska. EPA 

accessed the data to analyze the 

Transport Rule region and compare the 

square miles of Indian country with the 

square miles of the Transport Rule state 

that includes the Indian country. EPA 

then took the highest percentage as the 

number to be applied across all states 

with Indian country to determine the 

size of the Indian country new unit setaside pertinent to that state’s budgets 

under the Transport Rule. EPA chose to 

use the maximum percentage (5 percent) 

from the Indian country analysis to 

determine the Indian country set-aside 

for each state on the basis that this 

approach would reserve a reasonable 

number of allowances from each state’s 

budget for potential allocation to new 

units that may locate in Indian country 

within that state’s borders. Any 

allowances from the Indian country new 

unit set-aside that are not allocated in a 

given control period are redistributed 

into the state’s new unit set-aside. As 

discussed above, any allowances not 

allocated from that new unit set-aside 

are redistributed to existing units based 

on the existing units’ share of the total 

existing unit allocations. 

To calculate the size of each tribal 

new unit set-aside, EPA applied this 5 

percent Indian country factor to the 

portion of the state’s new unit set-aside 

originally determined by accounting for 

‘‘potential’’ new units, which as 

described above was set at 2 percent of 

each pollutant’s budget in each state. 

Therefore, the Indian country new unit 

set-aside is 5 percent of 2 percent of a 

state’s budget, or 0.1 percent of that total 

state budget. EPA did not apply the 5 

percent Indian country factor to the 

state-specific planned unit portion of 

each state’s new unit set-aside because 

the planned unit portion is determined 

using projected emissions from specific, 

known units coming online after 

January 1, 2010, and none of these 

known units are located in Indian 

country. 

The Indian country new unit setasides in the following Transport Rule 

states with Indian Country are shown in 

Table VII.D.2–2. 

TABLE VII.D.2–2—NEW UNIT SET-ASIDE ALLOWANCES FOR INDIAN COUNTRY

[Tons] 

SO2

2012– 

2013 

SO2

2014 

and 

beyond 

Annual 

NOX

2012– 

2013 

Annual 

NOX

2014 

and 

beyond 

Ozoneseason 

NOX

2012– 

2013 

Ozoneseason 

NOX

2014 

and 

beyond 

Florida .............................................................................................................................. ............ ............ ............ ............ 28 28 

Iowa .................................................................................................................................. 107 75 38 38 ............ ............

Kansas ............................................................................................................................. 42 42 31 26 ............ ............

Louisiana .......................................................................................................................... ............ ............ ............ ............ 13 13 

Michigan ........................................................................................................................... 229 144 60 58 ............ ............

Minnesota ......................................................................................................................... 42 42 30 30 ............ ............

Mississippi ........................................................................................................................ ............ ............ ............ ............ 10 10 

Nebraska .......................................................................................................................... 65 65 26 26 ............ ............

New York ......................................................................................................................... 27 19 18 18 8 8 

North Carolina .................................................................................................................. 137 58 51 42 22 18 

South Carolina ................................................................................................................. 89 89 32 32 14 14 

Texas ............................................................................................................................... 244 244 134 134 63 63 

Wisconsin ......................................................................................................................... 80 40 32 30 ............ ............


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82A group of one or more sources and units in 

a state has a common designated representative 

where the same individual is authorized as the 

designated representative (not the alternate 

designated representative) for that group of sources 

and units as of April 1 immediately following the 

allowance transfer deadline for the control period 

involved. 

Under the FIPs, EPA allocates 

allowances from Indian country new 

unit set-asides in essentially the same 

manner as it allocates allowances from 

state new unit set-asides. The approach 

for identifying, and determining the 

number of allowances allocated to, new 

units in Indian country is the same as 

the approach for identifying and 

determining allocations for non-Indian 

country new units covered by the state 

new unit set-aside, and allocations are 

made in two rounds using the same 

schedules for promulgation of notices of 

data availability. However, as discussed 

above, unallocated allowances in the 

Indian country set-asides are handled 

differently from unallocated allowances 

in the state new unit set-asides in that 

unallocated Indian country new unit 

set-aside allowances are first transferred 

back into the state new unit set-aside 

and then, if still not allocated to new 

units, are distributed to existing units in 

the state. EPA believes that the abovedescribed approach in establishing and 

handling the Indian country new unit 

set-asides and state new unit set-asides 

is a reasonable way of making a 

sufficient amount of allowances 

available for new units in the state and 

Indian country located in the state and 

ensuring that the entire state budget is 

available to either new or existing units 

in the state and Indian country. EPA 

retains administration of these Indian 

country new unit set-asides (and, of 

course, the portions of state budgets that 

comprise these set-asides) as part of the 

Transport Rule trading programs even if 

a state elects to modify or replace the 

Transport Rule FIPs through approved 

SIP revisions. EPA continues to manage 

and distribute the Indian country new 

unit set-aside allowances in the same 

manner as under the FIPs. Unallocated 

allowances in the Indian country new 

unit set-aside will be returned to the 

portion of the state budget allocated 

under the approved SIP’s allocation 

provisions. EPA believes that this 

approach is reasonable because EPA, 

rather than the states, has the authority 

and responsibility of administering the 

Transport Rule with regard to new units 

that locate in Indian country. 

E. Assurance Provisions 

To ensure that the FIPs require the 

elimination of all emissions that EPA 

has identified that significantly 

contribute to nonattainment or interfere 

with maintenance within each 

individual state, the Agency is adopting 

assurance provisions in addition to the 

requirement that sources hold 

allowances sufficient to cover their 

emissions. These assurance provisions 

limit emissions from each state to an 

amount equal to that state’s trading 

budget plus the variability limit for that 

state (i.e., the state assurance level). As 

discussed in section VI of this preamble, 

this variability limit takes into account 

the inherent variability in baseline EGU 

emissions and recognizes that state 

emissions may vary somewhat after all 

significant contribution to 

nonattainment and interference with 

maintenance are eliminated. This 

approach also provides sources with 

flexibility to manage growth and electric 

reliability requirements, thereby 

ensuring the country’s electric demand 

will be met, while meeting the statutory 

requirement of eliminating significant 

contribution to nonattainment and 

interference with maintenance. 

Starting in 2012, EPA is establishing, 

as part of the FIPs, limits on the total 

emissions that may be emitted from 

EGUs at sources in each state. For any 

single year, the state’s emissions must 

not exceed the state budget with the 

variability limit allowed for any single 

year for that state (i.e., the state’s 1-year 

variability limit). In other words, in 

addition to covered sources being 

required to hold allowances sufficient to 

cover their emissions, the total sum of 

EGU emissions in a particular state 

cannot exceed the state budget with the 

state’s 1-year variability limit in any 1 

year (i.e., the state’s assurance level). 

EPA is not finalizing 3-year variability 

limits that were included in the 

proposal for the reasons explained 

previously in section VI.E of this 

preamble. The state budgets, variability 

limits, and state assurance levels for 

each state are shown in Tables VI.F–1, 

VI.F–2 and VI.F–3 in section VI.F of this 

preamble. The basis for the variability 

limits is also described in section VI.E 

of this preamble. Additional details may 

be found in the Power Sector Variability 

Final Rule TSD in the docket to this 

rule. 

To implement this requirement, EPA 

first evaluates whether any state’s total 

EGU emissions in a control period 

exceeded the state’s assurance level. If 

any state’s EGU emissions in a control 

period exceed the state assurance level, 

then EPA applies additional criteria to 

determine which owners and operators 

of units in the state will be subject to an 

allowance surrender requirement. In 

applying the additional criteria, EPA 

evaluates which groups of units at the 

common designated representative (DR) 

level had emissions exceeding the 

respective common DR’s share of the 

state assurance level (regardless of 

whether the source had enough 

allowances to cover its emissions) 

during the control period.82

The requirement that owners and 

operators surrender allowances under 

the assurance provisions will be 

triggered only if two criteria are met: (1) 

The group of sources and units with a 

common DR are located in a state where 

the total state EGU emissions for a 

control period exceed the state 

assurance level; and (2) that group with 

the common DR had emissions 

exceeding the respective DR’s share of 

the state assurance level. The share of 

the assurance penalty borne by the 

owners and operators will be based on 

the amount by which the total emissions 

for the units in the group exceed the 

common DR’s share of the state 

assurance level as a percentage of the 

total calculated for all such groups of 

sources and units in the state. Thus, the 

owners and operators of each such 

group of sources and units must 

surrender an amount of allowances 

equal to the excess of state EGU 

emissions over the state assurance level 

multiplied by the owners’ and 

operators’ percentage and multiplied by 

two (to reflect the penalty of two 

allowances for each ton of the state’s 

excess EGU emissions). See Table VII.E– 

1 below for an illustrative example. 

This approach in the final rule of 

implementing the assurance provisions 

on a common designated representative 

basis contrasts with the approach in the 

proposed rule of implementing the 

assurance provisions on an owner basis. 

In the January 7, 2011 NODA, EPA 

requested comment on the alternative of 

basing the assurance provision penalty 

using common designated 

representatives, and some commenters 

supported this alternative. The common 

designated representative approach is 

simpler and avoids the need to collect 

information on percentage ownership 

(which information is not used in any 

other provisions of the Transport Rule 

trading programs). 

In addition, the common designated 

representative approach provides 

additional flexibility to owners and 

operators who have only one or a few 

units in a given state but have the 

option of selecting a common 

designated representative with owners 

and operators of other units in the state. 

EPA expects companies in various states 

will readily be able to manage their 


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83Some 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. 

emissions to stay collectively below 

their state’s assurance levels as they 

track emissions quarterly throughout the 

year and manage their generation units 

and pollution control efforts 

accordingly. However, if the state 

appears to be approaching its assurance 

level, this final rule also gives 

companies the ability to further ensure 

that they will not have excess emissions 

by combining multiple units under a 

common DR. This flexibility allows 

utilities to re-balance allowances and 

emissions to mitigate penalty risk if the 

state violates its assurance level. In a 

state that does not appear to risk 

violating its assurance level in a given 

period, utilities would not need to 

consider the assurance aspect of 

selecting DRs. However, EPA anticipates 

that in the event utilities desire 

additional certainty or mitigation of 

assurance penalty risk, they will take 

advantage of this common DR provision 

or pursue similar private arrangements 

with each other to cover their emissions 

at the lowest possible cost. 

While the DR provision could benefit 

utilities by allowing them to pool their 

penalty risk, the utilities would still be 

subject to the antitrust laws. As with 

any joint venture between competitors, 

the efficiency benefits of pooling risk 

would be weighed against any 

anticompetitive harm associated with 

DRs. 

This new feature in the final rule, in 

conjunction with the simplifications to 

the final rule’s variability limits 

described in section VI.E, will give 

companies under the air quality-assured 

trading program greater flexibility in 

each state to determine the most costeffective pattern of emission reductions 

while EPA ensures each state meets its 

assurance level needed to address the 

significant contribution in each state. 

In the January 7, 2011 NODA, EPA 

also requested comment on continuing 

to link allocations to assurance 

provision allowance surrender 

requirements. Even though the final rule 

uses a different allowance allocation 

methodology than the allocation 

methodology that was proposed, the 

final rule continues to treat the groups 

of units with greater emissions than 

their allocations plus share of state 

variability as responsible for the state’s 

excess of emissions over the state 

assurance level. EPA believes that this 

approach is reasonable because any 

state that exceeds its state assurance 

level likely does so because not all units 

have made the reductions necessary to 

eliminate the state’s contribution to 

nonattainment or interference with 

maintenance. Moreover, the groups of 

units with emissions exceeding their 

allocations plus share of variability are 

the units most likely to have contributed 

to the state’s exceedance of its state 

assurance level and thus to the state’s 

triggering of the assurance provisions. 

Consequently, EPA concludes that it is 

reasonable to penalize owners and 

operators of those sources and units 

(grouped by common DR) for the state’s 

exceedance through application of the 

assurance provision allowance 

surrender requirement. Some 

commenters stated that this is a 

reasonable approach. 

While a few commenters suggested 

alternative approaches to the assurance 

provisions, EPA believes that the 

suggested alternatives are not workable 

and are likely to create implementation 

problems. These commenters suggested 

variations of approaches that would 

have created state-specific and vintage 

year-specific allowances that would 

have been traded independently of 

compliance allowances. These 

differentiated allowances would have 

fragmented the allowance markets and 

made the programs resemble the 

intrastate trading option that EPA 

rejected because of market power and 

other concerns described in the 

proposal. 

The existence of the assurance 

provisions with significant penalties 

imposed if a state’s emissions exceed 

the state budget with the variability 

limit, along with other features of the 

Transport Rule trading programs 

discussed below, will ensure that state 

emissions stay below the level of the 

budget with the variability limit. In 

making compliance decisions and 

determining to what extent to rely on 

purchased or banked allowances, 

owners and operators will have to take 

into account the risk of triggering the 

assurance provisions in the state 

involved and of incurring significant 

assurance provision penalties. The 

greater the extent to which units sharing 

a common DR have emissions exceeding 

the DR units’ allocations plus share of 

the state variability limit, the greater the 

risk of being subject to the assurance 

provision penalties. 

As discussed previously in section 

VII.D.2, EPA allocates allowances to a 

new unit for the control period during 

which the unit commences commercial 

operation from the new unit set-aside 

based on its emissions. In the case 

where assurance provisions for a state 

are triggered in the year that a new unit 

commences operation, the unit’s share 

of the state assurance level is calculated 

using the unit’s allocation from the new 

unit set-aside plus its proportional share 

of the variability limit. There is the 

possibility that a new unit would 

receive no allocation for the control 

period during which the unit 

commences commercial operation. EPA 

sees no reasonable basis for 

disadvantaging owners and operators 

because they started up a new unit and 

EPA had no emissions data on which to 

base an allocation from the new unit setaside or no allowances were available 

for the unit in the state’s new unit setaside.83 For these new units, EPA would 

use a specific surrogate number to 

calculate the maximum amount of 

emissions that the unit would likely 

have had during that year. The surrogate 

emission number applies only if the 

state’s assurance provisions are 

triggered and only in the first year of the 

new unit’s commercial operation for a 

new unit that did not receive an 

allocation from the set-aside. The 

methodology for calculating the 

surrogate emission number is essentially 

unchanged from the proposal (75 FR 

45313). For more details on capacity 

factors for new units, see ‘‘Capacity 

Factors Analysis for New Units Final 

Rule TSD.’’ 

These assurance provisions are above 

and beyond the fundamental 

requirement for each source to hold 

enough allowances to cover its 

emissions in the control period. Failure 

to hold enough allowances to cover 

emissions is a violation of the CAA, 

subject to an automatic penalty and 

discretionary civil penalties, as 

described in section VII.F of this 

preamble. 

Several features of the air qualityassured trading programs work in 

conjunction with the assurance 

provisions to ensure state emissions do 

not exceed state assurance levels. The 

air quality-assured trading programs 

have: State-specific budgets that do not 

include the variability limits and that 

are the basis for allocating allowances in 

each state so that total allocations in a 

state cannot exceed the state budget; a 

requirement that owners and operators 

of each source hold enough allowances 

to cover source emissions for each 

control period; assurance provisions 

that require owners and operators to 

hold a significant amount of additional 

allowances in a state if the assurance 

provisions are triggered; and additional 

penalties for failing to hold sufficient 

allowances under the assurance 

provisions. The underlying mechanism 

of cap and trade—with a cap on 

allowances issued and a requirement to 


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hold allowances covering emissions— 

has succeeded, even without assurance 

provisions, in broadly reducing 

emissions below allowance allocation 

levels. The accumulated data, history, 

and experience from cap and trade 

programs underscore that emission 

reduction requirements and 

environmental and public health goals 

of the programs have been met and, in 

many instances, exceeded. Additionally, 

EPA has now added assurance 

provisions to ensure that emissions 

within a state do not exceed the state 

budget with the variability limitation 

that eliminates the state’s significant 

contribution to nonattainment and 

interference with maintenance in 

downwind states. 

Emissions from a common DR’s group 

of units in excess of the DR’s share of 

the state budget with the variability 

limit are not a violation of the rule or 

the CAA, but do lead to strict allowance 

surrender requirements. Specifically, 

the owners and operators with a 

common DR will be required to 

surrender two allowances for each ton 

of their proportional share of the 

exceedance of the state budget with the 

variability limit. Failing to hold 

sufficient allowances to meet the 

allowance surrender requirement will 

be a violation of the regulations and the 

CAA and subject to discretionary civil 

penalties under CAA section 113. 

Allowances surrendered to meet an 

assurance provision penalty may be 

from the year immediately following the 

control period in which the state 

assurance level was exceeded (i.e., the 

year during which the penalty is 

assessed) or any prior year. Any future 

vintage allowances beyond the year in 

which the penalty is assessed may not 

be used to meet an assurance provision 

penalty. 

This penalty level is a change from 

the proposal, in which one allowance 

was to be surrendered for each ton of 

emissions over the 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-forone allowance surrender requirement is 

significant, and EPA believes that this 

penalty—along with the other elements 

of the Transport Rule discussed above— 

will be sufficient to ensure that the state 

emissions will not exceed the budgets 

plus the variability limits. See the 

Assurance Penalty Level Analysis Final 

Rule TSD for further details of the 

analysis. 

Below are examples of how the 

penalty will be assessed for four 

common designated representatives in 

the same state if the assurance 

provisions are triggered. In the first case, 

DR1’s combined units were allowed to 

emit up to 71 tons of SO2 (60 * 118 

percent), but actually emitted 75 tons 

during the control period, or 4 more 

than their share of the state assurance 

level. Since the state, as a whole 

exceeded the state assurance level by 15 

tons, DR1’s share of the penalty is 25 

percent of the total penalty, or 8 

allowances (25 percent of 30). 

FIGURE VII.E–1—ASSURANCE PROVISION ALLOWANCE SURRENDER EXAMPLE

Allowances 

allocated 

Allocation + 

share of 

variability 

Total 

emissions 

Emissions 

above 

allocation 

Emissions 

above allocation + share of 

variability 

Share of state 

exceedance 

(%) 

Penalty 

(allowances 

surrendered) 

DR1 .............................. 60 71 75 15 4 25% 8 

DR2 .............................. 20 24 33 13 9 56% 17 

DR3 .............................. 10 12 15 5 3 19% 6 

DR4 .............................. 10 12 10 0 ¥2 0% ¥ 

Total ............................. 100 118 133 33 15 100% 30 

DR1, DR2, DR3, and DR4 are all in the same state. 

State budget plus 18 percent variability limit is 118 tons (100 + 18 = 118). 

State exceeded its assurance level by 15 tons (133¥118 = 15). 

Penalty is 2 allowances per ton over the assurance level (2 × 15 = 30). 

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 

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 allowances surrendered for 

the excess emissions penalty must be 

allocated for the control period in the 

year immediately following the year 

when the excess emissions occurred or 

for a control period in any prior year. 

The offset and the excess emissions 

penalty are automatic requirements in 


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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 

used in calculating the maximum civil 

penalty is the number in the ozone 

season. 

Commenters expressed concern that 

the proposed FIPs expressly stated that, 

for purposes of determining the 

maximum discretionary civil penalty for 

failure to meet the allowance-holding 

requirement, each ton of emissions 

lacking a held allowance would be a 

violation and each day in the averaging 

period involved would be a violation. 

Some commenters compared the 

proposed penalty provisions for excess 

emissions with the excess emissions 

penalty provisions under the Acid Rain 

Program and claimed that the proposed 

penalty provisions differed from the 

Acid Rain Program provisions and were 

excessive. 

In fact, however, the final FIP 

provisions concerning discretionary 

civil penalties are essentially the same 

as those under the Acid Rain Program, 

as well as those under the NOX Budget 

Trading Program and the CAIR trading 

programs. In particular, the Acid Rain 

Program regulations state that each ton 

of SO2 excess emissions constitutes ‘‘a 

separate violation’’ of the CAA. 40 CFR 

72.9(c)(2). Moreover, while the Acid 

Rain Program regulations do not 

expressly address that each day in the 

averaging period (i.e., a calendar year 

control period under the Acid Rain 

Program) constitutes a separate violation 

when a unit has excess emissions for the 

calendar year, the courts have addressed 

this question. In decisions applying the 

discretionary civil penalty provisions in 

section 309(d) of the Clean Water Act, 

which are analogous to the civil penalty 

provisions in CAA section 113, the 

courts have interpreted the provisions to 

mean that, when a source violates the 

emission limitation for a multi-day 

control period, the source has a 

violation for each day in the control 

period, as well as for each ton of excess 

emissions on each such day. See, e.g., 

Chesapeake Bay Foun. v. Gwaltney of 

Smithfield, 791 F.2d 304, 313–15 (4th 

Cir. 1986), Atlantic States Legal Foun. v. 

Tyson Foods, 897 F.2d 1128, 1139–40 

(11th Cir. 1990), and U.S. v. Allegheny 

Ludlum Corp., 366 F.3d 164, 169 (3d. 

Cir. 2004). As noted by the courts, the 

treatment of each ton and each day as 

a separate violation is used for purposes 

of setting the maximum discretionary 

civil penalty. Because CAA section 113 

sets the maximum civil penalty, EPA, of 

course, has the discretion to tailor the 

penalty amount that it seeks in any 

specific occurrence of excess emissions 

to reflect the circumstances of that 

excess emission occurrence. See 42 

U.S.C. 7413(b) (stating that the 

Administrator may commence a civil 

action ‘‘to assess and recover a civil 

penalty of not more than $25,000 per 

day for each violation’’). Moreover, 

when a district court imposes a civil 

penalty, the court ‘‘retains discretion to 

assess a penalty much smaller than the 

maximum, as the situation requires.’’ 

Chesapeake Bay, 791 F.2d at 316. In 

addition, the Acid Rain Program 

regulations state that any allowance 

deduction, excess emission penalty, or 

interest under the Acid Rain Program 

regulations ‘‘shall not affect liability’’ of 

the owners and operators ‘‘for any 

additional fine, penalty, or assessment, 

or their obligation to comply with any 

other remedy, for the same violation, as 

ordered under the [CAA],’’ including 

under CAA section 113 providing for 

discretionary civil penalties. 40 CFR 

77.1(b). In summary, under the Acid 

Rain Program, each ton of excess 

emissions and each day in the averaging 

period (i.e., the calendar year) constitute 

a violation, the resulting number of 

violations times $2,000 is the maximum 

civil penalty for violating owners and 

operators, and EPA has the discretion to 

impose a civil penalty at or below such 

maximum, in addition to the automatic 

requirement to surrender one allowance 

and pay $2,000 (inflation adjusted) for 

each ton of excess emissions. 

The final FIPs take an analogous 

approach to that under the Acid Rain 

Program. Specifically, the final FIPs 

state both that each ton of excess 

emissions is a violation of the CAA and 

that each day in the averaging period 

(i.e., a calendar year under the annual 

programs and the ozone season under 

the ozone-season program) is a 

violation. Moreover, the imposition of 

civil penalties at or below the maximum 

amount resulting from the maximum 

penalty calculation is in addition to the 

automatic allowance surrender and 

penalty totaling 2 allowances per ton of 

excess emissions. Thus, commenters’ 

assertion that the approach in the final 

FIPs is inconsistent with the approach 

in the Acid Rain Program is incorrect. 

Moreover, EPA has taken this same 

general approach in two other trading 

programs (i.e., the NOX Budget Trading 

Program and the CAIR trading 

programs), whose regulations explicitly 

state that each ton and each day of the 

averaging period constitute a violation. 

See 40 CFR 96.54(d)(3) (NOX Budget 

Trading Program); and 40 CFR 96.106(d) 

(CAIR). 

In any event, EPA maintains that the 

approach of treating each excess 

emission ton and each day in the 

averaging period as a violation for 

purposes of calculating the maximum 

discretionary civil penalty is reasonable. 

Some commenters suggested that only 

the days on which a source’s cumulative 

control period emissions exceed the 

amount of allowances that the source 

then holds for that control period 

should be treated as a violation. 

However, this suggested approach 

makes little sense in the context of the 

Transport Rule trading programs. 

In order to provide owners and 

operators compliance flexibility, the 

Transport Rule trading programs do not 

require source owners and operators to 

hold any amount of allowances to cover 

emissions until the allowance transfer 

deadline, no matter what the source’s 

cumulative control period emissions are 

before that deadline. The commenters’ 

approach of comparing—each day, 

cumulative emissions and allowances 

held—for purposes of calculating 

maximum civil penalties would be 

inconsistent with the flexibility that 

EPA intends to provide owners and 

operators. For example, under the 

commenters’ suggested approach, 

owners and operators that buy or sell 

allowances in the allowance market or 

hold allowances in a company-wide 

account, do not transfer allowances into 

their source’s compliance account until 

just before the allowance transfer 

deadline, and end up with some excess 

emissions for the calendar year would 


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face a significantly higher maximum 

civil penalty than owners and operators 

that every day increase the amount of 

allowances held in their source’s 

compliance account as the source’s 

cumulative emissions increase and end 

up with the same amount of excess 

emissions for the calendar year. In short, 

the commenters’ approach would 

penalize owners and operators that use 

some of the compliance flexibility that 

the trading programs are intended to 

provide. 

EPA also maintains that it is 

reasonable to both impose the automatic 

allowance surrender and penalty 

provisions and to retain the discretion 

to impose civil penalties for the same 

occurrence of excess emissions. This 

approach encourages compliance with 

the allowance-holding requirement by 

ensuring that violating owners and 

operators are penalized automatically 

(i.e., without any further administrative 

or judicial proceedings, except for 

appeals) and that EPA can seek 

additional penalties where the 

circumstances warrant discretionary 

civil penalties. In fact, the Acid Rain 

Program, for which CAA Title IV 

mandated this approach, has achieved a 

very high level of compliance with the 

requirement to hold allowances 

covering SO2 emissions and therefore 

resulted in major reductions in utility 

SO2 emissions. See 42 U.S.C.7651j(a). 

Similarly, the NOX Budget Trading 

Program and CAIR trading programs, 

which took the same approach, also 

have achieved very high compliance 

levels and major utility emission 

reductions. 

EPA notes that, in calculating 

maximum civil penalties when owners 

and operators fail to hold allowances 

required under the assurance provisions 

in the final FIPs, EPA takes a similar 

approach in determining the number of 

violations. Each ton for which an 

allowance is not held as required and 

each day in the control period involved 

constitute a violation of the CAA. As 

discussed elsewhere in this preamble, 

EPA believes that this calculation 

approach is also reasonable in the 

context of the assurance provisions and 

that taking an approach like the 

commenters’ suggested approach 

described above would be inconsistent 

with some of the flexibility that the 

Transport Rule trading programs are 

intended to provide. 

G. Allowance Management System 

The final Transport Rule trading 

programs, like the proposed preferred 

remedy, utilize EPA’s allowance 

management system (AMS), which 

currently supports allowance surrender, 

transfer, and tracking activity under the 

Acid Rain Program and CAIR. EPA 

received no adverse comment on this 

aspect of the proposed rule. 

The primary role of AMS is to provide 

an efficient, automated means for 

covered sources to comply and for EPA 

to determine whether covered sources 

are complying, with the emissionsrelated 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 groups of 

sources and units with common 

designated representatives under the 

assurance provisions); deduction of SO2

and NOX allowances for compliance 

purposes (including deductions from 

assurance accounts where necessary); 

and transfers of allowances between 

accounts. The AMS also allows the 

public to see whether each source is in 

compliance and provides information to 

the allowance market and the public in 

general, including information on 

ownership of allowances, dates of 

allowance transfers, buyer and seller 

information, and the serial numbers of 

allowances transferred. 

H. Emissions Monitoring and Reporting 

Under the proposed rule, units subject 

to the Transport Rule trading programs 

would monitor and report NOX and SO2

mass emissions in accordance with 40 

CFR part 75, as incorporated in the 

proposed rule, and with certain other 

specified requirements, such as 

compliance deadlines. 

In the final rule, like the proposed 

rule, covered units must comply with 

emissions monitoring and reporting 

requirements that are largely 

incorporated from Part 75 monitoring 

and reporting requirements. 

Under the final rule and under Part 

75, a unit has several options for 

monitoring and reporting, namely the 

use of: a CEMS; an excepted monitoring 

methodology (NOX mass monitoring for 

certain peaking units and SO2 mass 

monitoring for certain oil- and gas-fired 

units); low mass emissions monitoring 

for certain non-coal-fired, low emitting 

units; or an alternative monitoring 

system approved by the Administrator 

through a petition process. In addition, 

the Administrator can approve petitions 

for alternatives to Transport Rule and 

Part 75 monitoring, recordkeeping, and 

reporting requirements. 

Further, the final rule and Part 75 

specify that each CEMS must undergo 

rigorous initial certification testing and 

periodic quality assurance testing 

thereafter, including the use of relative 

accuracy test audits (RATAs) and 24- 

hour calibrations. In addition, when a 

monitoring system is not operating 

properly, standard substitute data 

procedures are applied and result in a 

conservative estimate of emissions for 

the period involved. 

In addition, the final rule and Part 75 

require electronic submission, to the 

Administrator and in a format 

prescribed by the Administrator, of a 

quarterly emissions report. The report 

must contain all of the data required 

concerning NOX annual and ozoneseason and SO2 annual emissions. 

Most Transport Rule units are in 

states subject to CAIR and are already 

monitoring and reporting NOX and/or 

SO2 under CAIR and the Acid Rain 

Program, which programs also use Part 

75 monitoring and reporting. Units 

under the Transport Rule annual trading 

programs and in states subject to CAIR 

generally have no changes to their 

monitoring and reporting requirements. 

These units must continue to monitor 

and submit reports on a year-round 

basis as they have under CAIR. 

Therefore, units in the following states 

must monitor and report both SO2 and 

NOX year-round under the Transport 

Rule: Alabama, Georgia, Illinois, 

Indiana, Iowa, Kansas, Kentucky, 

Maryland, Michigan, Minnesota, 

Missouri, Nebraska, New Jersey, New 

York, North Carolina, Ohio, 

Pennsylvania, South Carolina, 

Tennessee, Texas, Virginia, West 

Virginia and Wisconsin. 

Some states (Kansas, Minnesota, and 

Nebraska) subject to the Transport Rule 

annual trading programs were not 

subject to CAIR. Transport Rule units in 

those states must meet monitoring and 

reporting requirements that are new 

except to the extent the units were 

subject to Part 75 under some other 

program (such as the Acid Rain 

Program). 

Further, some states (Florida, 

Louisiana, and Mississippi) subject to 

the Transport Rule ozone-season trading 

program but not the Transport Rule 

annual trading programs were subject to 

the annual and ozone-season trading 

programs under CAIR. Transport Rule 


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84Part 70 addresses requirements for state Title V 

programs, and Part 71 governs the federal Title V 

program. 

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 yearround or ozone-season-only basis. 

In addition, one state (Arkansas) 

subject to the Transport Rule ozoneseason 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. 

Finally, some states (Connecticut, 

Delaware, District of Columbia, and 

Massachusetts) that were subject to 

CAIR are not subject to the Transport 

Rule. Electric generating units in those 

states must continue to meet monitoring 

and reporting requirements only to the 

extent the units are subject to Part 75 

under some other program (such as the 

Acid Rain Program or a state adopted 

program requiring such monitoring and 

reporting). 

EPA is finalizing requirements for 

existing Transport Rule units in states 

covered by the Transport Rule annual 

trading programs to monitor and report 

SO2 and NOX emissions by January 1, 

2012 programs and for existing 

Transport Rule units in states covered 

by the Transport Rule ozone-season 

trading program to monitor NOX

emissions by May 1, 2012. The use of 

Part 75 certified monitoring 

methodologies is required in both cases. 

As discussed previously, most covered 

existing units will generally have no 

changes to their monitoring and 

reporting requirements and will 

continue to monitor and submit reports 

under Part 75 as they have under CAIR. 

Existing units that have not been subject 

to Part 75 monitoring and reporting 

requirements in the past have less than 

1 year to install, certify, and operate the 

required monitoring systems. EPA 

believes that these units will be able to 

comply with this requirement because 

the monitoring equipment needed is not 

extensive or is largely in place already 

for the purpose of meeting other 

requirements. Quality assurance and 

reporting provisions and data system 

upgrades may be necessary, but EPA 

believes that there is sufficient time to 

accomplish this by the deadline for 

existing units in the final rule. 

In the proposed rule, the compliance 

deadline for installing, certifying, and 

operating the required monitoring 

systems at new units was based upon 

the date of commencement of 

commercial operation. A new unit 

would have to install and certify its 

monitoring system within 180 days of 

the commencement of commercial 

operation. The final rule adopts this 

deadline, which is consistent with the 

approach recently adopted in Part 75 

under the Acid Rain Program. See 76 FR 

17288, 17289 (March 28, 2011). 

Using this deadline (rather than a 

deadline, used previously in Part 75, of 

the earlier of the unit’s 90th operating 

day or 180 days after the unit’s 

commencement of commercial 

operation) ensures that new units have 

sufficient time to complete installation 

and certification of monitoring systems 

and facilitates units’ compliance. 

Because of unit shakedown problems, 

some new units have had difficulty 

meeting a deadline earlier than 180 days 

after commencement of commercial 

operation. Further, using this deadline 

facilitates owners’ and operators, and 

EPA’s, ability to track important dates 

related to monitoring, reporting, and 

allowance holding. Under the final rule, 

the requirement that a unit hold enough 

allowances to cover its emissions starts 

on the later of the commencement of the 

Transport Rule trading program 

involved or the deadline for installation 

and certification of the monitoring 

system. Having a simple, easily 

determined deadline (180 days after the 

commencement of commercial 

operation) makes it easier for owners 

and operators and EPA to determine 

when allowance-holding requirements 

begin, as well as when monitoring and 

reporting requirements begin. In 

contrast, using a deadline involving 

determination of a unit’s 90th operating 

day required keeping track of any days 

on which the unit did not operate (e.g., 

due to problems associated with 

shakedown of the unit). EPA found that 

owners and operators have had more 

difficulty reporting the 90th operating 

day than in reporting the 

commencement of commercial 

operation, and once the latter date is 

reported, EPA can independently 

determine the 180th calendar day after 

the reported date. 

I. Permitting 

1. Title V Permitting 

The final Transport Rule (like the 

proposed rule) does not establish any 

permitting requirements independent of 

those under Title V of the CAA and the 

regulations implementing Title V, 40 

CFR Parts 70 and 71.84 All major 

stationary sources of air pollution and 

certain other sources are required to 

apply for title V operating permits that 

include emission limitations and other 

conditions as necessary to assure 

compliance with applicable 

requirements of the CAA, including the 

requirements of the applicable State 

Implementation Plan. CAA §§ 502(a) 

and 504(a), 42 U.S.C. 7661a(a) and 

7661c(a). The ‘‘applicable 

requirements,’’ that must be addressed 

in title V permits are defined in the Title 

V regulations (40 CFR 70.2 and 71.2 

(definition of ‘‘applicable 

requirement’’)). 

EPA anticipates that, given the nature 

of the units covered by the final 

Transport Rule, most of the sources at 

which they are located are already or 

will be subject to Title V permitting 

requirements. For sources subject to 

Title V, the requirements applicable to 

them under the final FIPs will be 

‘‘applicable requirements’’ under Title V 

and therefore will need to be addressed 

in the Title V permits. For example, 

requirements under the final FIPs 

concerning designated representatives, 

monitoring, reporting, and 

recordkeeping, the requirement to hold 

allowances covering emissions, the 

assurance provisions, and liability will 

be ‘‘applicable requirements’’ to be 

addressed in the permits. 

The Title V permits program includes, 

among other things, provisions for 

permit applications, permit content, and 

permit revisions that will address the 

applicable requirements under the final 

FIPs in a manner that will provide the 

flexibility necessary to implement 

market-based programs such as the 

Transport Rule trading programs. For 

example, the Title V regulations provide 

that a permit issued under Title V must 

include, for any ‘‘approved * * * 

emissions trading and other similar 

programs or processes’’ applicable to the 

source, a provision stating that no 

permit revision is required ‘‘for changes 

that are provided for in the permit.’’ 40 

CFR 70.6(a)(8) and 71.6(a)(8). Consistent 

with this provision in the Title V 

regulations, the Transport Rule trading 

program regulations include a provision 

stating that no permit revision is 

necessary for the allocation, holding, 

deduction, or transfer of allowances. 

Consistent with the Title V regulations, 

this provision will also be included in 

each Title V permit for a covered source. 

As a result, allowances can be traded (or 

allocated, held, or deducted) under the 

final FIPs without a revision of the Title 

V permit of any of the sources involved. 

As a further example of flexibility 

under Title V, the Title V regulations 

allow the use of the minor permit 

modification procedures for permit 

modifications ‘‘involving the use of 

economic incentives, marketable 

permits, emissions trading, and other 


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85A 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). 

86We note that, for sources that are modifying 

and are not subject to PSD for emissions of a nonGHG pollutant, in order to be subject to PSD for 

GHGs the source must not only have an emissions 

increase of 75,000 TPY CO2e, but must also have 

a PTE of at least 100,000 TPY CO2e and 100 TPY 

mass GHG. See 40 CFR 52.21(b)(49)(v)(b). However, 

since it is reasonable to assume that all sources that 

are potentially subject to the Transport Rule will 

have a PTE of at least 100,000 TPY CO2e and 100 

TPY, for the purposes of discussions in this section 

we will only note the requirement to have an 

emissions increase of 75,000 TPY CO2e. 

similar approaches, to the extent that 

such minor permit modification 

procedures are explicitly provided for in 

an applicable implementation plan or in 

applicable requirements promulgated by 

EPA.’’ 40 CFR 70.7(e)(2)(i)(B) and 40 

CFR 71.7(e)(1)(i)(B). The final FIPs set 

forth in detail, and reference relevant 

provisions in Part 75 concerning, the 

approaches that are available for 

covered units to use for monitoring and 

reporting emissions (i.e., approaches 

using a continuous emission monitoring 

system, an excepted monitoring system 

under appendices D and E to Part 75, a 

low mass emissions excepted 

monitoring methodology under § 75.19, 

or an alternative monitoring system 

under 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 Web site. 

Moreover, EPA intends that each 

covered unit’s Title V permit will 

include a description of the general 

approach that the covered unit is 

required to use for monitoring and 

reporting emissions and that the 

description will reference the relevant 

sections of the Transport Rule trading 

program regulations and Part 75 and 

will state that the requirements may be 

modified through EPA approval of 

petitions for alternatives to specific 

requirements. Finally, consistent with 

§§ 70.7(e)(2)(i)(B) and 71.7(e)(1)(i)(B) of 

the Title V regulations, the final FIPs 

provide that a description of the general 

monitoring and reporting approach for a 

covered unit can be added to, or an 

existing description of a unit’s general 

monitoring and reporting approach can 

be changed, in a Title V permit, using 

minor permit modification procedures, 

provided that the approach being 

described in the changed or new general 

description and the requirements 

applicable to that approach are already 

incorporated elsewhere in the permit. 

As a result, minor permit modification 

procedures can be used to revise a 

covered unit’s Title V permit to be 

consistent with the monitoring and 

reporting approach, or any changes in 

the approach, allowed for the unit by 

EPA through the monitoring system 

certification or petition process under 

the Transport Rule trading programs. 

As new applicable requirements 

under Title V, the requirements for 

covered units under the final FIPs will 

be incorporated into covered sources’ 

existing Title V permits either pursuant 

to the provisions for reopening for cause 

(40 CFR 70.7(f) and 40 CFR 71.7(f)) or 

the permit renewal provisions (40 CFR 

70.7(c) and 71.7(c)).85 In contrast to the 

approach in CAIR of imposing 

permitting requirements and deadlines 

independent of those under Title V, the 

approach to permitting under the final 

FIPS of imposing no independent 

permitting requirements should reduce 

the burden on sources already required 

to be permitted under Title V and on 

permitting authorities. For sources 

newly subject to Title V that will also 

be covered sources under the final FIPs, 

the initial Title V permit issued 

pursuant to 40 CFR 70.7(a) will address 

the final FIP requirements. 

In order to ensure that covered 

sources’ Title V permit provisions 

concerning the final FIPs will reflect the 

Transport Rule trading program 

requirements and flexibilities properly 

and in a manner consistent from permit 

to permit, EPA intends to issue 

guidance to assist permitting 

authorities. This guidance would 

include information on permit issuance 

and permit modification requirements, 

as well as a permit content template that 

will identify the applicable 

requirements under the applicable 

Transport Rule trading program and 

thereby ensure that they will be 

correctly and comprehensively reflected 

in each permit in a manner that will 

reduce the burden on sources and 

permitting authorities related to the 

issuance of the permit and will reduce 

the need for permit revisions. 

2. New Source Review 

a. Background 

EPA recognizes that, following the 

vacatur of the new source review (NSR) 

pollution control project exemption in 

New York v. EPA, 413 F.3d 3, 40–41 

(D.C. Cir. 2005), pollution control 

projects, including pollution control 

projects constructed to comply with this 

rule, have the potential to trigger NSR 

permitting. 

This issue was previously addressed 

in the context of CAIR. On December 20, 

2005, the EPA agreed to reconsider one 

specific aspect of CAIR. In that notice, 

EPA granted reconsideration and sought 

comment on the potential impact of the 

opinion in New York v. EPA, which 

vacated the previously existing NSR 

exemption for certain environmentally 

beneficial pollution control projects. For 

this reconsideration, EPA conducted an 

analysis which showed that the court 

decision did not impact the CAIR 

analyses. Details of this analysis can be 

found in a technical support document 

which is available on EPA’s Web site at: 

http://epa.gov/cair/pdfs/0053-2263.pdf 

Because GHG emissions were not 

considered by EPA to be air pollutants 

within the meaning of the CAA at the 

time of CAIR, GHG emissions were not 

addressed in the 2005 analysis. GHG 

requirements related to the component 

of NSR concerning the Prevention of 

Significant Deterioration (‘‘PSD’’) 

program are addressed in EPA’s 

‘‘Interpretation of Regulations that 

Determine Pollutants Covered by Clean 

Air Act Permitting Programs,’’ 75 FR 

17004 (April 2, 2010), and ‘‘Prevention 

of Significant Deterioration and Title V 

Greenhouse Gas Tailoring Rule,’’ 75 FR 

(June 3, 2010) (‘‘Tailoring Rule’’). 

Generally, as discussed in those actions, 

major stationary sources will be 

required to address GHG emissions as 

part of the PSD program if these sources 

emit GHG in amounts that equal or 

exceed the thresholds in the Tailoring 

Rule. Major sources that undergo a 

modification, including the addition of 

pollution control equipment, will trigger 

PSD requirements for their emissions of 

GHG if such emissions increase by at 

least 75,000 86 tons per year of CO2

equivalent (CO2e). 

b. Proposed Rule 

In the proposed rule, EPA presented 

the following conclusions: 

(1) The 2005 analysis remains current 

and relevant for all pollutants except for 

GHG, and it shows that NSR 

requirements would not significantly 

impact the construction of controls that 


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87 ‘‘Net generation’’ refers to total generation 

minus the amount of power consumed on-site for 

various purposes, including operation of pollution 

control equipment. 

88The 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). 

89 Documentation Supplement for EPA Base Case 

v.4.10_FTransport—Updates for Final Transport 

Rule. 

are installed to comply with the 

proposed Transport Rule. 

(2) It is very unlikely that pollution 

control projects would cause GHG 

increases that would exceed the 75,000 

tons per year threshold. 

Consistent with these proposed 

conclusions, EPA also concluded that 

there would be no significant impacts 

from NSR for any pollution control 

projects resulting from the proposed 

rule such as low-NOX burners, SO2

scrubbers, or SCR. EPA requested 

comment on this issue. 

c. Public Comments 

EPA received a number of comments 

on the NSR issue, which can be divided 

into four types of comments: (1) 

Comments related to GHGs, (2) 

comments related to sulfuric acid mist, 

(3) comments related to CO emission 

increases from low-NOX burners, and (4) 

suggested changes to the EPA rules. 

Greenhouse Gases. A number of 

commenters recommended that EPA 

should document and substantiate its 

conclusion that greenhouse gases would 

be unlikely to trigger NSR requirements. 

Other commenters suggested that some 

units installing a FGD scrubber could 

exceed the 75,000 ton threshold for 

GHGs in the Tailoring Rule by emitting 

CO2 produced from the chemical 

reaction of SO2 with limestone. 

Commenters also suggested that NSR 

applicability for GHGs would also need 

to consider that an FGD would consume 

1–3 percent of a scrubbed unit’s 

generation, referred to as ‘‘parasitic 

load,’’ which (all else held equal) lowers 

that unit’s net generation.87

Commenters argued that any postretrofit increase in generation to offset 

that ‘‘parasitic load’’ could lead to GHG 

increases potentially exceeding the 

75,000 ton threshold. 

Sulfuric Acid Mist. Two commenters 

noted that use of high sulfur fuels, in 

combination with SCR, can lead to 

increases in sulfuric acid mist, a 

pollutant regulated under NSR. One of 

these commenters noted that reagent 

injection was necessary to avoid 

triggering NSR for sulfuric acid mist 

when their SCR was installed. 

Carbon Monoxide (CO). One 

commenter believed that EPA’s 2005 

analysis may not be adequate as it 

related to carbon monoxide emission 

increases that result from installation of 

low-NOX burners. The commenter noted 

EPA’s statement in the 2005 analysis 

that read as follows: ‘‘Since the NOX

removal efficiencies used in EPA’s 

analysis are not aggressive, it is believed 

that the units installing combustion 

controls can opt for moderate levels of 

overfire air flow rates and still achieve 

the NOX reduction levels projected in 

EPA’s analysis, without causing 

significant increases in the CO and 

unburned carbon emissions.’’ The 

commenter suggested that the transport 

rule NOX may be more aggressive than 

CAIR and thus EPA should conduct a 

review to determine whether EPA 

retains the same conclusion regarding 

CO emissions. 

Recommended Rule Changes. Some 

commenters suggested changes to EPA 

rules to address their concerns that 

control equipment installed as a result 

of the Transport Rule could trigger NSR. 

Some commenters suggested that EPA 

craft an exclusion from NSR in the 

Transport Rule. One of these 

commenters suggested that EPA could 

do this by: (1) Providing special 

definition of baseline actual emissions; 

(2) a causation determination 

specifically tied to the Transport Rule; 

or (3) interpret the term ‘‘stationary 

source’’ in CAA 110(a)(4) in a way that 

doesn’t impede Transport Rule 

compliance. 

Other commenters expressed the 

concern that if NSR is triggered, the 

proposed Transport Rule did not allow 

enough time for compliance for sources 

needing to install control equipment. 

These commenters recommend that EPA 

should waive Transport Rule 

requirements or provide extra 

allowances until NSR review is 

complete. 

d. Final Rule and Responses to 

Comments 

Greenhouse Gases. EPA has carefully 

reviewed relevant data in assessing the 

comments suggesting that NSR 

permitting would likely be triggered for 

facilities installing FGD scrubbers to 

comply with this rule. EPA believes that 

sources installing FGD to comply with 

the Transport Rule can achieve those 

installations without triggering NSR. 

EPA notes that its forecast of the 

number and extent of FGD scrubber 

installations substantially decreased 

since the time of proposal. For the 

proposed rule, EPA modeled 14 GW of 

FGD retrofit installations by 2014. For 

the final rule, EPA models a total of 5.7 

GW of wet FGD installations from 7 

units at 5 plants. 

There are two factors associated with 

wet FGD scrubbers that commenters 

suggested individually or in 

combination could lead to increases 

above the 75,000 tons per year threshold 

in the Tailoring Rule. The first is the 

CO2 chemically produced from the 

reaction of SO2 with limestone in wet 

FGD scrubbers. The second is that 

owners or operators of the affected units 

may desire to increase coal usage after 

the retrofit is made to offset the 

‘‘parasitic load’’ that is consumed onsite 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 × (0.96) × (44/64) = 67,980 tons 

CO2.88

Therefore, EPA finds that all currently 

uncontrolled units are technically 

capable of retrofitting with wet FGD 

without chemically produced CO2

increases leading to a triggering of NSR. 

In limited circumstances, an owner or 

operator may elect to switch fuels to a 

significantly higher-sulfur coal 

subsequent to FGD installation and may 

risk an increase in chemically produced 

CO2 emissions that would trigger NSR, 

but such a decision is not necessary in 

order to successfully install and operate 

the scrubber as a strategy for compliance 

with Transport Rule requirements. 

With respect to the ‘‘parasitic load’’ 

issue, EPA estimates that today’s wet 

FGD retrofit technology would consume 

typically about 1.7 percent of on-site 

generation.89 If a facility made no other 

changes to its operation other than 

installing an FGD retrofit, that facility’s 

CO2 emissions from fuel combustion 

would remain constant. It is possible, 

however, that a source’s owner or 

operator may elect to increase coal 

usage by some amount after retrofitting 

FGD, if for example the owner or 

operator desires to increase net 

generation after retrofitting. Under NSR, 

any such source would be able to 


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compare such a CO2 emissions increase 

against the highest average annual 

emissions in any consecutive 24-month 

period from a 5-year historic baseline. 

Therefore, a unit retrofitting a scrubber 

under the Transport Rule may be able to 

increase its CO2 emissions by more than 

75,000 tons without triggering NSR if 

that increase would register as less than 

75,000 tons against a higher emissions 

level in the aforementioned NSR 

baseline. 

EPA also notes that scrubber 

installations provide facilities with the 

opportunity to make other capital 

improvements at the unit on which the 

scrubber is installed to improve the 

efficiency of boilers, steam turbines, 

motors, other auxiliary equipment, and 

plant control systems. Such 

improvements could allow a retrofitting 

unit to lower its CO2 output rate such 

that a subsequent decision to increase 

net generation may not result in 

increased coal use, or may limit any CO2

emission increase to less than the 

75,000 tons per year threshold for 

triggering NSR. 

As discussed in section VII.C, EPA 

notes that the Transport Rule does not 

mandate any specific control activity, 

including scrubber retrofitting, as a 

compliance strategy for units within a 

state to meet that state’s SO2 budget. As 

demonstrated by EPA’s ‘‘no FGD’’ 

sensitivity analysis described in VII.C, 

covered sources within the Group 1 

states are capable of meeting their 

emission reduction obligations through 

a variety of emission reduction 

strategies even if no unit is able to 

complete a scrubber installation by 

2014. Therefore, EPA does not believe 

that NSR permitting presents an 

obstacle in any way to Transport Rule 

compliance, even if a given unit 

retrofitting with FGD triggers NSR for 

CO2. 

For some plants, EPA’s IPM modeling 

forecasts installation and operation of 

dry sorbent injection (DSI) systems. EPA 

does not believe any of these systems 

would result in CO2 emission increases 

above the 75,000 ton threshold. 

Moreover, given the relatively short 

construction schedule for DSI systems, 

EPA believes that if any of the plants 

did require NSR permitting, installation 

of DSI could still be accomplished by 

2014. 

In summary, EPA believes that the 

operators of plants projected to install 

scrubbers for Transport Rule SO2

reductions could readily develop 

workable compliance strategies whether 

or not such an installation would trigger 

NSR. Plant owners could readily 

develop strategies to avoid emission 

increases that would trigger NSR, 

including but not limited to alternative 

SO2 reduction strategies or technologies, 

efficiency improvements, or the ability 

to adjust net electricity generation to 

prevent a 75,000 ton increase in CO2

emissions. EPA believes that projected 

scrubber installations under the 

Transport Rule are broadly unlikely to 

trigger NSR, but even in the limited 

conditions where such a triggering may 

occur, the NSR permitting process 

would not infringe on a state’s ability to 

comply with its budgets under the 

Transport Rule. (See section VII.C for 

more details on EPA’s analysis of a ‘‘no 

FGD’’ sensitivity supporting these 

points.) 

Sulfuric Acid Mist. EPA continues to 

conclude that, consistent with the 2005 

TSD, sulfuric acid mist increases due to 

compliance with this rule are very 

unlikely to trigger NSR permitting. Such 

increases are most commonly seen from 

installation of SCR units on facilities 

with relatively high sulfur coal. 

However, as acknowledged by one of 

the commenters, engineering solutions 

have been developed to prevent such 

increases, and EPA believes that facility 

owners would take this into account in 

designing such an SCR system. 

Moreover, EPA’s IPM modeling of the 

NOX budgets in the final rule suggests 

that no new SCR units will result from 

the final rule. 

Carbon Monoxide. EPA concludes 

that any NSR permitting required due to 

CO increases associated with NOX

controls should not hinder the ability of 

sources to comply with Transport Rule 

requirements. For states that were 

included in the CAIR for either ozone, 

PM2.5, or both, EPA finds no evidence to 

suggest that the NOX control 

requirements of the Transport Rule 

would require more aggressive controls 

triggering NSR. As EPA’s baseline 

analysis acknowledges, many sources in 

these states installed NOX controls to 

comply with CAIR. In addition, their 

historic emissions reflect operation of 

these controls and there is no evidence 

to suggest that the Transport Rule will 

require sources to operate these controls 

more aggressively, thereby increasing 

CO emissions above the relevant 

threshold and triggering NSR. In a few 

states that were not covered by CAIR, a 

limited number of facilities may install 

new combustion controls (such as lowNOX burners, overfire air, or other 

combustion controls or upgrades) as a 

result of the Transport Rule. EPA 

expects relatively few such installations, 

and believes that NSR permitting, if 

required, is not an obstacle to 

compliance with the rule. First, EPA 

believes that NSR permitting should be 

relatively straightforward for these 

installations and that the BACT 

determination for CO will be very 

straightforward. EPA expects a 

relatively short time period for 

permitting, and as discussed later, EPA 

is planning to initiate actions that will 

further expedite any required 

permitting. 

Second, EPA notes that the rule 

achieves reductions through a trading 

program rather than direct control 

requirements. Accordingly, even if a few 

installations do not have controls in 

place at the very beginning of the 

compliance period, this should not 

hinder the ability of states to meet their 

ozone-season NOX budgets. Covered 

sources have a suite of NOX pollution 

control strategies and technologies 

available to them, including coal 

selection, selective non-catalytic 

reduction, gas re-burn, low-NOX burner 

and overfire air installations or 

upgrades, and neural network 

optimization of combustion controls 

operation. Sources may consider all of 

these technologies and strategies, which 

can be designed and operated so as to 

minimize CO emission increases that 

may otherwise trigger NSR. EPA also 

notes that during the downtime for 

installation of the construction controls, 

there would be no NOX emissions, and 

thus the source’s allowance holding 

requirements would also be lower for 

that period. 

Recommended Rule Changes. EPA 

disagrees with commenters who 

suggested rule changes, either to the 

NSR program or to this rule, to account 

for installations triggering NSR. As 

noted above, EPA concludes that NSR 

would be triggered at most for just a few 

of the projected control installations. 

EPA believes, however, that even if 

required these NSR permits would 

likely be issued in a timely manner 

given the overall environmental benefits 

resulting from the control equipment 

installation. In addition, this rule’s 

requirements are based on a flexible 

trading approach rather than a direct 

control approach. Accordingly, if this 

affect occurs for only a few installations, 

EPA believes that any extra emissions 

that occur during the relatively short 

time needed to obtain an NSR permit 

could be accommodated within the 

overall trading system. 

Expediting Permitting. In the limited 

circumstances where pollution control 

installations under the Transport Rule 

may trigger NSR, we also note that an 

expedited permitting process can occur 

with sufficient time to obtain permits 

and achieve emission reductions under 

the Transport Rule programs. For this 

reason, we strongly encourage 

permitting authorities to expedite 


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90As explained in greater detail in Section VI of 

this notice, for each covered state, EPA has 

identified emissions that must be prohibited 

pursuant to section 110(a)(2)(D)(i)(I). In most 

instances, EPA has determined that elimination of 

such emissions is sufficient to satisfy the 

requirements of that section. Thus, in these 

instances, the budgets represent an estimate of the 

emissions that will remain after the elimination of 

all emissions in that state that significantly 

contribute to nonattainment or interfere with 

maintenance of the NAAQS in another state. In a 

few limited instances, however, EPA determined 

that elimination of the emissions is necessary but 

may not be sufficient to satisfy the requirements of 

that section. In these instances, the budgets 

represent an estimate of the emissions that will 

remain after the elimination of all emissions that 

EPA, at this time, has determined must be 

eliminated. 

permitting for any such projects, which 

are likely to be very limited in number. 

To ensure that the permitting decisions 

are expedited, separate from this 

rulemaking EPA will provide assistance 

and guidance in order to expedite 

issuance of any such permits. For 

example, we are considering assistance 

that would serve to expedite BACT 

reviews or required air quality analysis. 

EPA requests early notification of any 

specific cases where such guidance and 

assistance may be needed. 

J. How the Program Structure Is 

Consistent With Judicial Opinions 

Interpreting the Clean Air Act 

The air quality-assured trading 

programs established by this rule 

eliminate all of the emissions that EPA 

has identified as significantly 

contributing to downwind 

nonattainment or interference with 

maintenance 90 in a manner that is 

consistent with section 110(a)(2)(D)(i) of 

the CAA as interpreted by the DC 

Circuit in North Carolina, 531 F.3d 896. 

The FIPs finalized in this action require 

sources to participate in air qualityassured interstate emission trading 

programs that include provisions to 

ensure that no state’s emissions exceed 

that state’s budget with variability limit. 

These assurance provisions, combined 

with the requirement that all sources 

hold emission allowances sufficient to 

cover their emissions, effectuate the 

requirement that emission reductions 

occur within the state. See 42 U.S.C. 

7410(a)(1)(2)(D). 

The state budgets developed in this 

rule represent an estimate of the 

emissions that will remain in a given 

state after the elimination of all 

emissions in that state that EPA has 

determined must be prohibited pursuant 

to section 110(a)(2)(D)(i)(I). However, for 

the reasons explained above, the 

amount of emissions that remain after 

the requirements of 110(a)(2)(D)(i)(I) are 

satisfied may vary. EPA recognizes that 

shifts in generation due to, among other 

things, changing weather patterns, 

demand growth, or disruptions in 

electricity supply from other units can 

affect the amount of generation needed 

in a specific state and thus baseline EGU 

emissions from that state. Because a 

state’s significant contribution to 

nonattainment or interference with 

maintenance is defined by EPA as all 

emissions that can be eliminated for a 

specific cost (as explained above, using 

air quality considerations to identify 

this cost threshold), and because EGU 

baseline emissions are variable, the 

amount of emissions remaining in a 

state after all significant contribution or 

interference with maintenance is 

eliminated is also variable. In other 

words, EGU emissions in a state whose 

sources have installed all controls and 

taken all measures necessary to 

eliminate its significant contribution to 

nonattainment or interference with 

maintenance could exceed the state 

budget without variability. 

For this reason, EPA determined that 

it is appropriate for the program to 

recognize the inherent variability in 

state EGU emissions. The program does 

so by identifying a variability range for 

each state in the program. The assurance 

provisions in the program, in turn, limit 

a state’s emissions to the state’s budget 

with variability limit. 

In addition, the requirement that all 

sources hold emission allowances 

sufficient to cover their emissions (and 

the fact that the total number of 

emission allowances allocated will be 

equal to the sum of all state budgets 

without variability) ensures that the use 

of variability limits both takes into 

account the inherent variability of 

baseline EGU emissions in individual 

states (i.e., the variability of total state 

EGU emissions before the elimination of 

significant contribution or interference 

with maintenance) and recognizes that 

this variability is not as great in a larger 

region. The variability of emissions 

across a larger region is not as large as 

the variability of emissions in a single 

state for several reasons. Increased EGU 

emissions in one state in one control 

period often are offset by reduced EGU 

emissions in another state within the 

control region in the same control 

period. In a larger region that includes 

multiple states, factors that affect 

electricity generation, and thus EGU 

emission levels, are more likely to vary 

significantly within the region so that 

resulting emission changes in different 

parts of the region are more likely to 

offset each other. For example, a broad 

region can encompass states with 

differing weather patterns, with the 

result that increased electricity demand 

and emissions due to weather in one 

state may be offset by decreased demand 

and emissions due to weather in another 

state. By further example, a broad region 

can encompass states with differing 

types of industrial and commercial 

electricity end-users, with the result that 

changes in electricity demand and 

emissions among the states due to the 

effect of economic changes on industrial 

and commercial companies may be 

offsetting. Similarly, because states in a 

broad region may vary in their degree of 

dependence on fossil-fuel-based electric 

generation, the impact of an outage of 

non-fossil-fuel-based generation (e.g., a 

nuclear plant) in one state may have a 

very different impact in that state than 

on other states in the region. Thus, EPA 

does not believe it is necessary to allow 

total regional allowance allocations for 

the states covered by a given trading 

program to exceed the sum of all state 

budgets without variability for these 

states. 

For these reasons, the fact that the use 

of state budgets with variability limits 

may allow limited shifting of emissions 

between states is not inconsistent with 

the court’s holding that emission 

reductions must occur ‘‘within the 

state.’’ North Carolina, 531 F.3d at 907. 

Under the FIPs, no state may emit more 

than its budget with variability limit 

and total emissions cannot exceed the 

sum of all state budgets without 

variability. This approach takes into 

account the inherent variability of the 

baseline emissions without excusing 

any state from eliminating its significant 

contribution to nonattainment or 

interference with maintenance. It is thus 

consistent with the statutory mandate of 

section 110(a)(2)(D)(i)(I) as interpreted 

by the Court. 

Most commenters voiced support for 

a remedy option that allows some 

degree of interstate trading. However, 

one commenter argued that the structure 

of the preferred trading remedy that 

EPA proposed is legally problematic. 

The program, the commenter argues, 

provides no legal assurance that the 

variability margins will be used by 

market participants to account for 

variability. The commenter does not 

suggest a solution, but instead says, if a 

solution cannot be found, EPA should 

not allow any amount of interstate 

trading. 

EPA disagrees with the commenter 

that the structure of the preferred 

interstate trading program is legally 

problematic. In North Carolina, the 

Court held that the CAIR interstate 

trading programs were inconsistent with 

section 110(a)(2)(D)(i)(I), concluding 

that ‘‘EPA’s apportionment decisions 

have nothing to do with each state’s 

‘significant contribution’ ’’ (531 F.3d at 


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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 

measure of their own significant 

contributions. To the contrary, it relates 

their SO2 reductions to their Title IV 

allowances. * * * The allocation of 

NOX caps is similarly arbitrary because 

EPA distributed allowances simply in 

the interest of fairness.’’ 531 F.3d at 930. 

As explained in this rule, EPA has 

addressed these concerns by using 

source specific analysis to identify each 

individual state’s significant 

contribution to nonattainment and 

interference with maintenance, and 

including assurance provisions to 

ensure that the necessary reductions 

occur in each state. The Court did not 

go further to prohibit all interstate 

trading. In fact, it notes that ‘‘after 

rebuilding, a somewhat similar CAIR 

may emerge’’ (531 F.3d at 930). For all 

of these reasons, EPA does not believe 

the opinion in North Carolina can be 

read to stand for the proposition that no 

interstate trading can be allowed unless 

the specific reasons behind market 

participants’ decisions to purchase 

allowances can be ascertained. Because 

allowance purchase decisions are likely 

to be based on multiple factors, which 

can include the desire to hedge against 

potential emission variability as well as 

to address actually occurring variability, 

requiring ascertainment of the specific 

reasons for allowance purchases would 

be tantamount to prohibiting all 

interstate trading. 

Moreover, as discussed above, 

variability is inherent to the operation of 

the electric generation system and thus 

to emissions from this sector. In fact, 

variability in emissions occurs every 

year in every state and, like variability 

of year-to-year weather conditions 

(which is a major cause of emission 

variability), cannot be accurately 

predicted. See the Power Sector 

Variability Final Rule TSD in the docket 

for this rulemaking. EPA maintains that 

its approach of allowing state EGU 

emissions each year to vary by up to the 

historically representative, annual 

amount of inherent, emission variability 

reasonably reflects the realities of the 

electric generation system and is 

consistent with the North Carolina 

decision. In summary, the variability 

limits take into account inherent 

variability over time of emissions in 

each state from this sector while also 

ensuring that each state makes 

necessary emission reductions to 

eliminate significant contribution and 

interference with maintenance. EPA 

thus concludes that the commenter’s 

argument that the use of variability 

limits allows sources ‘‘within the state’’ 

to avoid eliminating their significant 

contribution or interference with 

maintenance is without merit. 

VIII. Economic Impacts of the 

Transport Rule 

A. Emission Reductions 

The projected impacts of this final 

rule as presented throughout the 

preamble do not reflect minor technical 

corrections to SO2 budgets in three 

states (KY, MI, and NY) made after the 

impact analyses were conducted. These 

projections also assumed preliminary 

variability limits that were smaller than 

the variability limits finalized in this 

rule. EPA conducted sensitivity analysis 

confirming that these differences do not 

meaningfully alter any of the Agency’s 

findings or conclusions based on the 

projected cost, benefit, and air quality 

impacts presented for the final 

Transport Rule. The results of this 

sensitivity analysis are presented in 

Appendix F in the final Transport Rule 

RIA. 

Table VIII.A–1 presents projected 

power sector emissions in the base case 

(i.e., without the Transport Rule or 

CAIR) compared to projected emissions 

with the Transport Rule in 2012 and 

2014 for all covered states. Table VIII.A– 

2 presents 2005 historical power sector 

emissions compared to projected 

emissions with the Transport Rule in 

2012 and 2014. Note that for ozoneseason 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 

Ozone-Season NOX ......................................................... 0.7 0.6 0.1 0.7 0.6 0.1 

Notes: The SO2 and annual NOX emissions 

in this table reflect EGUs in the 23 states 

covered by this rule for purposes of the 24- 

hour and/or annual PM2.5 NAAQS (Alabama, 

Georgia, Illinois, Indiana, Iowa, Kansas, 

Kentucky, Maryland, Michigan, Minnesota, 

Missouri, Nebraska, New Jersey, New York, 

North Carolina, Ohio, Pennsylvania, South 

Carolina, Tennessee, Texas, Virginia, West 

Virginia, and Wisconsin). 

The ozone-season NOX emissions reflect 

EGUs in the 20 states covered by this rule for 

purposes of the ozone NAAQS (Alabama, 

Arkansas, Florida, Georgia, Illinois, Indiana, 

Kentucky, Louisiana, Maryland, Mississippi, 

New Jersey, New York, North Carolina, Ohio, 

Pennsylvania, South Carolina, Tennessee, 

Texas, Virginia, and West Virginia) and the 

six states that would be covered for the ozone 

NAAQS if EPA finalizes its supplemental 

proposal (Iowa, Kansas, Michigan, Missouri, 

Oklahoma, and Wisconsin). 

Tables VIII.A–3 through VIII.A–5 

present projected state-level emissions 

with and without the Transport Rule in 

2012 and 2014 from fossil-fuel-fired 

EGUs greater than 25 MW in covered 

states. 


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TABLE VIII.A–2—PROJECTED SO2 AND NOX ELECTRIC GENERATING UNIT EMISSION REDUCTIONS IN COVERED STATES

WITH THE TRANSPORT RULE COMPARED TO 2005 ACTUAL EMISSIONS

[Million tons] 

2005 

Actual 

emissions 

2012 

Transport 

rule 

emissions 

2012 

Emission 

reductions 

from 2005 

2014 

Transport 

rule 

emissions 

2014 

Emission 

reductions 

from 2005 

SO2 .......................................................................................................... 8.8 3.0 5.8 2.4 6.4 

Annual NOX ............................................................................................. 2.6 1.3 1.3 1.2 1.4 

Ozone-Season 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). 


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91As described in the Air Quality Modeling Final 

Rule TSD, the eastern U.S. was modeled at a 

horizontal resolution of 12 x 12 km. The remainder 

of the U.S. was modeled at a resolution of 36 x 36 

km. 

92To 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. 

BILLING CODE 6560–50–C 

B. The Impacts on PM2.5 and Ozone of 

the Final SO2 and NOX Strategy 

The air quality modeling platform 

described in section V was used by EPA 

to model the impacts of the final rule 

SO2 and NOX emission reductions on 

annual average PM2.5, 24-hour PM2.5, 

and 8-hour ozone concentrations. In 

brief, we ran the CAMx model for the 

meteorological conditions in the year of 

2005 for the eastern U.S. modeling 

domain.91 Modeling was performed for 

the 2014 base case and the 2014 air 

quality-assured trading (i.e., remedy) 

scenario to assess the expected effects of 

the final rule on projected PM2.5 and 

ozone design value concentrations and 

nonattainment and maintenance. The 

procedures used to project future design 

values and nonattainment and 

maintenance are described in section V. 

The projected 2014 concentrations of 

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

at each monitoring site in the East for 

which projections were made are 

provided in the Air Quality Modeling 

Final Rule TSD. The number of 

nonattainment and/or maintenance sites 

in the East for the 2012 base case, 2014 

base case, and 2014 remedy for annual 

PM2.5, 24-hour PM2.5, and ozone are 

provided in Table VIII.B–1.92 The 

average and peak reductions in annual 

PM2.5, 24-hour PM2.5, and ozone 

predicted at 2012 nonattainment and/or 

maintenance sites due the emission 

reductions between 2012 and the 2014 

remedy are provided in Table VIII.B–2. 


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93 ‘‘Nonattainment’’ is used to denote sites that 

are projected to have both nonattainment and 

maintenance problems. 

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) 

Percent reduction: 2014 

base case vs. 

2014 remedy 

Annual PM2.5 Nonattainment Sites 93 ........ 103 12 7 0 100 100 percent. 

Annual PM2.5 Maintenance-Only Sites ...... 22 4 3 0 100 100 percent. 

24-hour PM2.5 Nonattainment Sites .......... 151 20 10 1 95 90 percent. 

24-hour PM2.5 Maintenance-Only Sites ..... 48 21 12 4 81 67 percent. 

Ozone Nonattainment Sites ...................... 104 7 4 4 43 No Change. 

Ozone Maintenance-Only Sites ................. 65 9 6 6 33 No Change. 

TABLE VIII.B–2—AVERAGE AND PEAK REDUCTION IN ANNUAL PM2.5, 24-HOUR PM2.5, AND OZONE FOR SITES THAT ARE

PROJECTED TO HAVE NONATTAINMENT AND/OR MAINTENANCE PROBLEMS IN THE 2012 BASE CASE

Average reduction: 

2012 base Case to 

2014 remedy 

Peak reduction: 

2012 base case to 

2014 remedy 

Annual PM2.5 Nonattainment Sites ......................................................................................................... 2.73 μg/m3 ............. 3.32 μg/m3. 

Annual PM2.5 Maintenance-Only Sites ................................................................................................... 2.99 μg/m3 ............. 3.26 μg/m3. 

24-hour PM2.5 Nonattainment Sites ........................................................................................................ 6.8 μg/m3 ............... 11.7 μg/m3. 

24-hour PM2.5 Maintenance-Only Sites .................................................................................................. 6.5 μg/m3 ............... 11.0 μg/m3. 

Ozone Nonattainment Sites .................................................................................................................... 1.9 ppb ................... 2.3 ppb. 

Ozone Maintenance-Only Sites .............................................................................................................. 1.8 ppb ................... 2.1 ppb. 

The information in Table VIII.B–1 

shows that there will be significant 

reductions in the extent of 

nonattainment and maintenance 

problems for annual PM2.5, 24-hour 

PM2.5, and ozone between 2012 and 

2014 as a result of the emission budgets 

in this rule coupled with emission 

reductions during this time period from 

other existing control programs. 

Specifically, the results of the air quality 

modeling indicate that no sites are 

projected to be in nonattainment or 

projected to have a maintenance 

problem for annual PM2.5 in 2014 with 

the emission reductions expected from 

the Transport Rule. As indicated in 

Table VIII.B–2, the average reduction in 

annual PM2.5 across the twelve 2012 

nonattainment sites is 2.73 μg/m3 and 

the peak reduction at an individual 

nonattainment site is 3.32 μg/m3. Large 

reductions are also projected at annual 

PM2.5 maintenance-only sites. 

For 24-hour PM2.5, we project that the 

number of nonattainment sites will be 

reduced by 95 percent and the number 

of maintenance-only sites by 81 percent 

in 2014 compared to the 2012 base case. 

The average reduction in 24-hour PM2.5

across the twenty 2012 nonattainment 

sites is 6.8 μg/m3 and the peak 

reduction at an individual 

nonattainment site is 11.7 μg/m3. 

Similarly large reductions are projected 

at 24-hour PM2.5 maintenance-only 

sites, as indicated in Table VIII.B–2. 

The emission reductions in the 

Transport Rule will result in 

considerable progress toward attainment 

and maintenance at the 5 sites that 

remain as nonattainment and/or 

maintenance for the 24-hour PM2.5

standard. On average for these 5 sites, 

the predicted amount of PM2.5 reduction 

in 2014 is 64 percent of what is needed 

for these sites to attain and/or maintain 

the 24-hour standard. 

Thus, the SO2 and NOX emission 

reductions which will result from the 

Transport Rule will greatly reduce the 

extent of PM2.5 nonattainment and 

maintenance problems by 2014 and 

beyond. As described previously, these 

emission reductions are expected to 

substantially reduce the number of 

PM2.5 nonattainment and/or 

maintenance sites in the East and make 

attainment easier for those counties that 

remain nonattainment by substantially 

lowering PM2.5 concentrations in 

residual nonattainment sites. The 

emission reductions will also help those 

locations that may have maintenance 

problems. 

Based on the 2012 base air quality 

modeling for ozone, 16 sites in the East 

are projected to be nonattainment or 

have problems maintaining the 1997 

ozone standard. The summer NOX

reductions are projected to lower 8-hour 

ozone concentration by 1.8 ppb, on 

average by 2014, at monitoring sites 

projected to be nonattainment and/or 

have maintenance problems in the 2012 

base case. We expect that the number of 

nonattainment sites will be reduced by 

43 percent and the number of 

maintenance-only sites by 33 percent in 

2014 compared to the 2012 base case. 

Thus, our modeling indicates that by 

2014 the summer NOX emission 

reductions in this rule, coupled with 

other existing control programs, will 

lower ozone concentrations in the East 

and help bring areas closer to 

attainment for the 8-hour ozone 

NAAQS. As discussed in section III of 

this preamble, EPA plans to finalize its 

reconsideration of the 2008 revised 

ozone NAAQS soon, and these 

reductions will help areas achieve those 

revised NAAQS. 

C. Benefits 

1. Human Health Benefit Analysis 

To estimate the human health benefits 

of the final Transport Rule, EPA used 

the BenMAP model to quantify the 

changes in PM2.5 and ozone-related 

health impacts and monetized benefits 

based on changes in air quality. For 

context, it is important to note that the 

magnitude of the PM2.5 benefits is 

largely driven by the concentration 

response function for premature 

mortality. Experts have advised EPA to 

consider a variety of assumptions, 

including estimates based both on 

empirical (epidemiological) studies and 

judgments elicited from scientific 

experts, to characterize the uncertainty 

in the relationship between PM2.5


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94Pope 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. 95Laden et al., 2006. ‘‘Reduction in Fine 

Particulate Air Pollution and Mortality.’’ American 

Journal of Respiratory and Critical Care Medicine. 

173:667–672. 96Fann 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. 

concentrations and premature mortality. 

For this rule we cite two key empirical 

studies, one based on the American 

Cancer Society cohort study 94 and the 

other based on the extended Six Cities 

cohort study.95

The estimated benefits of this rule are 

substantial, particularly when viewed 

within the context of the total public 

health burden of PM2.5 and ozone air 

pollution. A recent EPA analysis 

estimated that 2005 levels of PM2.5 and 

ozone were responsible for between 

130,000 and 320,000 PM2.5-related and 

4,700 ozone-related premature deaths, 

or about 6.1 percent of total deaths from 

all causes in the continental U.S. (using 

the lower end of the range for premature 

deaths).96 In other words, 1 in 20 deaths 

in the U.S. is attributable to PM2.5 and 

ozone exposure. This same analysis 

attributed almost 200,000 non-fatal 

heart attacks, 90,000 hospital 

admissions due to respiratory or 

cardiovascular illness, 2.5 million cases 

of aggravated asthma among children, 

and many other human health impacts 

to exposure to these two air pollutants. 

We estimate that PM2.5 improvements 

under the Transport Rule will, starting 

in 2014, annually reduce between 

13,000 and 34,000 PM2.5-related 

premature deaths, 15,000 non-fatal heart 

attacks, 8,700 incidences of chronic 

bronchitis, 8,500 hospital admissions, 

and 400,000 cases of aggravated asthma 

while also reducing 10 million days of 

restricted activity due to respiratory 

illness and approximately 1.7 million 

work-loss days. We also estimate 

substantial health improvements for 

children from fewer cases of upper and 

lower respiratory illness and acute 

bronchitis. 

Ozone health-related benefits are 

expected to occur during the summer 

ozone season (usually ranging from May 

to September in the eastern U.S.). Based 

upon modeling for 2014, annual ozone 

related health benefits are expected to 

include between 27 and 120 fewer 

premature mortalities, 240 fewer 

hospital admissions for respiratory 

illnesses, 86 fewer emergency room 

admissions for asthma, 160,000 fewer 

days with restricted activity levels, and 

51,000 fewer days where children are 

absent from school due to illnesses. 

Table VIII.C–1 presents the primary 

estimates of annual reduced incidence 

of PM2.5 and ozone-related health effects 

for the final rule based on 2014 air 

quality improvements. When adding the 

PM and ozone-related mortalities 

together, we find that the Transport 

Rule will yield between 13,000 and 

34,000 fewer premature mortalities 

annually. By 2014, in combination with 

other federal and state air quality 

actions, the Transport Rule will address 

a substantial fraction of the total public 

health burden of PM2.5 and ozone air 

pollution. 

BILLING CODE 6560–50–P 


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2. Quantified and Monetized Visibility 

Benefits 

Only a subset of the expected 

visibility benefits—those for Class I 

areas—are included in the monetary 

benefit estimates we project for this 

rule. We anticipate improvement in 

visibility in residential areas where 

people live, work, and recreate within 

the Transport Rule region for which we 

are currently unable to monetize 

benefits. For the Class I areas we 

estimate annual benefits of $4.1 billion 

beginning in 2014 for visibility 

improvements. The value of visibility 

benefits in areas where we are unable to 

monetize benefits could be substantial. 

3. Benefits of Reducing GHG Emissions 

When fully implemented in 2014, the 

Transport Rule will reduce emissions of 

CO2 from electrical generating units by 

about 25 million metric tons annually. 

Using a ‘‘social cost of carbon’’ (SCC) 

estimate that accounts for the marginal 

dollar value (i.e., cost) of climate-related 

damages resulting from CO2 emissions, 

previous analyses, including the RIA for 

the Final Rulemaking to Establish LightDuty 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 

Table VIII.C–2 presents the estimated 

annual monetary value of reductions in 

the incidence of health and welfare 

effects. These estimates account for 

increases in the value of risk reduction 

over time. Total monetized benefits are 

driven primarily by the reduction in 

premature fatalities each year, which 

account for between 89 and 96 percent 

of total benefits. 


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BILLING CODE 6560–50–C 

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 

Transport Rule states are $1.85 billion 

in 2012 and $0.83 billion in 2014 (2007 

$). These costs are the annual 

incremental electric generation 

production costs that are expected to 

occur with the Transport Rule. The EPA 

uses these costs as compliance cost 

estimates in developing costeffectiveness estimates. 

In estimating the net benefits of 

regulation, the appropriate cost measure 

is ‘‘social costs.’’ Social costs represent 

the welfare costs of the rule to society. 

These costs do not consider transfer 

payments (such as taxes) that are simply 

redistributions of wealth. The social 

costs of this rule are estimated to be 

approximately $0.81 billion in 2014 

assuming either a 3 percent discount 

rate or a 7 percent discount rate. Thus, 

the annual net benefit (social benefits 

minus social costs) as shown in Table 

VIII.C–3 for the Transport Rule is 

approximately $120 to $280 billion or 


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97 In this analysis, we adjust the VSL to account 

for a different currency year (2007$) and to account 

for income growth to 2014. After applying these 

adjustments to the $6.3 million value, the VSL is 

$8.7 million. 

$110 to $250 billion (3 percent and 7 

percent discount rates, respectively) in 

2014. Implementation of the rule is 

expected to provide society with a 

substantial net gain in social welfare 

based on economic efficiency criteria. 

A listing of the benefit categories that 

could not be quantified or monetized in 

our benefit estimates is provided in 

Table VIII.C–4. 

TABLE VIII.C–3—SUMMARY OF ANNUAL BENEFITS, COSTS, AND NET BENEFITS OF THE FINAL TRANSPORT RULE IN 2014 

[Billions of 2007$] a

Description 

Transport Rule remedy 

(billions of 2007 $) 

3% discount rate 7% discount rate 

Social costs ...................................................................................................................................... $0.81 ......................... $0.81. 

Total monetized benefits b ............................................................................................................... $120 to $280 ............. $110 to $250. 

Net benefits (benefits-costs) ............................................................................................................ $120 to $280 ............. $110 to $250. 

aAll 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 

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 reemployed elsewhere in the economy, 

and certain relatively small permitting 

costs associated with Title V that new 

program entrants face. 

An optimization model was employed 

that assumes cost minimization. Costs 

may be understated if the regulated 

community chooses not to minimize its 

compliance costs in the same manner to 

comply with the rules. Although EPA 

has not quantified these costs, the 

Agency believes that they are small 

compared with the quantified costs of 

the program to the power sector. 

However, EPA’s experience and results 

of independent evaluation suggests that 

costs are likely to be lower by some 

degree (see RIA for details). The 

annualized cost estimates presented are 

the best and most accurate based upon 

available information. In a separate 

analysis, EPA estimates the indirect 

costs and impacts of higher electricity 

prices on the entire economy. These 

impacts are summarized in the RIA for 

this final rule. 

Every benefit-cost analysis examining 

the potential effects of a change in 

environmental protection requirements 

is limited to some extent by data gaps, 

model capabilities (such as geographic 

coverage), and uncertainties in the 

underlying scientific and economic 

studies used to configure the benefit and 

cost models. Gaps in the scientific 

literature often result in the inability to 

estimate quantitative changes in health 

and environmental effects, or to assign 

economic values even to those health 

and environmental outcomes that can be 

quantified. While uncertainties in the 

underlying scientific and economics 

literatures (that may result in 

overestimation or underestimation of 

benefits) are discussed in detail in the 

economic analyses and its supporting 

documents and references, the key 

uncertainties which have a bearing on 

the results of the benefit-cost analysis of 

this rule include the following: 

• EPA’s inability to quantify 

potentially significant benefit categories; 

• Uncertainties in population growth 

and baseline incidence rates; 

• Uncertainties in projection of 

emission inventories and air quality into 

the future; 

• Uncertainty in the estimated 

relationships of health and welfare 

effects to changes in pollutant 

concentrations, including the shape of 

the C–R function, the size of the effect 

estimates, and the relative toxicity of the 

many components of the PM mixture; 

• Uncertainties in exposure 

estimation; and 

• Uncertainties associated with the 

effect of potential future actions to limit 

emissions. 

Despite these uncertainties, we 

believe the benefit-cost analysis 

provides a reasonable indication of the 

expected economic benefits of the 

rulemaking in future years under a set 

of reasonable assumptions. This 

approach calculates a mean value across 

value of a statistical life (VSL) estimates 

derived from 26 labor market and 

contingent valuation studies published 

between 1974 and 1991. The mean VSL 

across these studies is $6.3 million 

(2000$).97 The benefits estimates 

generated for this rule are subject to a 

number of assumptions and 

uncertainties, which are discussed 

throughout the RIA document. 

As Table VIII.C–2 indicates, total 

annual monetary benefits are driven 

primarily by the reduction in premature 

mortalities each year. Some key 

assumptions underlying the primary 

estimate for the premature mortality 

category include the following: 

(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. 


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(2) EPA assumes all fine particles, 

regardless of their chemical 

composition, are equally potent in 

causing premature mortality. This is an 

important assumption, because the 

proportion of certain components in the 

PM mixture produced via precursors 

emitted from EGUs may differ 

significantly from direct PM released 

from automotive engines and other 

industrial sources, but no clear 

scientific grounds exist for supporting 

differential effects estimates by particle 

type. 

(3) We assume that the health impact 

function for fine particles is linear down 

to the lowest air quality levels modeled 

in this analysis. Thus, the estimates 

include health benefits from reducing 

fine particles in areas with varied 

concentrations of PM2.5, including both 

regions that are in attainment with the 

fine particle standard and those that do 

not meet the standard down to the 

lowest modeled concentrations. 

The EPA recognizes the difficulties, 

assumptions, and inherent uncertainties 

in the overall enterprise. The analyses 

upon which the Transport Rule is based 

were selected from the peer-reviewed 

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: Health a ......................... Low birth weight. 

Pulmonary function. 

Chronic respiratory diseases other than chronic bronchitis. 

Non-asthma respiratory emergency room visits. 

UVb exposure b. 

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 exposure b. 

Global climate impacts b. 

Ozone: Health ...................... Chronic respiratory damage. 

Premature aging of the lungs. 

Non-asthma respiratory emergency room visits. 

UVb exposure b. 

Ozone: Welfare .................... Yields for: 

—Commercial forests. 

—Fruits and vegetables, and 

—Other commercial and noncommercial crops. 

Damage to urban ornamental plants. 

Recreational demand from damaged forest aesthetics. 

Ecosystem functions. 

Increased exposure to UVb b. 

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 mechanisms. The public health impact of these biological responses may be partly represented by our quantified endpoints. b May result in benefits or disbenefits. 


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98U.S. Environmental Protection Agency (U.S. 

EPA). 2008. Integrated Science Assessment for 

Oxides of Nitrogen and Sulfur—Ecological Criteria 

National (Final Report). National 

Center for Environmental Assessment, Research 

Triangle Park, NC. EPA/600/R–08/139. December. 

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

deid=201485. 

99 Joslin, J.D., Kelly, J.M., van Miegroet, H. 1992. 

Soil chemistry and nutrition of North American 

spruce-fir stands: evidence for recent change. 

Journal of Environmental Quality, 21, 12–30. 

100 DeHayes, D.H., P.G. Schaberg, G.J. Hawley, 

and G.R. Strimbeck. 1999. Acid rain impacts on 

calcium nutrition and forest health. Bioscience 

49(10):789–800. 

101National Oceanic and Atmospheric 

Administration (NOAA). 2007. Annual Commercial 

Landing Statistics. August. http://www.st.nmfs.

noaa.gov/st1/commercial/landings/annual_

landings.html. 

102 Valigura, R.A., R.B. Alexander, M.S. Castro, 

T.P. Meyers, H.W. Paerl, P.E. Stacy, and R.E. 

Turner. 2001. Nitrogen Loading in Coastal Water 

7. What are the unquantified and nonmonetized 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 cobenefits due to Transport Rule 

compliance. These benefits are listed in 

Table VIII.C–4. Some of the more 

important examples include: Reduced 

acidification and, in the case of NOX, 

eutrophication of water bodies; possible 

reduced nitrate contamination of 

drinking water; and reduced acid and 

particulate deposition that causes 

damages to cultural monuments, as well 

as, soiling and other materials damage. 

To illustrate the important nature of 

benefit categories EPA is currently 

unable to monetize, we discuss four 

categories of public welfare and 

environmental impacts related to 

reductions in emissions required by the 

Transport Rule: Reduced acid 

deposition, reduced eutrophication of 

estuaries, reduced mercury methylation 

and deposition, and reduced vegetation 

impairment from ozone. 

a. What are the benefits of reduced 

deposition of sulfur and nitrogen to 

aquatic, forest, and coastal ecosystems? 

Atmospheric deposition of sulfur and 

nitrogen, often referred to as acid rain, 

occurs when emissions of SO2 and NOX

react in the atmosphere (with water, 

oxygen, and oxidants) to form various 

acidic compounds. These acidic 

compounds fall to earth in either a wet 

form (rain, snow, and fog) or a dry form 

(gases and particles). Prevailing winds 

can transport acidic compounds 

hundreds of miles, across state borders. 

These compounds are deposited onto 

terrestrial and aquatic ecosystems across 

the U.S., contributing to the problems of 

acidification. 

(1) Acid Deposition and Acidification of 

Lakes and Streams 

The extent of adverse effects of acid 

deposition on freshwater and forest 

ecosystems depends largely upon the 

ecosystem’s ability to neutralize the 

acid. The neutralizing ability depends 

largely on the watershed’s physical 

characteristics, such as geology, soils, 

and size. A key indicator of neutralizing 

ability is termed Acid Neutralizing 

Capacity (ANC). Higher ANC indicates 

greater ability to neutralize acidity. 

Acidic conditions occur more frequently 

during rainfall and snowmelt that cause 

high flows of water, and less commonly 

during low-flow conditions except 

where chronic acidity conditions are 

severe. Biological effects are primarily 

attributable to a combination of low pH 

and high inorganic aluminum 

concentrations. Biological effects of 

episodes include reduced fish condition 

factor—changes in species composition 

and declines in aquatic species richness 

across multiple taxa, ecosystems and 

regions—as well as fish mortality. 

Waters that are sensitive to acidification 

tend to be located in small watersheds 

that have few alkaline minerals and 

shallow soils. Conversely, watersheds 

that contain alkaline minerals, such as 

limestone, tend to have waters with a 

high ANC. Areas especially sensitive to 

acidification include portions of the 

Northeast (particularly, the Adirondack 

and Catskill Mountains, portions of New 

England, and streams in the midAppalachian highlands) and 

southeastern streams. This regulatory 

action will decrease acid deposition 

within and downwind of the transport 

region and is likely to have positive 

effects on the health and productivity of 

aquatic ecosystems in the region. 

(2) Acid Deposition and Forest 

Ecosystem Impacts 

Acidifying deposition has altered 

major biogeochemical processes in the 

U.S. by increasing the nitrogen and 

sulfur content of soils, accelerating 

nitrate and sulfate leaching from soil to 

drainage waters, depleting base cations 

(especially calcium and magnesium) 

from soils, and increasing the mobility 

of aluminum. Inorganic aluminum is 

toxic to some tree roots. Plants affected 

by high levels of aluminum from the 

soil often have reduced root growth, 

which restricts the ability of the plant to 

take up water and nutrients, especially 

calcium.98 These direct effects can, in 

turn, influence the response of these 

plants to climatic stresses such as 

droughts and cold temperatures. They 

can also influence the sensitivity of 

plants to other stresses, including insect 

pests and disease,99 leading to increased 

mortality of canopy trees. 

Both coniferous and deciduous forests 

throughout the eastern U.S. are 

experiencing gradual losses of base 

cation nutrients from the soil due to 

accelerated leaching from acidifying 

deposition. This change in nutrient 

availability may reduce the quality of 

forest nutrition over the long term. 

Evidence suggests that red spruce and 

sugar maple in some areas in the eastern 

U.S. have experienced declining health 

because of this deposition. For red 

spruce (Picea rubens), dieback or 

decline has been observed across high 

elevation landscapes of the northeastern 

U.S. and, to a lesser extent, the 

southeastern U.S. Acidifying deposition 

has been implicated as a causal 

factor.100

This regulatory action will decrease 

acid deposition within and downwind 

of the transport region and is likely to 

have positive effects on the health and 

productivity of forest systems in the 

region. 

b. Coastal Ecosystems 

Since 1990, a large amount of research 

has been conducted on the impact of 

nitrogen deposition to coastal waters. 

Nitrogen is often the limiting nutrient in 

coastal ecosystems. Increasing the levels 

of nitrogen in coastal waters can cause 

significant changes to those ecosystems. 

In recent decades, human activities have 

accelerated nitrogen nutrient inputs, 

causing excessive growth of algae and 

leading to degraded water quality and 

associated impairments of estuarine and 

coastal resources. 

Atmospheric deposition of nitrogen is 

a significant source of nitrogen to many 

estuaries. The amount of nitrogen 

entering estuaries due to atmospheric 

deposition varies widely, depending on 

the size and location of the estuarine 

watershed and other sources of nitrogen 

in the watershed. A recent assessment of 

141 estuaries nationwide by the 

National Oceanic and Atmospheric 

Administration (NOAA) concluded that 

19 estuaries (13 percent) suffered from 

moderately high or high levels of 

eutrophication due to excessive inputs 

of both nitrogen and phosphorus, and a 

majority of these estuaries are located in 

the coastal area from North Carolina to 

Massachusetts.101 For estuaries in the 

Mid-Atlantic region, the contribution of 

atmospheric distribution to total 

nitrogen loads is estimated to range 

between 10 percent and 58 percent.102


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DC: American Geophysical Union. 

103U.S. Environmental Protection Agency (U.S. 

EPA). 2008. Integrated Science Assessment for 

Sulfur Oxides—Health Criteria (Final Report). 

National Center for Environmental Assessment, 

Research Triangle Park, NC. September. http://

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198843. 

104 Drevnick, P.E., D.E. Canfield, P.R. Gorski, 

A.L.C. Shinneman, D.R. Engstrom, D.C.G. Muir, 

G.R. Smith, P.J. Garrison, L.B. Cleckner, J.P. Hurley, 

R.B. Noble, R.R. Otter, and J.T. Oris. 2007. 

Deposition and cycling of sulfur controls mercury 

accumulation in Isle Royale fish. Environmental 

Science and Technology 41(21):7266–7272. 

105Munthe, 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 mercurycontaminated fisheries. AMBIO:A Journal of the 

Human Environment 36:33–44. 

106Fox, S., Mickler, R.A. (Eds.). 1996. Impact of 

Air Pollutants on Southern Pine Forests. Ecological 

Studies. (Vol. 118, 513 pp.) New York: SpringerVerlag. 

107U.S. Environmental Protection Agency (U.S. 

EPA). 2006. Air Quality Criteria for Ozone and 

Related Photochemical Oxidants (Final). EPA/600/ 

R–05/004aF–cF. Washington, DC: U.S. EPA. 

February. http://cfpub.epa.gov/ncea/CFM/

recordisplay.cfm?deid=149923. 

108 De Steiguer, J., Pye, J., Love, C. 1990. Air 

Pollution Damage to U.S. Forests. Journal of 

Forestry, 88(8), 17–22. 

109Pye, J.M. 1988. Impact of ozone on the growth 

and yield of trees: A review. Journal of 

Environmental Quality, 17, 347–360. 

110Chappelka, A.H., Samuelson, L.J. 1998. 

Ambient ozone effects on forest trees of the eastern 

United States: a review. New Phytologist, 139, 91– 

108. 

111Heck, W.W. & Cowling, E.B. 1997. The need 

for a long term cumulative secondary ozone 

standard—an ecological perspective. Environmental 

Management, January, 23–33. 

112U.S. Environmental Protection Agency (U.S. 

EPA). 2007. Review of the National Ambient Air 

Quality Standards for Ozone: Policy assessment of 

scientific and technical information. Staff paper. 

Office of Air Quality Planning and Standards. EPA– 

452/R–07–007a. July. http://www.epa.gov/ttn/

naaqs/standards/ozone/data/2007_07_ozone_staff_

paper.pdf. 

113Abt Associates, Inc. 2005. U.S. EPA. Urban 

ornamental plants: sensitivity to ozone and 

potential economic losses. Memorandum to Bryan 

Hubbell and Zachary Pekar. 

Eutrophication in estuaries is 

associated with a range of adverse 

ecological effects. The conceptual 

framework developed by NOAA 

emphasizes four main types of 

eutrophication effects: low dissolved 

oxygen (DO), harmful algal blooms 

(HABs), loss of submerged aquatic 

vegetation (SAV), and low water clarity. 

Low DO disrupts aquatic habitats, 

causing stress to fish and shellfish, 

which, in the short-term, can lead to 

episodic fish kills and, in the long-term, 

can damage overall growth in fish and 

shellfish populations. Low DO also 

degrades the aesthetic qualities of 

surface water. In addition to often being 

toxic to fish and shellfish, and leading 

to fish kills and aesthetic impairments 

of estuaries, HABs can, in some 

instances, also be harmful to human 

health. SAV provides critical habitat for 

many aquatic species in estuaries and, 

in some instances, can also protect 

shorelines by reducing wave strength. 

Therefore, declines in SAV due to 

nutrient enrichment are an important 

source of concern. Low water clarity is 

the result of accumulations of both algae 

and sediments in estuarine waters. In 

addition to contributing to declines in 

SAV, high levels of turbidity also 

degrade the aesthetic qualities of the 

estuarine environment. 

Estuaries in the eastern United States 

are an important source of food 

production, in particular fish and 

shellfish production. The estuaries are 

capable of supporting large stocks of 

resident commercial species, and they 

serve as the breeding grounds and 

interim habitat for several migratory 

species. 

This rule is anticipated to reduce 

nitrogen deposition within and 

downwind of the Transport Rule states. 

Thus, reductions in the levels of 

nitrogen deposition will have a positive 

impact upon current eutrophic 

conditions in estuaries and coastal areas 

in the region. 

c. Mercury Methylation and Deposition 

Mercury is a highly neurotoxic 

contaminant that enters the food web as 

a methylated compound, 

methylmercury.103 The contaminant is 

concentrated in higher trophic levels, 

including fish eaten by humans. 

Experimental evidence has established 

that only inconsequential amounts of 

methylmercury can be produced in the 

absence of sulfate. Current evidence 

indicates that in watersheds where 

mercury is present, increased SOX

deposition very likely results in 

methylmercury accumulation in 

fish.104 105 The SO2 Integrated Science 

Assessment concluded that evidence is 

sufficient to infer a causal relationship 

between sulfur deposition and increased 

mercury methylation in wetlands and 

aquatic environments. 

d. Ozone Vegetation Effects 

Ozone causes discernible injury to a 

wide array of vegetation.106 In terms of 

forest productivity and ecosystem 

diversity, ozone may be the pollutant 

with the greatest potential for regionalscale forest impacts.107 Studies have 

demonstrated repeatedly that ozone 

concentrations commonly observed in 

polluted areas can have substantial 

impacts on plant function.108 109

Assessing the impact of ground-level 

ozone on forests in the eastern United 

States involves understanding the risks 

to sensitive tree species from ambient 

ozone concentrations and accounting for 

the prevalence of those species within 

the forest. As a way to quantify the risks 

to particular plants from ground-level 

ozone, scientists have developed ozoneexposure/tree-response functions by 

exposing tree seedlings to different 

ozone levels and measuring reductions 

in growth as ‘‘biomass loss.’’ Typically, 

seedlings are used because they are easy 

to manipulate and measure their growth 

loss from ozone pollution. The 

mechanisms of susceptibility to ozone 

within the leaves of seedlings and 

mature trees are identical, and the 

decreases predicted using the seedlings 

should be related to the decrease in 

overall plant fitness for mature trees, but 

the magnitude of the effect may be 

higher or lower depending on the tree 

species.110 In areas where certain ozonesensitive species dominate the forest 

community, the biomass loss from 

ozone can be significant. Significant 

biomass loss can be defined as a more 

than 2 percent annual biomass loss, 

which would cause long-term ecological 

harm, as the short-term negative effects 

on seedlings compound to affect longterm forest health.111

Urban ornamentals are an additional 

vegetation category likely to experience 

some degree of negative effects 

associated with exposure to ambient 

ozone levels. Because ozone causes 

visible foliar injury, the aesthetic value 

of ornamentals (such as petunia, 

geranium, and poinsettia) in urban 

landscapes would be reduced. Sensitive 

ornamental species would require more 

frequent replacement and/or increased 

maintenance (fertilizer or pesticide 

application) to maintain the desired 

appearance because of exposure to 

ambient ozone.112 In addition, many 

businesses rely on healthy-looking 

vegetation for their livelihoods (e.g., 

horticulturalists, landscapers, Christmas 

tree growers, farmers of leafy crops, etc.) 

and a variety of ornamental species have 

been listed as sensitive to ozone.113

D. Costs and Employment Impacts 

1. Transport Rule Costs and 

Employment Impacts 

For the affected region, the projected 

annual private incremental costs of the 

rule to the power industry are $1.4 

billion in 2012 and $0.8 billion in 2014. 

These costs represent the private 

compliance cost to the electric 

generating industry of reducing NOX

and SO2 emissions to meet the 

requirements set forth in the rule. 

Estimates are in 2007 dollars. 

In estimating the net benefits of 

regulation, the appropriate cost measure 


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is ‘‘social costs.’’ Social costs represent 

the welfare costs of the rule to society. 

These costs do not consider transfer 

payments (such as taxes) that are simply 

redistributions of wealth. The social 

costs of this rule are estimated to be 

approximately $0.8 billion annually in 

2014. Overall, the economic impacts of 

the Transport Rule are modest in 2014, 

particularly in light of the large benefits 

($120 to $280 billion annually at a 3 

percent discount rate and $110 to $250 

billion annually at a 7 percent discount 

rate) we expect, as shown in section 

XII.A of this preamble. Ultimately, we 

believe the electric power industry will 

pass along most of the costs of the rule 

to consumers, so that the costs of the 

rule will largely fall upon the 

consumers of electricity. For more 

information on electricity price changes 

that result from this final rule, refer to 

section XII.H (Statement of Energy 

Effects) later in this preamble. 

For this rule, EPA analyzed the costs 

using the Integrated Planning Model 

(IPM). The IPM is a dynamic linear 

programming model that can be used to 

examine the economic impacts of air 

pollution control policies for SO2 and 

NOX throughout the contiguous United 

States for the entire power system. 

Documentation for IPM can be found in 

the docket for this rulemaking or at 

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

progsregs/epa-ipm/index.html. 

EPA also included an analysis of 

impacts of the final rule to industries 

outside of the electric power sector by 

using the 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 economic 

impacts for the proposed MATS, and 

the promulgated industrial boilers major 

and area source standards and CISWI 

standard. 

We use the Multi-Market Model to 

estimate the social costs of the final 

rule. Using this model, we estimate the 

social costs of the final rule to be 

approximately $0.8 billion (2007 

dollars), which is close to the 

compliance costs. Documentation for 

the Multi-Market Model can be found in 

the RIA for this final rule. 

Also note that as explained in section 

V.B (Baseline for Pollution Transport 

Analysis), the baseline used in this 

analysis assumes no CAIR. As explained 

in that section, EPA believes that this is 

the most appropriate baseline to use for 

purposes of determining whether an 

upwind state has an impact on a 

downwind monitoring site in violation 

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

Although a stand-alone analysis of 

employment impacts is not included in 

a standard cost-benefit analysis, the 

current economic climate has led to 

heightened concerns about potential job 

impacts. Such an analysis is of 

particular concern in the current 

economic climate as sustained periods 

of excess unemployment may introduce 

a wedge between observed (market) 

wages and the social cost of labor. In 

such conditions, the opportunity cost of 

labor required by regulated sectors to 

bring their facilities into compliance 

with an environmental regulation may 

be lower than it would be during a 

period of full employment (particularly 

if regulated industries employ otherwise 

idled labor to design, fabricate, or install 

the pollution control equipment 

required under this rule). For that 

reason, EPA also includes estimates of 

job impacts associated with the final 

rule. EPA presents an estimate of shortterm employment opportunities as a 

result of increased demand for pollution 

control equipment. Overall, the results 

suggest that the final rule could support 

a net increase of roughly 2,250 job-years 

in direct employment in 2014. 

The basic approach to estimate these 

employment impacts involved using 

projections from IPM from the final rule 

analysis such as the amount of capacity 

that will be retrofit with control 

technologies, for various energy market 

implications, along with data on labor 

and resource needs of new pollution 

controls and labor productivity from 

secondary sources, to estimate 

employment impacts for 2014. This 

analysis was also applied for the 

proposed MATS. For more information, 

refer to Appendix D of the RIA for the 

final Transport Rule.’’ 

EPA relied on Morgenstern, et al. 

(2002), a study that is a basis for 

employment impacts estimated for the 

final industrial boiler major and area 

source rules and CISWI standard, and 

the proposed MATS. The Morgenstern 

study identifies three economic 

mechanisms by which pollution 

abatement activities can indirectly 

influence jobs: (1) Higher production 

costs raise market prices, higher prices 

reduce consumption, and employment 

within an industry falls (‘‘demand 

effect’’); (2) pollution abatement 

activities require additional labor 

services to produce the same level of 

output (‘‘cost effect’’); and (3) post 

regulation production technologies may 

be more or less labor intensive (i.e., 

more/less labor is required per dollar of 

output) (‘‘factor-shift effect’’). 

Using plant-level Census information 

between the years 1979 and 1991, 

Morgenstern, et al., estimate the size of 

each effect for four polluting and 

regulated industries (petroleum, plastic 

material, pulp and paper, and steel). On 

average across the four industries, each 

additional $1 million spending on 

pollution abatement results in a small 

net increase of 1.6 jobs; however, the 

estimated effect is not statistically 

significant. As a result, the authors 

conclude that increases in pollution 

abatement expenditures do not 

necessarily cause economically 

significant employment changes. The 

conclusion is similar to Berman and Bui 

(2001), who found that increased air 

quality regulation in Los Angeles did 

not cause large employment changes. 

For more information, please refer to the 

RIA for this final rule. 

The ranges of job effects calculated 

using the Morgenstern, et al., approach 

are listed in Table VIII.D–1. 

TABLE VIII.D–1—RANGE OF JOB EFFECTS FOR THE ELECTRICITY SECTOR

[Estimates using Morgenstern, et al. (2002)] 

Demand effect Cost effect Factor shift 

effect Net effect 

Change in Full-Time Jobs per Million Dollars of 

Environmental Expenditure a.

¥3.56 ...................... 2.42 .......................... 2.68 .......................... 1.55. 

Standard Error ......................................................... 2.03 .......................... 0.83 .......................... 1.35 .......................... 2.24. 

EPA Estimate for Final Rule b ................................. + 200 to ¥3,000 ..... + 400 to 2,000 ......... 0 to 2,000 ................ ¥1,000 to + 3,000. 

aExpressed in 1987 dollars. See footnote a of Table 8–3 in the RIA for the inflation adjustment factor used in the analysis. bAccording 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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114U.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. 

115Metropolitan Washington Council of 

Governments developed a regional air quality plan 

for the eight-hour ozone standard for the DC Region 

nonattainment area that included an EE measure. 

The plan was adopted by Virginia, Maryland, and 

the District of Columbia and the respective ozone 

SIPs were approved by the EPA regions in 2007. 

116Because 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. 

EPA recognizes there may be other job 

effects which are not considered in the 

Morgenstern, et al., study. Although 

EPA has considered some economywide changes in industry output as 

shown earlier with the Multi-Market 

model, we do not have sufficient 

information to quantify other associated 

job effects associated with this rule. 

2. End-Use Energy Efficiency 

EPA believes that achievement of 

energy efficiency (EE) improvements in 

homes, buildings, and industry is an 

important component of achieving 

emission reductions from the power 

sector while minimizing associated 

compliance costs. By reducing 

electricity demand, energy efficiency 

avoids emissions of all pollutants 

associated with electricity generation, 

including emissions of NOX and SO2

targeted by this final rule, and reduces 

the need for investments in EGU 

emission control technologies in order 

to meet emission reduction 

requirements. Moreover, energy 

efficiency can often be implemented at 

a lower cost than traditional control 

technologies. 

EPA recognizes that significant 

opportunities remain for energy 

efficiency improvements in businesses, 

homes, and industry. However, there are 

several informational and market 

barriers that limit investment in costeffective energy efficient practices. 

Several federal programs authorized 

under the CAA, including ENERGY 

STAR, are designed to address these 

barriers. 

Congress, EPA, and states have all 

recognized the value of incorporating 

energy efficiency into air regulatory 

programs. Several allowance-based 

programs—including the Acid Rain 

Program, EPA’s NOX Budget Trading 

program, and the Regional Greenhouse 

Gas Initiative (an effort of 10 states from 

the Northeast and 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 emission 

caps established by these programs are 

unaffected by this approach. However, 

to the extent electricity demand 

reductions are realized, compliance 

costs are reduced. In addition to these 

allowance-based programs, EPA has also 

provided guidance 114 concerning the 

recognition, in SIPs, of emission 

reduction benefits of energy efficiency 

and has approved the inclusion of EE 

measures in individual SIPs.115

While all remedy options considered 

in the proposed rule would have lead to 

an increase in the relative 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 setasides can be effective at encouraging 

incremental investments in EE, EE setasides are more likely to be practically 

and effectively implemented at the state 

level. Establishing EE set-asides in the 

allowance allocation provisions in the 

final rule would not allow for the 

tailoring of the set-asides to the unique 

characteristics of individual states and 

would not build on the existing EE 

program delivery infrastructure that 

many states already possess. Instead of 

establishing EPA-administered EE setasides 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.116

As discussed elsewhere in this 

preamble, the final rule provides for 

submission and approval of abbreviated 

and full SIPs providing for continued 

state participation in the Transport Rule 

trading programs, and adopting 

alternative allowance allocation 

methodologies (which may include EE 

set-asides) to the allocation 

methodologies adopted in the FIPs. 

While the final rule establishes certain 

requirements for approval of any such 

alternative allocation methodology, the 

final rule provides states flexibility to 

create state-implemented EE set-asides. 

IX. Related Programs and the Transport 

Rule 

A. Transition From the Clean Air 

Interstate Rule 

1. Key Differences Between the 

Transport Rule and CAIR 

The Transport Rule replaces CAIR 

and its associated trading programs. 

There are a number of differences 

between implementation of the 

Transport Rule and implementation of 

CAIR. This section describes key 

implementation differences including 

differences in states covered, 

compliance deadlines, applicability, 

structure of the remedy, provisions for 

early reductions, and provisions for 

SIPs. 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. 


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TABLE IX.A–1—DIFFERENCES IN SO2 AND ANNUAL NOX STATE COVERAGE BETWEEN THE TRANSPORT RULE AND CAIR 

State 

Transport rule 

SO2 and annual NOX

programs 

CAIR SO2

and annual 

NOX programs 

Kansas ........................................................................................................................................................................ Yes ............... No. 

Minnesota ................................................................................................................................................................... Yes ............... No. 

Nebraska ..................................................................................................................................................................... Yes ............... No. 

Delaware ..................................................................................................................................................................... No ................ Yes. 

District of Columbia .................................................................................................................................................... No ................ Yes. 

Florida ......................................................................................................................................................................... No ................ Yes. 

Louisiana ..................................................................................................................................................................... No ................ Yes. 

Mississippi ................................................................................................................................................................... No ................ Yes. 

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 

ozone-season 

NOX program 

CAIR ozoneseason NOX

program 

Georgia ....................................................................................................................................................................... Yes ............... No. 

Texas .......................................................................................................................................................................... Yes ............... No. 

Connecticut ................................................................................................................................................................. No ................ Yes. 

Delaware ..................................................................................................................................................................... No ................ Yes. 

District of Columbia .................................................................................................................................................... No ................ Yes. 

Iowa ............................................................................................................................................................................ No ................ Yes. 

Massachusetts ............................................................................................................................................................ No ................ Yes. 

Michigan ...................................................................................................................................................................... No ................ Yes. 

Missouri ....................................................................................................................................................................... No ................ Yes. 

Wisconsin .................................................................................................................................................................... No ................ Yes. 

In addition, EPA is proposing a 

supplemental notice to apply Transport 

Rule ozone-season requirements to the 

states of Iowa, Kansas, Michigan, 

Missouri, Oklahoma, and Wisconsin, as 

discussed in section III of this preamble. 

The transition from CAIR to the 

Transport Rule is discussed in section 

IX.A.2 and SIPs are discussed in section 

X of this preamble. 

Compliance deadlines. The Transport 

Rule reduction requirements commence 

January 1, 2012 for annual NOX and SO2

requirements and May 1, 2012 for 

ozone-season NOX requirements. More 

stringent SO2 reduction requirements 

commence January 1, 2014 for Group 1 

states. 

In contrast, the first phase of CAIR 

NOX reductions commenced January 1, 

2009 for annual NOX requirements and 

May 1, 2009 for 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 of CAIR reductions would 

have (if not replaced by the Transport 

Rule) commenced January 1, 2015 for 

annual NOX and SO2 requirements, and 

May 1, 2015 for ozone-season NOX

requirements. 

Applicability. Except for the changes 

to the states covered, the general 

applicability provisions of the final 

Transport Rule trading programs are 

essentially the same as the CAIR general 

applicability provisions, with a few 

exceptions. 

First, the final Transport Rule does 

not allow any non-covered units to opt 

into the trading programs, for the 

reasons discussed in section VII.B of 

this preamble. In contrast, under CAIR, 

through SIPs, the states could elect to 

allow boilers, combustion turbines, and 

other combustion devices to opt into the 

CAIR trading programs under opt-in 

provisions specified by EPA. 

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. 

In contrast, in the CAIR trading 

programs, a NOX SIP Call state could 

expand the applicability of the CAIR 

ozone-season NOX trading program in 

the state in order to include all units 

subject to the NOX Budget Trading 

Program under the NOX SIP Call. A 

number of states chose to expand the 

CAIR ozone-season NOX trading 

program applicability in this way. The 

transition from CAIR to the Transport 

Rule is discussed in section IX.A.2 and 

SIPs are discussed in section X of this 

preamble. 

Structure of the remedy. The CAIR 

FIPs (and CAIR model trading rules 

adopted by a number of states in their 

CAIR SIPs) implemented reductions 

through SO2, annual NOX, and ozoneseason NOX interstate emission trading 

programs covering primarily large 

EGUs. The owners and operators of a 

covered source could buy allowances 


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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 the aggregate emissions 

from covered units within any covered 

state. 

The Transport Rule FIPs will also 

achieve the required reductions through 

SO2, annual NOX, and ozone-season 

NOX interstate trading programs. 

However, in contrast to CAIR and for 

the reasons discussed in section VII of 

this preamble, the Transport Rule FIPs 

include assurance provisions 

specifically designed to ensure that no 

state’s emissions will exceed that state’s 

emission budget plus the variability 

limit, i.e., the state’s assurance level. 

Another difference in the remedy 

structure is in the design of the SO2

trading programs. In CAIR all of the 

states required to reduce SO2 emissions 

were grouped together in one SO2

trading program with no restriction on 

the use of SO2 allowances from any state 

in the program by any source in the 

program. In contrast, and for the reasons 

discussed in section VI of this preamble, 

the Transport Rule divides states 

required to reduce SO2 emissions into 

two groups with emission reduction 

requirements of different stringency 

starting in 2014 (SO2 Group 1, whose 

reduction requirements become more 

stringent starting in 2014, and SO2

Group 2, whose reduction requirements 

in 2014 do not change). A covered 

source may only use for compliance— 

with the requirements to hold 

allowances covering emissions and, if 

applicable, to surrender allowances 

under the assurance provisions—an SO2

allowance issued for the SO2 Group in 

which the source’s state is included. In 

other words, an SO2 Group 1 source 

may only use a SO2 Group 1 allowance 

for compliance, and likewise an SO2

Group 2 source may only use a SO2

Group 2 allowance for compliance. 

Provisions for early reductions. CAIR 

included provisions for covered sources 

to make early reductions prior to the 

start of CAIR’s SO2 and NOX trading 

programs, bank emission allowances, 

and carry banked allowances into its 

trading programs. In contrast, the 

Transport Rule does not include 

provisions for covered sources to carry 

over any allowances (i.e., Title IV SO2

allowances or CAIR annual or ozoneseason 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 better meet the needs of the 

state. Both the Transport Rule and CAIR 

allow full or abbreviated SIPs that 

involve one or more applicable FIP 

trading programs. However, there are a 

few differences. 

In particular, under the Transport 

Rule, states may submit SIP revisions 

under which the state determines 

allocations for the applicable trading 

program using either full or abbreviated 

SIP revisions. States could submit 

similar revisions under CAIR. Under the 

Transport Rule, the state may use the 

same allocation methodology as that 

currently used in the Transport Rule FIP 

trading program or some other 

allocation methodology. However, the 

Transport Rule specifies certain 

requirements that must be met 

concerning, for example, the timing of 

such allocation determinations, and 

expressly allows allowance auctions to 

be used. CAIR did not include similar 

provisions. Further, the SIP submission 

deadlines, allocation submission, and 

allocation recordation dates are different 

between the Transport Rule and CAIR. 

The Transport Rule SIP submission 

deadlines and allocation recordation 

dates are discussed in section X of this 

preamble. 

In addition, both the Transport Rule 

and CAIR include provisions that allow 

states to submit SIP revisions under 

which the state expands the general 

applicability provisions of the ozoneseason NOX trading programs to cover 

certain units subject 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. 

Finally, neither full nor abbreviated 

SIPs can replace FIP provisions that 

apply to units in Indian country within 

the borders of a state. For example, the 

FIPs include, for states within whose 

borders Indian country is located, an 

Indian country new unit set-aside. For 

states not having Indian country within 

their borders, abbreviated SIPs are 

limited to replacing the allowance 

allocation provisions of the FIPs for the 

state involved and may replace some or 

all of those provisions. However, for 

states having Indian country within 

their borders, abbreviated SIPs cannot 

replace the FIP provisions for the Indian 

country new unit set-aside. Similarly, 

for states not having Indian country, full 

SIPs can replace an entire FIP, but, in 

doing so, can only change the allowance 

allocation provisions. For states having 

Indian country, full SIPs can replace the 

FIPs except for the Indian country new 

unit set-aside provisions, which will 

remain under the applicable FIPs, and, 

like the abbreviated SIPs, can only 

change the allowance allocation 

provisions that are replaced. 

Details of the Transport Rule 

provisions for abbreviated and full SIP 

revisions, including deadlines for 

submission to EPA, are discussed in 

section X of this preamble. 

2. Transition From the Clean Air 

Interstate Rule to the Transport Rule 

The Transport Rule replaces CAIR 

and its associated trading programs. 

This section elaborates on areas of 

transition from CAIR to the Transport 

Rule. 

a. Sunsetting of CAIR, CAIR SIPs, and 

CAIR FIPs 

The proposal explained that, for 

control periods in 2012 and thereafter, 

CAIR, CAIR SIPs, and CAIR FIPs would 

be replaced entirely by the Transport 

Rule provisions. The proposal outlined 

implementation of the sunsetting of 

CAIR and CAIR FIPs, through revisions 

to CAIR, §§ 51.123 and 51.124, and the 

CAIR FIPs, §§ 52.35 and 52.36. For the 

control period in these years, the CAIR 

trading programs would not continue, 

and the Administrator would not carry 

out any of the functions established for 

the Administrator in the CAIR model 

trading rule, the CAIR FIPs, or any state 

trading programs approved under CAIR. 

Offset and automatic penalty provisions 

under CAIR would not apply to excess 

emissions for 2011 control periods. 


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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 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 post2011 CAIR annual NOX and ozoneseason allowances from the Allowance 

Tracking System. 

The CAIR SO2 trading program, of 

course, uses Acid Rain allowances, 

which will remain in the Allowance 

Tracking System because they were 

created by CAA Title IV and continue to 

be usable in the Acid Rain Program. 

The final rule also adopts the 

discussion in the proposed rule 

concerning state-specific Part 52 

provisions concerning CAIR (75 FR 

45337–38). With regard to Part 52 

provisions reflecting EPA’s adoption of 

ongoing CAIR FIPs for some individual 

states, the final rule revises the CAIR 

FIP provisions to make them 

inapplicable to control periods in 2012 

and thereafter and to require the 

Administrator to remove from the 

Allowance Tracking System, CAIR 

allowances for these control periods. 

The final, state-specific CAIR FIP 

provisions in Part 52 essentially echo 

the language in the final, general CAIR 

provisions in Part 52 discussed above. 

In making the CAIR FIP provisions 

inapplicable to control periods in 2012 

and thereafter, the final, state-specific 

provisions sunset the applicable CAIR 

FIP trading programs whether or not the 

CAIR FIPs were revised by approved, 

abbreviated CAIR SIPs. (Under CAIR, 

abbreviated CAIR SIPs were adopted by 

certain states so that states, rather than 

EPA, made NOX allowance allocations.) 

Consequently, states with approved, 

abbreviated CAIR SIPs will not need to 

revise their abbreviated CAIR SIPs in 

order to sunset the CAIR trading 

programs to which these abbreviated 

SIPs applied. Thus, although such 

abbreviated SIPs may remain in the state 

SIPs, they will have no force and effect, 

once the CAIR FIPs sunset. 

With regard to Part 52 provisions 

reflecting EPA’s approval of full CAIR 

SIPs submitted to EPA by many 

individual states, the Court’s North 

Carolina decision essentially overrides 

these Agency approvals of individual 

CAIR SIPs. (Under CAIR, full CAIR SIPs 

were adopted by certain states to replace 

CAIR FIPs and continue participation 

through the CAIR SIPs in the CAIR 

trading programs.) The Court found 

CAIR to be illegal and only allowed it 

to remain in effect temporarily. For this 

reason, the CAIR SIPs though approved, 

can have no force and effect once CAIR 

is replaced by this rule. For this reason, 

although the proposed rule indicated 

that states would need to submit SIP 

revisions to, among other things, make 

the CAIR SIPs inapplicable to control 

periods after 2011, the final rule does 

not require states to take any actions to 

revise their full or abbreviated CAIR 

SIPs. For states covered by CAIR or 

CAIR FIPs that are not subject to the 

Transport Rule and have relied on CAIR 

reductions to satisfy other SIP 

requirements, EPA will discuss with 

states alternative ways to satisfy 

requirements for those SIP 

requirements, e.g., through intrastate 

cap and trade programs that 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 ozoneseason NOX emissions from EGUs and 

large non-EGUs under NOX SIP Call 

requirements. The program started in 

2003 and ended in 2008. Under CAIR, 

a state subject to the NOX SIP Call was 

allowed to expand the applicability of 

the CAIR ozone-season NOX trading 

program in the state in order to include 

all units subject to the NOX Budget 

Trading Program under the NOX SIP 

Call and thereby to continue to meet the 

state’s NOX SIP Call requirements. 

Fourteen states chose to expand the 

CAIR ozone-season NOX applicability in 

this way, while six states chose not to 

expand the applicability and instead to 

meet their NOX SIP Call obligations in 

other ways. EPA proposed to not allow 

this expansion in applicability for the 

Transport Rule, primarily because these 

sources as a group did not actually 

reduce emissions for the NOX Budget 

Trading Program or CAIR. EPA took 

comment on the proposed approach. 

Several commenters generally 

advocated allowing, at state discretion, 

all NOX Budget Trading Program units 

to be regulated under the Transport Rule 

ozone-season NOX trading program. 

Some also questioned how states would 

otherwise satisfy NOX SIP Call 

requirements for these units. Some 

commenters argued that some units did 

in fact make emission reductions in the 

NOX Budget Trading Program, but did 

not provide information on specific 

units. 

The final rule provides states an 

option to expand the general 

applicability provisions of the Transport 

Rule ozone-season NOX trading program 

to cover small EGUs, but not other units 

in the NOX SIP Call. Specifically, 

consistent with the comments, EPA 

determined that it is appropriate to 

allow states to expand the applicability 

of the Transport Rule ozone-season NOX

trading program to include units serving 

a generator with a nameplate capacity 

equal to or greater than 15 MWe 

producing electricity for sale. This will 

allow states with NOX SIP Call 

obligations to meet those requirements 

with respect to these small EGUs. These 

units can be brought into the program 

through abbreviated or full Transport 

Rule SIPs. However, if a state chooses to 

expand the general applicability 

provisions, the state Transport Rule 

ozone-season NOX budget cannot be 

increased. EPA believes that the level of 


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117Although 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. 

118The Title IV allowance bank is expected to be 

about 14 million tons at the beginning of 2012. 

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 applicability 

provisions for the ozone-season NOX

trading program to include such units. 

As explained in the proposed rule (75 

FR 43340), while some of these units 

may have installed controls around the 

start of the NOX Budget Trading 

Program, EPA analysis shows that, as a 

group, these units did not collectively 

reduce emissions, their current emission 

rates are nearly identical to their 

emission rates before the start of the 

NOX Budget Trading Program, and their 

allocations are about twice their 

emissions, with the result that the 

excess allocations were sold to covered 

EGUs.117 Moreover, EPA believes that 

there are little or no emission reductions 

available by non-EGUs at the cost 

thresholds used in the final rule and so 

no basis for developing non-EGUs state 

budgets reflecting the elimination of 

significant contribution to 

nonattainment and interference with 

maintenance. For these reasons, the 

final rule allows states to expand the 

ozone-season NOX trading program to 

cover small EGUs that were in the NOX

Budget Trading Program, but not to 

cover large non-EGUs that were in that 

program. As explained in the proposed 

rule, if a state were to do so, emissions 

from these units could jeopardize 

elimination of the state’s significant 

contribution to nonattainment or 

interference with maintenance. See 75 

FR 45340. For states that relied on large 

non-EGUs for emission reductions 

required by the NOX SIP Call, EPA will 

assist in identifying ways to ensure 

continued, future compliance with the 

NOX SIP Call requirements. 

c. Early Reduction Provisions 

Substantial emission reductions have 

occurred as a result of previous 

emission trading programs, under both 

Title IV and CAIR. This has lead to 

substantial ‘‘banks’’ of allowances (i.e., 

holdings of unused allowances allocated 

for years before the programs sunset) in 

each of the CAIR programs. In the 

proposal, EPA requested comment on 

whether to allow banked CAIR 

allowances to be used in the Transport 

Rule trading programs. EPA recognizes 

the importance of continuity in 

emission trading programs as a general 

principle. However, for the reasons 

explained below, EPA has decided not 

to allow banked CAIR allowances to be 

used in any of the Transport Rule 

trading programs. (1) SO2 Allowance 

Bank 

The bank of Title IV allowances was 

more than 12 million tons at the end of 

2009. This bank is the result of emission 

reductions under the Title IV Acid Rain 

Program. Under the CAIR SO2 trading 

program, EPA allowed banked (as well 

as future year) Title IV allowances to be 

used in the CAIR SO2 trading program— 

in lieu of being used in the Acid Rain 

Program—for compliance with the 

requirement to hold allowances 

covering SO2 emissions. This approach 

encouraged early reductions for the 

CAIR SO2 trading program, but was held 

to be unlawful in North Carolina. 

In the proposed rule, EPA took 

comment on whether sources should be 

allowed to use banked Title IV 

allowances in the Transport Rule SO2

program. EPA proposed to not allow the 

use of Title IV allowances either as the 

basis for allocating Transport Rule SO2

allowances or directly for compliance 

with allowance-holding requirements, 

in part, because EPA was concerned that 

those approaches would be perceived as 

inconsistent with the requirements of 

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

interpreted by the Court in North 

Carolina. See 75 FR 45338–39. 

A number of commenters advocated 

that EPA recognize Title IV allowance 

holdings in the Transport Rule, either 

by allowing full or limited carryover of 

the allowances or by allocating all or a 

portion of the Transport Rule SO2

allowances based on Title IV allowance 

holdings. Other commenters agreed 

with EPA’s assessment that allowing 

Title IV allowance carryover in the 

Transport Rule is inconsistent with 

North Carolina and that any linkage of 

Transport Rule allocations with Title IV 

allowance holdings would carry 

unnecessary, significant legal risk. 

Therefore, for the reasons explained 

above and in the proposal, EPA has 

decided not to permit sources to use 

Title IV allowances for compliance with 

the Transport Rule SO2 trading 

programs. 

In addition, unlike CAIR, in the 

Transport Rule, EPA decided not to base 

allocation of Transport Rule SO2

allowances on the specific distribution 

of existing Title IV allowances. Title IV 

allowances continue, of course, to be 

usable for compliance in the Acid Rain 

Program.118

(2) NOX Allowance Banks 

In the proposed rule, EPA estimated 

that the CAIR ozone-season NOX bank 

would contain over 600,000 allowances 

and the CAIR annual NOX bank would 

contain about 720,000 allowances after 

completion of 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 pre2012 CAIR NOX allowances in the 

Transport Rule NOX trading programs 

and the pros and cons of each (75 FR 

45339): 

• Allow all such banked CAIR 

allowances to be brought into the 

Transport Rule NOX programs, make the 

assurance provisions effective starting 

in 2012, and rely on the assurance 

provisions to ensure that each state 

continues to eliminate all of its 

significant contribution to 

nonattainment and interference with 

maintenance; 

• Allow only a limited amount of 

banked pre-2012 CAIR allowances to be 

brought into the Transport Rule NOX

programs; 

• 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. 


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119This 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. 

• Many commenters advocated 

allowing the carryover of CAIR NOX

allowances to the Transport Rule. 

Reasons given included: preservation of 

early reduction investments; need for 

market continuity; increased flexibility 

during program start up and early years 

of the programs; preservation of the 

credibility of, and certainty under, 

trading approaches; and the lack of a 

prohibition in North Carolina of 

carryover of CAIR NOX allowances. 

Commenters also suggested that 

surrender ratios be used to limit the 

amount, and negative effects, of a 

carryover. 

• Many other commenters were 

against allowing CAIR NOX allowance 

carryover into the Transport Rule. 

Reasons given included: unnecessary, 

significant legal risk; concerns about the 

efficacy of the Transport Rule if state 

budgets are supplemented by a 

carryover; and differences in the nature 

of the programs (the NOX Budget 

Trading Program, which addressed the 

1-hour ozone NAAQS, and the CAIR 

ozone-season NOX trading program, 

which addressed the 1997 8-hour ozone 

NAAQS and was reversed in North 

Carolina) under which the allowances 

were banked, and the Transport Rule 

ozone-season NOX trading program, 

which addresses the 1997 8-hour ozone 

NAAQS. 

For the reasons explained below, after 

evaluating all comments on this issue, 

EPA decided not to allow the use of 

CAIR NOX allowances in the Transport 

Rule NOX trading programs. EPA 

reevaluated the estimated size of the 

potential carryover (allowances that will 

remain unused in the CAIR programs at 

the end of 2011 compliance periods), 

taking into account 2010 emissions. 

EPA estimates that more than 440,000 

CAIR ozone-season NOX allowances 

will remain and that more than 460,000 

CAIR annual NOX allowances will 

remain at the end of the 2011 

compliance periods. EPA considered 

whether to allow these CAIR ozoneseason NOX and CAIR annual NOX

allowances to be used in the Transport 

Rule NOX trading programs. The CAIR 

ozone-season NOX allowances expected 

to remain unused represent nearly 

three-quarters of aggregate state ozoneseason NOX budgets 119 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 NOX budgets. 

In response to public comments, EPA 

considered whether the Transport Rule 

trading programs should allow some 

form of exchange of banked CAIR 

annual NOX and ozone-season 

allowances for new Transport Rule NOX

allowances within each state’s annual 

NOX and/or ozone-season budgets, 

respectively. However, EPA believes 

that this type of approach carries 

substantial legal and technical 

problems. First, the state-by-state 

distribution of CAIR NOX allowances 

resulted from the methodology applied 

by EPA in CAIR of using fuel factors to 

set the total amounts of allowance 

allocations in each state (i.e., the state 

NOX budgets). The CAIR NOX allowance 

banks therefore are—at least in part— 

the result of this methodology, which 

was reversed in North Carolina. See 

North Carolina, 531 F.3d at 918–22. 

Thus, EPA did not use fuel factors in 

developing the Transport Rule state 

budgets. However, EPA is concerned 

that the distribution of some or all 

Transport Rule NOX allowances through 

exchanges of banked CAIR NOX

allowances for Transport Rule NOX

allowances would blur the bright line 

between the methodology used for 

setting budgets in the Transport Rule 

and the methodology used for setting 

budgets in CAIR that was rejected by the 

Court. At least to some extent, the 

parties that were advantaged under 

EPA’s budget-setting methodology in 

CAIR would continue to have an 

advantage under the Transport Rule by 

receiving more Transport Rule NOX

allowances. EPA therefore believes that 

allowing exchange of banked CAIR NOX

allowances for Transport Rule NOX

allowances carries significant legal risk. 

Second, establishing a procedure for 

exchanging banked CAIR NOX

allowances for Transport Rule NOX

allowances within each state’s budget 

would mean that Transport Rule NOX

allowances could not be allocated until 

after completion of the process for 

determining compliance with 

allowance-holding requirements for 

2011 in the CAIR NOX trading programs. 

This process cannot begin until after the 

allowance transfer deadline for the 2011 

control periods (i.e., March 1, 2012 for 

the CAIR annual NOX program and 

November 1, 2011 for the CAIR ozoneseason NOX program) and will not likely 

be completed until mid-2012. At that 

time, EPA could begin the procedure of 

implementing, state-by-state, the 

exchanges of the remaining CAIR NOX

allowance banks held by parties (owners 

and operators, brokers, and other 

entities) for some or all of the 

allowances in the state NOX budgets for 

2012. The portion of each state budget 

that would be used up by such 

exchanges would likely vary from state 

to state. The resulting delay, and 

uncertainty about the unit-by-unit 

amounts, of Transport Rule NOX

allowance allocations for 2012 would 

undermine Transport Rule allowance 

market liquidity, significantly disrupt 

planning by owners and operators for 

compliance with allowance-holding 

requirements for the 2012 control 

periods, and likely impose increased 

compliance costs under the Transport 

Rule NOX trading programs or impact 

the ability to comply with the 2012 

limits. 

In light of the specific circumstances 

in this case and the above-described 

legal and technical problems that would 

result from a carryover of CAIR NOX

allowances into the Transport Rule 

trading programs, the final rule does not 

allow any such carryover. EPA agrees 

that, as a general principle, it is 

desirable to provide continuity between 

sequential regulatory programs 

involving emission trading and thereby 

to ensure that allowances in the past 

program continue to have some value in 

the new program. Balancing the general 

desirability of providing program 

continuity against the potential negative 

consequences of a carryover in, and the 

specific circumstances of, this case, EPA 

concludes that the carryover of banked 

CAIR NOX allowances into the 

Transport Rule trading programs should 

not be allowed. EPA notes that, in this 

case, it signaled the possibility that it 

would take such an approach in order 

to provide markets with full information 

and avoid unnecessary disruptions. 

After CAIR was remanded by the Court 

in North Carolina, 550 F.3d 1176, in 

December 2008, EPA was concerned 

about the future status of CAIR NOX

allowances and consequently advised 

the public—through a statement posted 

on the EPA Web site in March, 2009— 

that ‘‘EPA’s continued recording of 

CAIR NOX allowances does not 

guarantee or imply that any allowances 

will continue to be usable for 


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120http://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’’). 

compliance after a replacement rule is 

finalized or that they will continue to 

have value in the future.’’ 120 EPA 

believes its decision to disallow 

carryover of banked allowances here 

reflects the specific factors in this case 

and should not be treated as setting any 

precedent for the treatment, in any 

future trading programs, of any past 

trading program’s banked allowances. 

However, EPA notes that, under the 

CAIR ozone-season NOX trading 

program, where unused allowances 

were carried forward from the preceding 

NOX Budget Trading Program, and 

under the CAIR annual NOX trading 

program, where extra allowances (from 

the compliance supplement pool) were 

allocated for early reductions made 

during the NOX Budget Trading 

Program, the vast majority of allowance 

allocation decisions were made by the 

states administering these programs. 

Moreover, a number of states did not 

allocate CAIR allowances to their 

sources using fuel adjustment factors, 

whose use the Court rejected in North 

Carolina in connection with EPA’s 

setting of state NOX emission budgets. 

In light of the general desirability of 

providing continuity between state 

programs, states may want to address 

the CAIR NOX banks when developing, 

in SIP revisions, the Transport Rule 

allowance allocations for control 

periods after 2012. EPA encourages each 

state that wants to allocate Transport 

Rule NOX allowances through SIP 

revisions to consider using information 

on the CAIR NOX allowance banks that 

will remain after 2011. Any such 

allowance allocations, of course, must 

be within the respective state’s NOX

trading budget, and must be submitted 

to EPA within the applicable 

submission deadlines, established in the 

final rule for the control periods for 

which the allocations are made. The 

Agency intends to contact states 

concerning the desirability of holding a 

workshop to discuss issues related to 

state allowance allocations. 

B. Interactions With NOX SIP Call 

The proposed rule explained that 

states covered by both the NOX SIP Call 

and the Transport Rule would be 

required to comply with the 

requirements of both rules and that the 

Transport Rule would not preempt or 

replace the requirements of the NOX SIP 

Call. Most, but not all, NOX SIP Call 

states would be included in the 

Transport Rule. The proposed rule 

further explained that the Transport 

Rule ozone-season NOX trading program 

would achieve the emission reductions 

required by the NOX SIP Call from EGUs 

serving generators with a nameplate 

capacity greater than 25 MW and 

producing electricity for sale in most 

NOX SIP Call states. (This would not be 

the case, of course, for those NOX SIP 

Call states not covered by the Transport 

Rule.) 

The NOX SIP Call states used the NOX

Budget Trading Program to comply with 

the NOX SIP Call requirements for EGUs 

serving a generator with a nameplate 

capacity greater than 25 MW and large 

non-EGUs with a maximum rated heat 

input capacity greater than 250 mmBtu/ 

hour. (In some states, EGUs serving a 

generator with a nameplate capacity of 

25 MW or less were also included in the 

NOX Budget Trading Program as a 

carryover from the Ozone Transport 

Commission NOX Budget Trading 

Program.) EPA stopped administering 

the NOX Budget Trading Program under 

the NOX SIP Call after the completion of 

compliance activities related to the 2008 

ozone-season control period, and states 

used other mechanisms to comply with 

the NOX SIP Call requirements. 

The proposal further explained that, if 

EPA promulgated a final rule that did 

not allow the expansion of the 

Transport Rule to NOX Budget Trading 

Program units, any state that allowed 

these units to participate in the CAIR 

ozone-season NOX trading program 

would need to submit a SIP revision to 

address the state’s NOX SIP Call 

requirement for the reductions. The 

proposal also explained that states in 

the CAIR ozone-season NOX trading 

program or the NOX Budget Trading 

Program that would not be in the 

Transport Rule ozone-season NOX

trading program would need to submit 

SIP revisions addressing the NOX SIP 

Call requirements for any emission 

reductions (by EGUs and 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 

with respect to small EGUs brought into 

the Transport Rule trading program, but 

not with regard to large non-EGUs. 

With the issuance of the final 

Transport Rule, NOX SIP Call 

requirements remain in place. See 40 

CFR 51.121. EPA is not changing any of 

the NOX SIP Call requirements. The 

NOX SIP Call generally requires that 

states choosing to rely on large EGUs 

and large non-EGUs for meeting NOX

SIP Call emission reduction 

requirements must establish a NOX mass 

emissions cap on each source and 

require Part 75, subpart H monitoring. 

As an alternative to source-by-source 

NOX mass emissions caps, a state may 

impose NOX emission rate limits on 

each source and use maximum 

operating capacity for estimating NOX

mass emissions or may rely on other 

requirements that the state demonstrates 

to be equivalent to either the NOX mass 

emissions caps or the NOX emission rate 

limits that assume maximum capacity. 

Collectively, the caps or their 

alternatives cannot exceed the portion 

of the state budget for those sources. See 

40 CFR 51.121(f)(2) and (i)(4). EPA will 

work with states to ensure that NOX SIP 

Call obligations continue to be met (e.g., 

through intrastate cap and trade 

programs that require the level of 

reductions on which the state has 

recently relied). 

C. Interactions With Title IV Acid Rain 

Program 

The final rule does not affect any Acid 

Rain Program requirements. Acid Rain 

Program requirements are established 

independently in Title IV of the CAA 

and are not replaced by the 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 


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units in the states that border the 

Transport Rule states may increase 

because of potential load-shifting from 

units in Transport Rule states and 

because of a potential decrease in the 

Title IV allowance price. There is a 

discussion of possible emission 

increases in non-covered states in 

section VI.C of this preamble. 

D. Other State Implementation Plan 

Requirements 

In this final action, EPA has not 

conducted any technical analysis to 

determine whether compliance with the 

Transport Rule would satisfy RACT 

requirements for EGUs in any 

nonattainment areas, or Regional Haze 

BART-related requirements. For that 

reason, EPA is neither making 

determinations nor establishing any 

presumptions that compliance with the 

Transport Rule satisfies any RACT or 

BART-related requirements for EGUs. 

Based on analyses that states conduct on 

a case-by-case basis, states may be able 

to conclude that compliance with the 

Transport Rule for certain EGUs fulfills 

nonattainment area RACT requirements. 

EPA intends to undertake a separate 

analysis to determine if compliance 

with the Transport Rule would provide 

sufficient reductions to satisfy BART 

requirements for EGUs in accordance 

with Regional Haze Rule requirements 

for alternative BART compliance 

options as soon as practicable following 

promulgation of the Transport Rule. 

X. Transport Rule State 

Implementation Plans 

EPA proposed (75 FR 45342) FIPs 

setting state-specific emission reduction 

requirements for each upwind state 

covered by the proposed Transport Rule 

and with respect to one or more of three 

air quality standards—the 1997 annual 

PM2.5 NAAQS, the 2006 24-hour PM2.5

NAAQS, and the 1997 ozone NAAQS. 

In CAIR, EPA allowed the states to 

replace the CAIR FIP with SIPs and 

provided substantial flexibility. In the 

proposed Transport Rule, EPA proposed 

to allow similar flexibility to states for 

addressing the CAA section 

110(a)(2)(D)(i)(I) transport issues 

through a SIP. EPA proposed to allow a 

state to submit a SIP for the ozone 

requirements only, for the PM2.5

requirements only, or for both the ozone 

and the PM2.5 requirements with the 

specific quantity of emission reductions 

necessary for a state’s SIP determined 

based on the state emission budgets 

provided in the final Transport Rule. 

EPA received comments suggesting 

that if the proposal’s remedy were 

finalized, EPA should allow states to 

replace the FIP allowance allocation 

provisions in the proposed Transport 

Rule trading programs by statedeveloped allocation provisions. 

Commenters referenced the two 

alternatives provided to states in the 

CAIR trading programs where: (1) EPA 

adopted a rule and model trading 

regulations under which states that 

adopted, as state SIP trading programs, 

the model regulations (with only certain 

limited changes allowed, e.g., in the 

allocation provisions) could participate 

in the EPA-administered CAIR trading 

programs; and (2) EPA adopted a rule 

allowing states to adopt in SIPs 

provisions replacing only certain 

provisions in the CAIR FIPs (e.g., the 

allocation provisions) and to remain in 

the CAIR trading programs under the 

CAIR FIPs. Under both approaches, the 

covered units in the state participated in 

the CAIR trading programs, albeit with 

state-, rather than EPA-, determined 

allocations. Comments on the Transport 

Rule proposal supported these two 

types of approaches for allowing states 

to replace EPA allocations under the 

proposed Transport Rule trading 

programs by state allocations. EPA 

requested additional comment on this 

topic in the NODA published January 7, 

2011 (76 FR 1109). 

Two approaches with associated 

deadlines were explained in the NODA. 

Under the first approach, EPA would 

adopt new provisions, as part of the 

proposed Transport Rule FIP that would 

allow a state to submit a SIP (referred as 

an abbreviated SIP) that would modify 

specified provisions of the proposed 

Transport Rule FIP trading programs. 

Specifically, the abbreviated SIP would 

substitute state allocation provisions for 

control periods in years after 2012, 

applicable to one or more of the 

proposed Transport Rule FIP trading 

programs that apply to the state. The 

NODA explained which specific 

provisions in the FIP could be replaced. 

If the state allocation provisions met 

certain requirements and the 

abbreviated SIP did not change any 

other provisions in the respective 

proposed Transport Rule FIP trading 

program, then EPA would approve the 

abbreviated SIP. In the substitute state 

allocation provisions, the state could 

allocate allowances to Transport Rule 

units (whether existing or new units) or 

other entities (such as renewable energy 

facilities) or could auction some or all 

of the allowances. The NODA went on 

to describe the requirements for EPA 

approval of an abbreviated SIP (76 FR 

1119) including that the total amount of 

allowances allocated and auctioned 

each year could not exceed the 

applicable budget; allocations and 

auction results would need to be 

reported to EPA by the permitting 

authority (usually the state) by 

particular dates prior to the applicable 

control period depending on whether 

allowances were going to existing or 

new sources; the reported allocations 

and auction results could not be 

changed; and no other provisions of the 

FIP would be changed. 

Under the second approach, EPA 

would adopt a new rule that would 

provide that, if a state submitted a SIP 

(referred to as a full SIP) that adopted 

trading program regulations meeting 

certain requirements for control periods 

in years after 2012, then EPA would 

approve the full SIP as correcting the 

deficiency under CAA section 

110(a)(2)(D)(i)(I) in the state’s SIP that 

was the basis for issuance of the 

comparable proposed Transport Rule 

FIP. In the state allocation provisions, 

the state could allocate allowances to 

Transport Rule units (whether existing 

or new units, except for opt-in units) or 

other entities (such as renewable energy 

facilities) or could auction allowances. 

Upon EPA approval of a state’s full SIP, 

the state’s SIP-based trading program 

would be integrated with the 

comparable FIP-based Transport Rule 

trading program (whether or not 

modified by an abbreviated SIP) 

covering other states. Moreover, covered 

sources in the state could participate in 

the integrated trading program, and the 

allowances issued under the SIP-based 

state trading program would be 

interchangeable with the allowances 

issued in the comparable FIP-based 

Transport Rule trading program. 

The NODA went on to describe the 

limited changes that states could make 

under the full SIP option. Only 

allocation provisions could be modified 

with the same requirements as for 

abbreviated SIPs, including, among 

other things, that the total amount of 

allowances allocated each year could 

not exceed the applicable budget and 

that allocations would need to be 

reported to EPA by the permitting 

authority (usually the state) by 

particular dates prior to the applicable 

control period depending on whether 

allowances were going to existing or 

new sources. 

The NODA also discussed the option 

for states to submit SIPs using emission 

reduction approaches other than the 

proposed Transport Rule trading 

programs to correct the deficiency under 

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

state’s SIP. EPA would review on a caseby-case basis SIPs using such alternative 

approaches (76 FR 1120). 

Suggested deadlines for abbreviated 

and full SIPs were given in tables in the 


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121EPA is not finalizing opt-in provisions, so the 

reference to federal-only opt-in allocations in the 

NODA has been removed. 

NODA (76 FR 1120). These deadlines 

generally required states to submit SIPs 

about 2 years ahead of a particular 

control period for which state 

allocations would apply in order to give 

EPA time to review and approve the SIP 

and record allowances. 

Most commenters on the NODA 

supported state allocation options, 

within the preferred FIP remedy, that 

would replace FIP allocations with SIPbased state allocations. 

In the final rule, EPA adopts, with 

some revisions, both of the approaches 

described in the January 7, 2011 NODA. 

Under the first approach, a state may 

submit an abbreviated SIP that modifies 

a final Transport Rule FIP trading 

program in only a limited way (i.e., by 

replacing the allowance allocation 

provisions in §§ 97.411(a) and (b)(1) and 

97.412(a) for the annual NOX trading 

program, §§ 97.511(a) and (b)(1) and 

97.512(a) for the ozone-season NOX

trading program, §§ 97.611(a) and (b)(1) 

and 97.612(a) for the SO2 Group 1 

trading program, and §§ 97.711(a) and 

(b)(1) and 97.712(a) for the SO2 Group 

2 trading program). In the state’s 

replacement provisions, the state may 

allocate allowances to Transport Rule 

units (whether existing or new units) 121

or other entities (such as renewable 

energy facilities) or may auction 

allowances. Additionally, state SIPs can 

address one or all of the pollutants 

addressed by the FIPs. For PM2.5, EPA 

is finalizing the flexibility for a state SIP 

to address either SO2 or NOX, or both. 

Further, if a state is required to make 

ozone-season and annual NOX

reductions, the SIP could address either 

ozone-season or annual NOX emissions, 

or both. In other words, states can 

replace provisions in all FIPs that apply 

or some subset of the FIPs that apply to 

a particular state, and leave in place the 

FIPs for the requirements not addressed 

by a SIP. 

Further, EPA will approve the 

abbreviated SIP only if the state 

replacement for the Transport Rule FIP 

allocation provisions meets certain 

requirements and the abbreviated SIP 

does not change any other provisions in 

the Transport Rule FIP trading program. 

For EPA approval, the state allocation 

and, where applicable, auction 

provisions (and any accompanying 

definitions of terms applying only to 

terms as used in these provisions) must 

meet the following requirements. First, 

the provisions must provide that, for 

each year for which the state allocation 

and, where applicable, auction 

provisions will apply, the total amount 

of control period (annual or ozoneseason) allowances allocated and, where 

applicable, auctioned in accordance 

with these provisions cannot exceed the 

applicable state budget (less any 

applicable Indian country new unit setaside, which will continue to be 

administered by EPA) for that year 

under the relevant Transport Rule FIP 

trading program. 

Second, to the extent the state 

provisions provide for allocations for, or 

auctions open to, existing units, the 

provisions must require that the state or 

the permitting authority under title V of 

the CAA for the state submit to the 

Administrator final allocations and, if 

any auction is to be held, final auction 

results in accordance with a schedule of 

deadlines discussed below. To the 

extent the provisions provide for 

allocations for or auctions open to new 

units or any other entities, the 

provisions must require that the 

permitting authority submit to the 

Administrator final allocations and, if 

applicable, auction results by July 1 of 

the year of the control period for which 

the allowances will be distributed. The 

allocation and auction results must be 

final and cannot be subject to 

modification (e.g., through an allowance 

surrender adjusting the allocation or 

auction results). 

As noted above, the state’s submission 

to the Administrator of allocations or 

auction results with regard to existing 

units must meet a specified schedule of 

deadlines. These submission deadlines 

reflect, and are necessarily coordinated 

with, the deadlines for recordation by 

the Administrator of allowance 

allocations and any auction results 

under the Transport Rule trading 

programs. The recordation deadlines, 

which are discussed in detail in section 

XI of this preamble, provide that the 

Administrator must record 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 state 

or permitting authority must make these 

submissions to the Administrator by: 

June 1, 2013 for the applicable control 

periods in 2014 and 2015; June 1, 2014 

for the applicable control periods in 

2016 and 2017; June 1, 2015 for the 

applicable control periods in 2018 and 

2019; and June 1, 2016 and June 1 of 

each year thereafter for the applicable 

control period in the fourth year after 

the year of the applicable submission 

deadline. 

Under the second approach, a state 

may submit a full SIP adopting a 

Transport Rule trading program that 

differs from the comparable Transport 

Rule FIP trading program only with 

regard to limited provisions of the FIP 

trading program. First, the full SIP may 

include new allocation or auction 

provisions instead of the Transport Rule 

FIP allowance allocation provisions 

other than those concerning the Indian 

country new unit set-aside. In the state 

allocation or auction provisions, the 

state may allocate allowances to 

Transport Rule units (whether existing 

or new units) or other entities (such as 

renewable energy facilities) or may 

auction allowances. EPA will approve 

the full SIP only if the state allocation 

or auction provisions (and any 

accompanying definitions of terms 

applying only to terms as used in these 

provisions) meet certain requirements. 

Second, the full SIP may substitute the 

name of the state for the term ‘‘State’’ as 

used in the FIP trading program 

provisions, provided that EPA 

determines that the substitutions are not 

substantive changes. Third, as discussed 

in more detail below, all references to 

units in Indian country, as used in the 

FIP trading program provisions, must be 

removed, and the full SIP cannot 

impose any requirements on units in 

Indian country within the borders of the 

state and may not include the Indian 

country set-aside provisions. Other than 

these allowed changes, all other 

provisions in the Transport Rule trading 

program in the full SIP must be the 

same as those in the Transport Rule FIP 

trading program with regard to nonIndian country units. For EPA approval, 

the state allocation provisions must 

meet the same requirements, as 

discussed above, that state allocation or 

auction provisions in an abbreviated SIP 

must meet. 

A Transport Rule trading program 

adopted by a state in a full SIP, and 

approved by EPA, under the second 

approach will be fully integrated with 

the comparable Transport Rule FIP 

trading program (i.e., the ‘‘TR NOX

Annual Trading Program’’, ‘‘TR NOX

Ozone Season Trading Program’’, ‘‘TR 

SO2 Group 1 Trading Program’’, or ‘‘TR 

SO2 Group 2 Trading Program’’ 


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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 NOX

Annual allowance’’, ‘‘TR NOX Ozone 

Season allowance’’, ‘‘TR SO2 Group 1 

allowance’’, and ‘‘TR SO2 Group 2 

allowance’’ in the full SIPs approved by 

EPA and the TR FIP trading programs 

(whether or not the programs were 

modified by abbreviated SIPs). ‘‘TR NOX

Annual allowance’’ will be defined in 

the state and Transport Rule FIP trading 

programs as including allowances 

issued under any of the following 

trading programs: The comparable EPAapproved state Transport Rule trading 

programs; the comparable Transport 

Rule FIP trading programs with EPAapproved state allocation and auction 

provisions; and the Transport Rule FIP 

trading programs with EPA allocation 

provisions. Similarly, the definitions in 

the state and Transport Rule FIP trading 

programs of ‘‘TR NOX Ozone Season 

allowance’’, ‘‘TR SO2 Group 1 

allowance’’, and ‘‘TR SO2 Group 2 

allowance’’ respectively will include 

allowances issued under all three types 

of trading programs. As a result, 

allowances issued in one approved state 

Transport Rule trading program will be 

interchangeable with allowances issued 

in the comparable Transport Rule FIP 

trading program (whether or not 

modified by an abbreviated SIP), and all 

these allowances will be available for 

use for compliance with the allowanceholding 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 NOX Annual Trading 

Program,’’ ‘‘TR NOX Ozone Season 

Trading Program’’, ‘‘TR SO2 Group 1 

Trading Program’’, and ‘‘TR SO2 Group 

2 Trading Program’’. Each of these 

definitions in the state Transport Rule 

and Transport Rule FIP trading 

programs will expressly encompass the 

comparable Transport Rule FIP trading 

programs (whether or not modified by 

an abbreviated SIP) and the comparable 

EPA-approved state full SIP trading 

program. 

The final rule also sets deadlines for 

the submission of complete abbreviated 

and full SIPs. These deadlines are based 

on the first year for which the state 

wants to allocate or auction allowances, 

reflect the above-discussed deadlines for 

the Administrator’s recordation of 

allocations and auction results, and 

build in a 6-month period for EPA 

review, provision of notice and 

opportunity for public comment, and 

approval of the SIP revisions. This 6- 

month period is built into the final 

rule’s SIP submission deadlines because 

that is the period EPA found was 

needed for reviewing, providing notice 

and comment for, and approving state 

trading program provisions in 

abbreviated and full SIPs under CAIR. 

As a result, the final rule requires that 

complete abbreviated and full SIPs must 

be submitted to the Administrator by: 

December 1, 2012 in order to govern 

allowance allocation and auction for 

control periods in 2014 and 2015; 

December 1, 2013 in order to govern 

control periods in 2016 and 2017; 

December 1, 2014 in order to govern 

allowance allocation and auction for 

control periods in 2018 and 2019; and 

December 1, 2015 and by December 1 of 

any year thereafter in order to govern 

allowance allocation and auction for 

control periods in the fifth year after 

such submission deadline. 

EPA notes that, in cases where a state 

that has Indian country within its 

borders submits, and EPA approves, a 

full SIP, the comparable FIP will not be 

entirely replaced. In such cases, the FIP 

will continue to be in place with regard 

to the Transport Rule trading program 

provisions that concern units in Indian 

country, and the full SIP will 

encompass all other provisions of the 

trading program. Specifically, to the 

extent Transport Rule trading program 

provisions reference and apply to Indian 

country units (including, for example, 

references in the applicability 

provisions and the Indian country new 

unit set-aside provisions), those 

provisions, as they apply to Indian 

country units, will remain in the FIP. 

The full SIP will include those 

provisions only as they apply to nonIndian country units. 

As a practical matter, this means that 

the Indian country new unit set-aside 

provisions, which apply exclusively to 

Indian country new units, will remain 

entirely in the FIP. Further, other 

trading program provisions that 

reference both non-Indian country units 

and Indian country units (such as the 

applicability provisions) will remain in 

the FIP to the extent of their application 

to Indian country units and will be 

included in the full SIP to the extent of 

their application to non-Indian country 

units. 

However, EPA notes that the 

assurance provisions in each Transport 

Rule trading program require 

calculations using the entire state 

budget, including any portion of the 

budget that may be allocated to Indian 

country new units. Further, EPA notes 

that currently no new units are planned 

or anticipated to be located in Indian 

country. Under these circumstances, 

EPA will handle the assurance 

provisions as follows. The full SIP for a 

state having Indian country will initially 

include the assurance provisions, as set 

forth in the FIP, except with removal of 

any references to sources and units in 

Indian country. The FIP will initially 

not include the assurance provisions, 

which will be fully effective and 

enforceable under the full SIP. In the 

event that any new unit is located in 

Indian country in the state, EPA intends 

to modify its approval of the full SIP to 

take back the assurance provisions in 

order to apply, in the FIP, the assurance 

provisions to both Indian country and 

non-Indian country units. 

This final rule not only allows a state 

to choose to submit an abbreviated or a 

full SIP; it also allows a state to choose 

to submit either form of SIP to replace 

any or all of the FIPs in this rule as they 

apply to a particular state. By 

promulgating these Transport Rule FIPs, 

EPA in no way affects the right of a state 

to submit, for review and approval, a 

SIP that replaces the federal 

requirements of the FIP with state 

requirements that do not involve state 

participation in the Transport Rule 

trading programs. In order to replace the 

FIP in a state, the state’s SIP taking an 

approach other than participation in 

Transport Rule trading programs must 

provide adequate provisions to prohibit 

NOX and SO2 emissions that are 

determined in the Transport Rule to 

contribute significantly to 

nonattainment or interfere with 

maintenance in another state or states. 

EPA will review such a SIP on a caseby-case basis. The Transport Rule FIPs 

remain fully in place in each covered 

state until a state’s SIP is submitted and 

approved by EPA to revise or replace a 

FIP. 

In response to numerous comments 

urging EPA to allow states to determine 

allowance allocations as soon as 

possible, EPA has developed a SIP 

revision procedure that applies to 2013 

allowance allocations only. In 

developing this procedure, EPA is 

balancing the desire to allow states the 

flexibility to tailor allowance allocations 

to the specific needs and situations in 

a particular state with the need to 

provide certainty to source owners and 

operators by having allowances 

recorded sufficiently ahead of the 

control period for which the allocations 

are made in order to facilitate owners’ 


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122Existing unit means a unit that commenced 

commercial operation before January 1, 2010. 

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 those units and their 

corresponding allocations for 2013. 

Additionally, this particular SIP 

revision may allocate only the portions 

of the state budgets set forth in Tables 

X–1 through X–3, i.e., each state budget 

minus the new unit set-aside and the 

Indian country new unit set-aside. 

In developing this procedure, EPA set 

deadlines for submissions of the SIP 

revisions for 2013 allocations and for 

recordation of the allocations that 

balanced the need to record allowances 

sufficiently ahead of the control period 

with the desire to allow state flexibility 

for 2013. EPA set deadlines that will 

allow sufficient time for EPA to review 

and approve these SIP revisions, taking 

into account that EPA approval must be 

final and effective before the 2013 

allocations can be recorded and the 

allowances are available for trading. In 

order to ensure that EPA review and 

approval (which must include public 

notice and opportunity for comment) 

can be completed in time, the final rule 

necessarily limits the allowed scope of 

the SIP revisions for 2013 allocations, as 

set forth in the requirements discussed 

below, and thereby limits the issues that 

must be considered and addressed in 

the review and approval process. 

Further, the final rule prescribes the 

form in which the state allocations for 

2013 must be provided to EPA in order 

to facilitate rapid recordation of the 

allocations upon their approval. 

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 the date 70 days after 

publication of the final rule in the 

Federal Register, a state must provide 

notification to EPA if the state intends 

to submit state allocations for 2013. The 

notification must be in a format 

prescribed by the Administrator and 

submitted electronically. 

• By April 1, 2012, the state must 

submit a SIP revision to EPA that: 

Æ Allocates to existing units 122 only, 

provides a list of the units and their 

state allocations to EPA electronically 

and in a format prescribed by EPA, and 

does not provide for any change in the 

units and allocations on the list and in 

any allocation previously determined 

and recorded by the Administrator; 

Æ Allocates a total amount of 

allowances for 2013 that does not 

exceed the applicable amount in Tables 

X–1 through X–3 for each trading 

program that applies in that particular 

state; and 

Æ Provides for no set-asides and does 

not alter the new unit set-asides, the 

Indian country new unit set-asides, and 

any aspect of the FIP rules other than 

the existing-unit allocations for 2013. 

If EPA does not receive notification 

from a state by the date 70 days after 

publication of the final rule in the 

Federal Register, EPA will record FIP 

allocations for 2012 and 2013 as 

scheduled (by the date 90 days after 

publication of the final rule). If EPA 

receives timely notification from a state, 

EPA will record FIP allocations for 2012 

only and wait to record 2013 

allocations. If the state provides a timely 

(not later than April 1, 2012) SIP 

revision meeting all the above-described 

requirements and EPA approves the SIP 

revision by October 1, 2012, EPA will 

record state-determined allocations for 

2013 by October 1, 2012. Otherwise, 

EPA will record the EPA-determined 

allocations for 2013. 

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BILLING CODE 6560–50–C 

EPA will work with states that wish 

to submit full SIPs or abbreviated SIPs 

to ensure a smooth integration with the 

relevant Transport Rule trading 

programs. The Agency intends to 

provide information and tools to assist 

states in their rulemaking efforts, 

including electronic versions of the 

Transport Rule trading rules and EPA 

will work with states that wish to 

submit full SIPs or abbreviated SIPs to 

ensure a smooth integration with the 

relevant Transport Rule trading 

programs. The Agency intends to 

provide information and tools to assist 

states in their rulemaking efforts, 

including electronic versions of the 

Transport Rule trading rules and other 

products states feel may be helpful. 

States that submit approvable full SIPs 

or abbreviated SIPs to implement one or 

all of the Transport Rule trading 

programs are not required to include an 

additional technical demonstration 

relating to elimination of emissions that 

contribute significantly to 

nonattainment or contribute to 

maintenance in downwind areas. 

XI. Structure and Key Elements of 

Transport Rule Air Quality-Assured 

Trading Program Rules 

In order to make the final FIP trading 

program rules as simple and consistent 

as possible, EPA designed them so that 

the final rules (like the proposed rules) 

for each of the trading programs (i.e., the 

‘‘TR NOX Annual Trading Program’’, 

‘‘TR NOX Ozone Season Trading 

Program’’, ‘‘TR SO2 Group 1 Trading 

Program’’, and ‘‘TR SO2 Group 2 

Trading Program’’) are parallel in 

structure and contain the same basic 

elements. For example, the rules for the 

Transport Rule annual NOX, ozoneseason 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. 


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(1) General Provisions 

(i) §§ 97.402 and 97.403, 97.502 and 

97.503, 97.602 and 97.603, and 97.702 

and 97.703—Definitions and 

Abbreviations 

Most of the definitions in the final 

Transport Rule trading program rules 

are essentially the same as in the 

proposed rules and for each of the 

Transport Rule trading programs (except 

where necessary to reflect the different 

pollutants (NOX and SO2), control 

periods (for annual and ozone-season 

NOX, and for annual SO2), and 

geographic coverage involved in the 

trading programs). Moreover, many of 

the definitions in the final rules that are 

essentially the same as in the proposed 

rule are also essentially the same as in 

prior EPA-administered trading 

programs. However, as discussed in 

more detail below, some of the 

definitions in the final rules clarify, or 

differ from, the definitions in the 

proposed rule. 

As noted, several definitions in the 

final rules are essentially the same as 

those both in the proposed rules and in 

prior 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 are used as fuel, 

these materials in the consumer 

products qualify as fossil fuel. The 

definition in the final rules also 

includes language establishing a 

narrower meaning of ‘‘fossil fuel’’ that is 

not generally applicable, but rather is 

applicable only for purposes of applying 

the limitation on fossil-fuel use under 

the solid waste incineration unit 

exemption (which is discussed 

elsewhere in this preamble). This latter 

portion of the ‘‘fossil fuel’’ definition 

makes explicit an interpretation that 

EPA adopted in CAIR that—solely for 

purposes of applying the 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. 

By further example, while the 

proposed rules used the same definition 

of ‘‘commence commercial operation’’ 

as in prior EPA-administered trading 

programs, the final rules clarify the 

definition. Under the definition in the 

proposed rules, a unit that is physically 

changed is treated as the same unit. 

However, the proposed rules were 

unclear about the treatment of a unit 

that is replaced and whether moving a 

unit to a different location or source 

constitutes a physical change. The 

definition of ‘‘commence commercial 

operation’’ in the final rules clarifies 

that a unit that is physically changed 

(which includes a unit that is replaced) 

continues to be treated, for purposes of 

this final rule, as the same unit with the 

same commence-commercial-operation 

date. The definition also clarifies that 

moving a unit to a different location or 

source is treated the same as a physical 

change, and so the unit continues to be 

treated as the same unit. The definition 

also clarifies that a unit (the replaced 

unit) that is replaced, whether at the 

same source or a different source, is 

treated as the same unit, while the unit 

(the replacement unit) that replaces the 

unit is treated as a separate unit with a 

new commence-commercial-operation 

date. (The definition of ‘‘commence 

operation’’ is removed in the final rules 

because they do not use this term.) 

By further example, while the 

proposed rules used the same definition 

of ‘‘unit’’ as in prior EPA-administered 

trading programs, the final rules clarify 

the definition. The ‘‘unit’’ definition is 

clarified by expanding it to incorporate 

explicitly the concepts—set forth in the 

definition in the final rules of 

‘‘commence commercial operation’’ and 

thus already applicable to all units— 

that a unit that is physically changed, 

moved to a different location or source, 

or replaced at the same or a different 

source continues to be treated as the 

same unit and that a replacement unit 

at the same source is treated as a 

separate unit. EPA believes that it is 

preferable to provide a comprehensive 

definition of ‘‘unit’’ in one place 

because the term is used so frequently 

in the final rules. 

By further example, the definition of 

‘‘nameplate capacity’’ is clarified in the 

final rules by explaining that it is 

expressed in MWe rounded to the 

nearest tenth. This is the same rounding 

convention that is used in the reporting 

of nameplate capacity to the Energy 

Information Administration. 

As noted above, some of the 

definitions in the final rules are similar 

to those in the proposed rules but have 

some substantive differences. For 

example, in the proposed rules, the 

definitions of ‘‘cogeneration unit’’ and 

‘‘fossil-fuel-fired’’ are similar to those in 

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-fuelfired, a unit would have to combust any 

amount of fossil fuel in 1990 or 

thereafter. In order to qualify as a 

cogeneration unit, a unit would have to 

meet certain efficiency and operating 

standards during the later of: the 12- 

month period starting when the unit 

begins producing electricity, or 1990. 

For a topping-cycle unit, useful power 

plus one-half of useful thermal energy 

output of the unit must equal no less 

than a certain percentage of the total 

energy input and useful thermal energy 

must be no less than a certain 

percentage of total energy output, and, 

for a bottoming-cycle unit, useful power 

must be no less than a certain 

percentage of total energy input. EPA 

proposed to limit to 1990 or later the 

historical period for which information 

on fuel consumption and on 

cogeneration unit efficiency and 

operations would be required to apply 

the ‘‘fossil-fuel-fired’’ and ‘‘cogeneration 

unit’’ definitions. This limitation was 

proposed because EPA was concerned 

that some owners and operators could 

have difficulty obtaining pre-1990 

information about older units, 

particularly for units whose ownership 

has changed over time. 

While EPA proposed to use 1990 as 

the earliest year for which information 


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would be required under these 

definitions, EPA requested comment on 

whether a more recent year should be 

used. As discussed elsewhere in this 

preamble, the final rules use 2005 

(about 5 years before this rule’s 

promulgation), rather than 1990, as the 

reference year. Further, because the 

language describing the historical time 

period used (including the reference 

year), appeared in the proposal both in 

the ‘‘cogeneration unit’’ definition and 

the provisions concerning cogeneration 

units in the applicability provisions, the 

final rules removed any language about 

the historical time period from the 

‘‘cogeneration unit’’ definition and 

revised the language in the applicability 

provisions to use the 2005 reference 

year for the requirements for meeting 

the exemption for cogeneration units 

from the Transport Rule trading 

programs. Further, consistent with this 

use of 2005 as the reference year, the 

‘‘fossil-fuel-fired’’ definition in the final 

rule specifically references 2005, rather 

than 1990, and as discussed elsewhere 

in this preamble, the final rules also use 

January 1, 2005 (rather than November 

15, 1990) as the reference date 

throughout the applicability provisions. 

With this change in the reference date 

for the requirement to meet the 

operating and efficiency standards 

under the ‘‘cogeneration unit’’ 

definition, a unit would have to meet 

these standards throughout the later of 

2005 or the 12-month period starting 

when the unit begins producing 

electricity and continuing thereafter. 

EPA requested comment on whether 

these standards should be applied to a 

calendar year when the unit involved 

did not combust any fuel, i.e., did not 

operate at all. As discussed elsewhere in 

this preamble, the final rules expressly 

provide that the operating and 

efficiency standards do not have to be 

met for a calendar year throughout 

which a unit did not operate at all. 

In addition, under the proposed rules, 

if a group of cogeneration units 

operating as an integrated cogeneration 

system met the efficiency standards, a 

topping-cycle unit in that system would 

be deemed to meet those standards. EPA 

requested comment on whether this 

provision should also apply to a 

bottoming-cycle unit. As discussed 

elsewhere in this preamble, this 

provision in the final rules is not 

limited to topping-cycle units. 

By further example of definitions in 

the final rules that have substantive 

differences from the definitions in the 

proposed rules, the proposed definitions 

of ‘‘TR NOX Annual allowance,’’ ‘‘TR 

NOX Ozone Season allowance,’’ ‘‘TR 

SO2 Group 1 allowance,’’ ‘‘TR SO2

Group 1 allowance,’’ ‘‘TR NOX Annual 

Trading Program,’’ ‘‘TR NOX Ozone 

Season Trading Program,’’ ‘‘TR SO2

Group 1 Trading Program,’’ and ‘‘TR 

SO2 Group 1 Trading Program’’ are 

changed in the final rules. Language is 

added to the definitions in order to 

reference comparable allowances and 

trading programs established through 

SIP revisions submitted by states and 

approved by the Administrator. As 

discussed elsewhere in this preamble, 

the final Transport Rule provides that, 

if a state submits SIP revisions meeting 

certain specified requirements, the state 

or permitting authority (rather than the 

Administrator) will allocate allowances, 

and the covered sources in the state will 

participate—along with covered sources 

in states remaining subject to the 

Transport Rule FIPs—in an integrated, 

region-wide air quality-assured trading 

program under which both any 

allowance allocated by the 

Administrator and any allowance 

allocated by the state or permitting 

authority will each authorize one ton of 

emissions of the relevant pollutant and 

will be usable by any source for 

compliance with the requirement to 

hold allowances covering emissions. 

As noted above, the final rules 

include some definitions that were not 

used in prior EPA-administered trading 

programs and that reflect unique 

provisions of the Transport Rule trading 

programs. For example, the terms, 

‘‘assurance account,’’ ‘‘TR NOX Annual 

unit,’’ ‘‘TR NOX Ozone Season unit,’’ 

‘‘TR SO2 Group 1 unit,’’ ‘‘TR SO2 Group 

2 unit,’’ ‘‘common designated 

representative,’’ ‘‘common designated 

representative’s assurance level,’’ and 

‘‘common designated representative’s 

share’’ are used and defined in the final 

rule. 

While the proposed rules included 

definitions for the terms, ‘‘owner’s 

assurance level’’ and ‘‘owner’s share,’’ 

the final rules replace these terms and 

instead define the terms, ‘‘common 

designated representative,’’ ‘‘common 

designated representative’s assurance 

level,’’ and ‘‘common designated 

representative’s share.’’ This is because, 

as discussed elsewhere in this preamble, 

the final rules include assurance 

provisions similar to those in the 

proposed rules but that are 

implemented based on groups of units 

having a common designated 

representative, instead of being 

implemented on an owner-by-owner 

basis. The definition of ‘‘common 

designated representative’’ in the final 

rules reflects that the determination of 

what groups of units and sources in a 

State have a common designated 

representative is made based on the 

identity of units’ and sources’ 

designated representatives as of April 1 

of the year after the year of the control 

period when a state triggers the 

assurance provisions. EPA believes that 

the use of this reference date will give 

owners and operators greater flexibility 

to select common designated 

representatives after information about 

total state control period emissions is 

available and after the allowance 

transfer deadline when owners and 

operators may prefer to have a 

designated representative for their 

specific source (rather than a common 

designated representative for a larger 

group) who is focused on ensuring that 

sufficient allowances are held in or 

transferred to the source’s account to 

cover the sources’ emissions. EPA notes 

that the definition of ‘‘common 

designated representative’s share’’ is 

simpler than the definition of ‘‘owner’s 

share’’ because implementing the 

assurance provisions at the designated 

representative level means it is no 

longer necessary to address, in the 

definition, owner- and unit-level issues 

that may arise when a unit has multiple 

owners or where two or more units emit 

through the same stack. 

Finally, some definitions are added to 

the final rules that are not in the 

proposed rules. For example, because 

the term, ‘‘business day,’’ was used, but 

not defined, in the proposed rule, its 

meaning was unclear. Specifically, it 

was unclear whether a day that was 

uniquely a state holiday, and not a 

federal holiday, was a business day for 

purposes of the federally administered 

Transport Rule trading programs, e.g., 

whether the allowance transfer deadline 

applicable to all sources in all states in 

a Transport Rule trading program could 

fall on a day that was a unique state 

holiday in one or a few states or 

whether the allowance transfer deadline 

would be advanced to the next business 

day for all sources in all states or 

perhaps only for sources in the state 

with the state holiday. EPA believes 

that, for a federally administered trading 

program covering sources in multiple 

states, the deadlines should be clear and 

uniform for all sources, regardless of the 

state in which the sources are located, 

and should not be affected by unique 

state holidays of which owners and 

operators of sources in other states may 

not even be aware. Consequently, the 

‘‘business day’’ definition is added in 

the final rules and means a day that 

does not fall on a weekend or a federal 

holiday. 

By further example, a definition for 

‘‘natural gas’’ was added in the final 

rules. That definition, as well as the 

definition for ‘‘coal,’’ incorporate the 


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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. 

Under the general applicability 

provisions of the proposed rules, the 

Transport Rule trading programs would 

cover fossil-fuel-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 throughout 

each calendar year ending after the later 

of 2005 or such 12-month period and 

that meets the limitation on electricity 

sales to the grid. In order to qualify as 

a cogeneration unit (i.e., meet the 

definition of ‘‘cogeneration unit’’) in the 

final rules, a unit (i.e., a boiler or 

combustion turbine) must operate as 

part of a ‘‘cogeneration system,’’ which 

is defined as an integrated group of 

equipment at a source (including a 

boiler or combustion turbine, and a 

steam turbine generator) designed to 

produce useful thermal energy for 

industrial, commercial, heating, or 

cooling purposes and electricity through 

the sequential use of energy. In 

addition, in order to qualify, a unit must 

be a topping-cycle unit or a bottoming 

cycle unit because units that produce 

useful thermal energy and useful power 

through sequential use of energy either 

produce useful power first (i.e., are 

topping-cycle units) or produce thermal 

energy first (i.e., are bottom-cycle units). 

Further, in order to qualify as a 

cogeneration unit, a unit also must 

meet, on a 12-month or annual basis, the 

above described efficiency and 

operating standards. As discussed 

elsewhere in this preamble, EPA 

clarifies that the electricity sales 

limitation under the exemption is 

applied in the same way whether a unit 

serves only one generator or serves more 

than one generator. In both cases, the 

total amount of electricity produced 

annually by a unit and sold to the grid 

cannot exceed the greater of one-third of 

the unit’s potential electric output 

capacity or 219,000 MWhr. 

The final rules also clarify when a 

unit that meets the requirements for the 

cogeneration unit exemption and 

subsequently fails to meet all these 

requirements loses the exemption and 

becomes a covered unit. Such a unit 

loses the exemption starting the earlier 

of January 1 (or May 1 for the NOX

ozone season trading program) after the 

first year during which the unit no 

longer meets the ‘‘cogeneration unit’’ 

definition or January 1 (or May 1) of the 

first year during which the unit no 

longer meets the electricity sales 

limitation. 

Solid waste incineration unit 

exemption. The final rules also include 

an exemption for a unit that qualifies as 

a solid waste incineration unit during 

the later of 2005 or the first 12 months 

during which the unit first produces 

electricity, that continues to qualify 

throughout each calendar year ending 

after the later of 2005 or such 12-month 

period, and that meets the limitation on 

fossil-fuel use. In contrast, the 

exemption for solid waste incineration 

units in the proposed rules 

distinguished between units 

commencing operation before January 1, 

1985 and those commencing operation 

on or after that date and established 

somewhat different criteria for these two 

categories of units. As discussed 

elsewhere in this preamble, the final 

rules remove the distinction based on 

whether a solid waste incineration unit 

commences operation before January 1, 

1985 or on or after January 1, 1985. In 

order to be exempt, the unit must 

qualify as a solid waste incineration 

units during the later of 2005 or the first 

12 months during which the unit first 

produces electricity, must continue to 

qualify throughout each calendar year 

ending after the later of 2005 or such 12- 

month period, and must meet the 

limitation on fossil-fuel use on a threeyear 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 preamble) if the state’s 

total covered-unit emissions exceed the 

state assurance level. 

Specifically, a common designated 

representative must include these units 

in determining whether his or her share 

of total emissions of covered units in a 

state exceed his or her share (generally 

based on the allowances allocated to the 

units that he or she represents) of the 

state trading budget with the variability 

limit and thus whether the owners and 

operators of the units that he or she 

represents have to surrender allowances 

under the assurance provisions. 

(iii) §§ 97.406, 97.506, 97.606, and 

97.706—Standard Requirements 

The basic requirements applicable to 

owners and operators of units and 

sources covered by the Transport Rule 

trading programs and presented as 

standard requirements in the final rules 

are, except as discussed herein, 

essentially the same as in proposed 

rules and for each of the Transport Rule 

trading programs. These basic 

requirements include: designated 

representative requirements; emissions 

monitoring, reporting, and 

recordkeeping requirements; emissions 

requirements comprising emissions 

limitations and assurance provisions; 

permit requirements; additional 

recordkeeping and reporting 

requirements; liability provisions; and 

provisions describing the effect of the 

Transport Rule trading program 

requirements on other CAA provisions. 

In particular, the paragraphs 

addressing emissions requirements for 

owners and operators describe these 

requirements in detail and reference 


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other sections of the final rules that set 

forth the procedures for determining 

compliance with the emissions 

limitations and assurance provisions. 

The paragraphs in the final rules 

concerning compliance with the 

emissions limitations clarify that 

owners and operators of a source and 

each covered unit at the source must 

hold allowances at least equaling the 

total control period emissions of all 

covered units at the source. Further, the 

paragraphs in the final rules concerning 

compliance with the assurance 

provisions differ from those in the 

proposed rules in that, as discussed 

elsewhere in this preamble, the final 

rules implement the assurance 

provisions based on groups of units 

with a common designated 

representative, instead of being 

implemented on an 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 

deduction through the transfer of such 

allowances to the assurance account 

created by the Administrator for such 

owners and operators) is determined on 

a common designated representative 

basis. 

For purposes of implementing the 

assurance provisions, covered units in a 

state are in effect grouped by common 

designated representative (which is 

defined as an individual (i.e., a natural 

person) who is the designated 

representative, as distinguished from 

the alternate designated representative, 

for a group of one or more units and 

sources as of April 1 after the control 

period for which the state exceeds the 

state assurance level). The control 

period emissions of all covered units 

with a common designated 

representative are compared with the 

allowance allocations of such units plus 

their share of the state variability limit. 

The owners and operators of the units 

and sources in each group that has 

emissions in excess of allocations plus 

share of variability are subject to the 

assurance provisions penalty. The 

owners and operators of the units and 

sources in each group must transfer to 

the assurance account created for such 

owners and operators a total amount of 

allowances equal to two times such 

owners’ and operators’ proportionate 

share of the state’s excess of coveredunit 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 this percentage is not rounded to 

the nearest whole number, but rather 

that the calculated amount of 

allowances resulting from application of 

this percentage is rounded to the nearest 

whole number because, in the Transport 

Rule trading programs, only whole (not 

fractional) allowances are used. If 

instead this percentage were rounded 

before its application, each group’s 

share would be either 100 percent or 0 

percent, which would be contrary to the 

intent of the assurance provisions in 

both the final rules and the proposed 

rules. 

The provisions addressing the 

assurance requirements in the final 

rules reflect this common-designatedrepresentative-based approach. For 

example, as discussed elsewhere in this 

preamble, these provisions use the 

terms, ‘‘common designated 

representative’s share’’ and ‘‘common 

designated representative’s assurance 

level,’’ in lieu of the terms, ‘‘owner’s 

share’’ and ‘‘owner’s assurance level,’’ 

used in the proposed rules. By further 

example, these final rule provisions 

refer to both ‘‘common designated 

representatives’’ and ‘‘owners and 

operators,’’ rather than simply 

‘‘owners.’’ 

The final rules also explain what 

vintage year (i.e., allocation year) of 

allowances can be used in order to 

comply with the requirement to cover 

emissions and with the requirements of 

the assurance provisions. With regard to 

emissions during a control period in a 

given year, only allowances allocated 

for that year or any prior year can be 

used to cover such emissions. Further, 

only allowances of the following vintage 

can be used to meet excess emissions 

penalties and assurance penalties 

concerning emissions during a control 

period in a given year: allowances 

allocated for that year, any year before 

that year, or the year immediately after 

that year. This approach makes the 

vintage years usable for excess 

emissions and assurance penalties 

consistent and helps ensure that 

allowances will be available to meet 

these obligations. 

The final rules also clarify the 

standard emission requirements by 

explaining further what is meant by the 

provision that an allowance is a limited 

authorization to emit. The final rules 

clarify that an allowance provides 

authorization to emit during the control 

period in one year and is limited in both 

its use and its duration. For example, 

each Transport Rule trading program’s 

final rules state that an allowance 

provides an emission authorization that 

can only be used in accordance with the 

requirements of the respective trading 

program, such as the requirements 

specifying what allowances are 

available for use, and how such 

allowances must be held or transferred, 

in order to cover emissions or meet the 

assurance provisions. By further 

example, under the final rules, an 

allowance continues to provide an 

authorization to emit one ton of the 

relevant pollutant until the allowance is 

deducted, e.g., in order to be used for 

compliance with the requirement to 

cover emissions or the requirements of 

the assurance provisions. Moreover, 

under the final rules, the Administrator 

has the express authority to terminate or 

limit the authorization to emit, and 

thereby change the use and duration of 

the authorization, described in the final 

rules, to the extent he or she determines 

to be necessary or appropriate to 

implement any provision of the CAA. 

The remaining paragraphs in the 

standard requirements section address 

permitting, recordkeeping and 

reporting, liability provisions, and the 

effect on other CAA provisions. For 

example, the paragraphs concerning 

permitting requirements are limited to 

stating that no title V permit revisions 

are necessary to account for allowance 

allocation, holding, deduction, or 

transfer and that the minor permit 

modification procedures can be used to 

add or change general descriptions in 

the title V permits of the monitoring and 

reporting approach used by the units 

covered by each title V permit. These 

provisions remain essentially the same 

in the final rules as in the proposed 

rules. 

(iv) §§ 96.407, 97.507, 97.607, and 

97.707—Computation of Time 

These sections address how to 

determine the deadlines referenced in 

the Transport Rule trading program 

rules and are, except as discussed 

herein, essentially the same as in the 

proposed rules and for each of the 

Transport Rule trading programs. The 

final rules revise the proposed rule 

provisions concerning the treatment of 

the final date in any time period in 

order to make the provision consistent 

with the approach discussed above with 

regard to the new definition of 

‘‘business day.’’ The revised provision 

states that, if the final date is not a 


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‘‘business day’’, then the time period is 

extended to the next ‘‘business day.’’ 

(v) §§ 97.408, 97.508, 97.608, 97.708 and 

Part 78—Administrative Appeal 

Procedures 

Under the final Transport Rule, final 

decisions of the Administrator under 

the Transport Rule trading programs are 

appealable to EPA’s Environmental 

Appeals Board under the regulations set 

forth in Part 78 (40 CFR part 78), which 

are revised by the final Transport Rule 

to accommodate such appeals. The 

provisions in the final Transport Rule 

concerning appeals are, except as 

discussed herein, essentially the same 

as in the proposed Transport Rule. The 

proposed Transport Rule would add a 

provision in Part 78 explaining who is 

an ‘‘interested person’’ with regard to a 

decision, i.e., a person who submitted 

comments, testimony, or objections as 

part of the process of making the 

decision or a person who submitted his 

or her name to the Administrator to be 

placed to an interested persons list. The 

final Transport Rule includes that 

provision, but with additional language 

that clarifies the process for submitting 

a name to be placed on such a list. 

(2) Allowance Allocations 

Sections 97.410 through 97.412, 

97.510 through 97.512, 97.610 through 

97.612, and 97.710 through 97.712 set 

forth: certain information related to 

allowance allocation and for 

implementation of the assurance 

provisions; the timing for allocation of 

allowances to existing and new units; 

and the procedures for new unit 

allocations. In particular, these sections 

include tables providing, for each state 

covered by the particular Transport Rule 

trading program and for each year, the 

state trading budget (without the 

variability limit), new unit set-aside, 

Indian country new unit set-aside 

(where applicable), and variability limit. 

These provisions in the final rules differ 

in several ways, from the proposed rules 

and are essentially the same for each of 

the Transport Rule trading programs. 

With regard to the tables in the final 

rules for the state trading budgets 

(without the variability limits), new unit 

set-asides, and variability limits, the 

identity of the specific states involved 

and the values for each state differ from 

the tables in the proposed rules. The 

final rule values reflect the 

determinations and modeling 

underlying the final rules and discussed 

elsewhere in this preamble. Further, as 

discussed elsewhere in this preamble, 

the variability limits are only those 

based on one-year variability and not 

those proposed to be based on threeyear variability, and Indian country setasides are shown for states with Indian 

country within their borders. 

With regard to existing unit 

allocations, the final rules provide that 

these allocations will be set forth in a 

notice of data availability to be issued 

by the Administrator. In contrast, the 

proposed rules stated that existing unit 

allocations would be set forth in an 

appendix to the rules for each Transport 

Rule trading program. EPA believes that 

including these allocations in a notice of 

data availability referencing the EPA 

Web site (rather than publishing them in 

tables requiring a large number of pages 

in the Federal Register for each 

Transport Rule trading program) is a 

more efficient method of making these 

allocations public, particularly since 

these allocations may be changed for 

2013 and thereafter by states through 

SIP revisions. In addition, under the 

final rules the allocations for an existing 

unit can change if the unit does not 

operate (i.e., has no heat input) for 2 

consecutive years starting in 2012. In 

that case, the unit continues to receive 

its existing unit allocation for those 

years plus only 2 more years. As 

explained elsewhere in this preamble, 

this is a modification of the proposed 

rules, under which a unit that did not 

operate for 3 consecutive years would 

continue to receive its existing unit 

allocation for those years plus 3 more 

years. 

Under the final rule provisions for 

new units, the Administrator allocates 

allowances from the new unit set-aside 

for the state where the respective unit is 

located and for each year when the unit 

first becomes eligible for an allocation 

and each year thereafter. The units 

eligible for new unit set-aside 

allocations include units commencing 

commercial operation on or after 

January 1, 2010, as well as several other 

categories of units, such as, for example, 

existing units that were not initially but 

then become covered units, existing 

units whose allocations are lost due to 

lack of unit operation and that 

subsequently begin operating again, and 

units that lost their allocations because 

they changed location from one state to 

another. The approach in the final rules 

differs from the proposed rules, which 

required that owners and operators 

initially request allowances from the 

new unit set-aside when the unit first 

became eligible for an allocation. As 

discussed elsewhere in this preamble, 

under the final rules, EPA identifies 

which units become eligible and when 

they become eligible, based on 

information provided in other 

submissions (e.g., certificates of 

representation, monitoring system 

certifications, and quarterly emissions 

reports) that such units must make to 

EPA, and the requirement that owners 

and operators submit requests for new 

unit set-aside allocations is removed in 

the final rules. 

The final rules also provide for two 

rounds of allocations from the new unit 

set-aside, in contrast with the proposed 

rules that provided for only one round. 

In the first round in the final rules (as 

in the single round in the proposed 

rules), a unit’s new unit set-aside 

allocation initially equals that unit’s 

emissions—as determined in 

accordance with §§ 97.430–97.435, 

97.530–97.535, 97.630–97.635, and 

97.730–97.735 of the final rules and Part 

75 (40 CFR part 75)—for the control 

period (annual or ozone season, 

depending on the Transport Rule 

trading program involved) in the 

preceding year. If the new unit set-aside 

lacks sufficient allowances to provide 

this initial allocation for all of the new 

units, then each new unit is allocated its 

proportionate share (based on its initial 

allocation amount) of the allowances in 

the new unit set-aside. The 

Administrator issues a notice of data 

availability informing the public of the 

specific new unit allocations and 

provides an opportunity for submission 

of objections on the grounds that the 

allocations are not consistent with the 

requirements of the relevant final rule 

provisions. A second notice of data 

availability is subsequently issued in 

order to make any necessary corrections 

in the specific new unit allocations. As 

discussed elsewhere in this preamble, 

the final rules establish a somewhat 

different schedule for issuance of these 

notices of data availability than the 

proposed rules. In particular, a single 

set of dates (i.e., for the first notice, June 

1 of the year for which the new unit 

allocations are described in the notice 

and, for the second notice, August 1 of 

that year) is established for all of the 

Transport Rule trading programs. For 

the reasons discussed elsewhere in this 

preamble, the final rules provide for a 

second round of allocations to the 

extent that any allowances remain in the 

new unit set-aside after the allocations 

are made to new units in the first round. 

(In the proposed rules, remaining 

allowances were immediately allocated 

to existing units.) The units eligible for 

allocations in the second round are new 

units that commenced commercial 

operation during the control period for 

which allocations are being made and 

during the prior control period. The 

second round allocation for each such 

unit initially equals the positive 

difference (if any) between the unit’s 


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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 new units, then each such 

new unit is allocated its proportionate 

share of the allowances remaining in the 

new unit set-aside. The Administrator 

uses notices of data availability (which 

are issued by December 15 (for the 

annual trading programs) and 

September 15 (for the ozone season 

trading program) of the control period 

involved and February 15 (for the 

annual trading programs) and November 

15 (for the ozone season trading 

program) before the allowance transfer 

deadline for the control period 

involved, in a manner analogous to the 

use of such notices in the first round, to 

inform the public about the 

identification of the new units in the 

second round allocations and obtain 

and consider any objections. The 

February 15 and November 15 notices 

also inform the public about the 

amounts of the second round 

allocations. If, after both rounds of 

allocations, any allowances remain in 

the new unit set-aside, those allowances 

are allocated to existing units in 

proportion to such units’ allocations. 

The final rules also establish a 

separate Indian country new unit setaside in each state where Indian country 

is located (i.e., in Florida, Iowa, Kansas, 

Louisiana, Michigan, Minnesota, 

Mississippi, Nebraska, New York, North 

Carolina, South Carolina, Texas, and 

Wisconsin). As discussed elsewhere in 

this preamble, the Administrator 

operates the Indian country new unit 

set-aside in essentially the same manner 

as state new unit set-aside, except that 

unallocated allowances remaining in the 

Indian country new unit set-aside after 

the two rounds of new unit set-aside 

allocations are first placed in the new 

unit set-aside in the state where the 

Indian country involved is located and 

then, if still unallocated, are allocated to 

existing units in the state. As with the 

state new unit set-aside, EPA will 

identify the new units qualifying for the 

Indian country new unit set-aside, 

calculate the allocations, and issue 

notices of data availability using the 

same schedules as notices for the state 

new unit set-aside. 

Under the final rules (like under the 

proposed rules), if a unit in certain 

specified categories is allocated 

allowances that should not have 

received them, the Administrator 

applies procedures under which the 

allocation is not recorded or the amount 

of the recorded allocations is deducted 

as an incorrect allocation, with one 

exception. The exception is where the 

determination of compliance with the 

emissions limitation (i.e., requirement 

to hold allowances covering emissions, 

as distinguished from the assurance 

provisions) for the source that includes 

the unit has already been completed, in 

which case no action is taken to account 

for the erroneous allocation for the 

control period involved. 

While this procedure concerning 

recordation or deduction of allocations 

is the same as under the proposed rules, 

the final rules change the description of 

the circumstances under which this 

procedure concerning recordation or 

deduction of allocations is applied. 

Under both the final rules and the 

proposed rules, this procedure is 

applied to a unit (whether an existing 

unit or a new unit) that receives an 

allocation but is not actually a covered 

unit. However, under the final rules, 

another category of units—i.e., any 

existing unit that is not located—as of 

January 1 of the control period for 

which the allocation is received—in the 

state from whose trading budget the 

allocation was made is also subject to 

this procedure. Although relatively few 

units are moved from one state to 

another, EPA believes that it is 

important to address what happens to 

such units’ allocations, both because 

each state has a limited trading budget 

out of which all allocations for a year to 

existing and new units in that state must 

be made and because, under the 

assurance provisions, determinations 

are made about owners’ and operators’ 

surrender of allowances based on, 

among other things, the allocations for 

units in a specific state. Because, under 

the final rules, a unit that is moved from 

one state to another may lose its existing 

unit allocation in the first state under 

the above-described procedure, the final 

rules also makes such a unit eligible for 

allocations from the new-unit set-aside 

of the second state. 

Finally, the final rules remove, as no 

longer necessary, one category of units 

that the proposed rules included as 

subject to this procedure. The proposed 

rules, treated, as existing units, some 

units that had not yet operated but were 

projected to operate by January 1, 2012, 

and so the proposed rules made these 

units subject to the procedure for not 

recording or for deducting allocations if 

they actually were not required to 

certify their monitoring systems and 

hold allowances covering emissions 

starting January 1, 2012. The final rule 

does not treat projected units as existing 

units and so this category of units no 

longer needs to be made subject to this 

procedure. 

(3) Designated Representatives and 

Alternate Designated Representatives 

Sections 97.413 through 97.418, 

97.513 through 97.518, 97.613 through 

97.618, and 97.713 through 97.718 

establish the procedures for certifying 

and authorizing the designated 

representative, and alternate designated 

representative, of the owners and 

operators of a source and the units at the 

source, and for changing the designated 

representative and alternate designated 

representative. These sections also 

describe the designated representative’s 

and alternate designated 

representative’s responsibilities and the 

process through which he or she can 

delegate to an agent the authority to 

make electronic submissions to the 

Administrator. Except as discussed 

herein, the provisions in the final rules 

are essentially the same as in the 

proposed rules and for each of the 

Transport Rule trading programs. 

The designated representative is the 

individual (i.e., the natural person) 

authorized to represent the owners and 

operators of each covered source and 

covered unit at the source in matters 

pertaining to all Transport Rule trading 

programs to which the source and units 

were subject. One alternate designated 

representative (also an individual) can 

be selected to act on behalf of, and 

legally bind, the designated 

representative and thus the owners and 

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 


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source or covered unit must be 

submitted, signed, and certified by the 

designated representative or alternate, 

except that electronic submission may 

be delegated. 

In order to change the designated 

representative or alternate, a new 

certificate of representation must be 

received by the Administrator. A new 

certificate of representation must also be 

submitted to reflect changes in the 

owners and operators of the source and 

units involved. The new certificate must 

be submitted within 30 days of such 

changes. 

The final rules make explicit an 

implied requirement of the proposed 

rules, i.e., that, if a unit is added to a 

source or is moved from one source to 

a second source, a certificate of 

representation needs to be submitted to 

reflect the change. This requirement is 

implicit in the proposed rules when a 

unit is added to a source because the 

designated representative would not be 

authorized to make submissions 

concerning the added unit unless that 

unit were included on the certificate of 

representation. Similarly, where a unit 

is moved to another source, new 

certificates of representation would 

need to be submitted in order for the 

correct designated representative to be 

authorized to make submissions 

concerning the moved unit. Moreover, 

because compliance accounts in the 

Allowance Management System would 

cover all units at a given source and 

would be based on the information in 

the certificate of representation 

submitted by the designated 

representative for the source, when a 

unit is moved from a source to a second 

source, the designated representative of 

the second source would need to submit 

a certificate of representation removing 

the moved unit from the list of units. 

The final rules explicitly require that 

a new certificate of representation be 

submitted to reflect changes (whether 

caused by the addition or removal of 

units) in which units are located at a 

source. In addition, the final rules 

impose a deadline on the submission 

requirement of 30 days from the date of 

the change in the units. This is 

analogous to the maximum time period 

between a change in a unit’s owner or 

operator and the deadline for 

submission of a new certificate of 

representative reflecting to the change. 

Long before any actual move of a unit 

to a new location, owners and operators 

will need to make decisions about, and 

plan the implementation of, such a 

move. Consequently, EPA believes that 

a 30-day deadline after any move for 

reflecting the move in the certificate of 

representation is reasonable. In the 

event the change involves the addition 

of a unit that operated before being 

located at the source, the final Transport 

Rule also requires that the designated 

representative provide in the certificate 

of representation information on the 

entity from which the unit was 

obtained, the date on which the unit 

was obtained, and the date on which the 

unit became located at the source. In the 

event of a change involving the removal 

of a unit, the designated representative 

must provide in the certificate of 

representation information on the entity 

that obtained the unit, the date on 

which that entity obtained the unit, and 

the date on which the unit became no 

longer located at the source. This 

information will enable the 

Administrator to determine what 

actions are necessary to reflect the 

change in units located at the sources 

involved. For example, if a covered unit 

is moved from one source to second 

source, the Administrator will have the 

information necessary to determine 

whether the unit’s allocation should be 

changed to reflect movement of the unit 

from one state to another. 

(4) Allowance Management System 

Sections 97.420 through 97.428, 

97.520 through 97.528, 97.620 through 

97.628, and 97.720 through 97.728 

establish the procedures and 

requirements for using and operating 

the Allowance Management System 

(which is the electronic data system 

through which the Administrator 

handles allowance allocation, holding, 

transfer, and deduction), and for 

determining compliance with the 

emissions limitations and assurance 

provisions, in an efficient and 

transparent manner. The Allowance 

Management System also provides the 

allowance markets with a record of 

ownership of allowances, dates of 

allowance transfers, buyer and seller 

information, and the serial numbers of 

allowances transferred. Except as 

discussed herein, these sections of the 

final rules are essentially the same as in 

the proposed rules and for each of the 

Transport Rule trading programs. 

(i) §§ 97.420, 97.520, 97.620, and 

97.720—Compliance, Assurance, and 

General Accounts 

Under the final rules, the Allowance 

Management System contains three 

types of accounts. One type comprises 

compliance accounts, one of which the 

Administrator establishes for each 

covered source upon receipt of the 

certificate of representation for the 

source. A compliance account is the 

account in which all allowance 

allocations must be recorded and in 

which any allowances used by the 

covered source for compliance with the 

emission limitations must be held. The 

designated representative and alternate 

for the source are also the authorized 

account representative and alternate for 

the compliance account. 

A second type comprises general 

accounts, which can be established by 

any entity upon receipt by the 

Administrator of an application for a 

general account. General accounts can 

be used by any person or group for 

holding or trading allowances. To open 

a general account, a person or group 

must submit an application for a general 

account, which is similar in many ways 

to a certificate of representation. The 

provisions for changing the authorized 

account representative and alternate, for 

submitting a superseding application to 

take account of changes in the persons 

having an ownership interest with 

respect to allowances, and for delegating 

authority to make electronic 

submissions are analogous to those 

applicable to comparable matters for 

designated representatives and 

alternates. 

A third type comprises assurance 

accounts. The Administrator establishes 

one assurance account for each group of 

units having a common designated 

representative and located in a state 

where the assurance provisions are 

triggered by total emissions exceeding 

the state trading budget plus variability. 

(ii) §§ 97.421 Through 97.423, 97.521 

Through 97.523, 97.621 Through 

97.623, and 97.721 Through 97.723— 

Recordation of Allowance Allocations 

and Transfers 

Under the final rules, by November 7, 

2011, 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 revision with existing-unit 

allocations for 2013 by May 1, 2012. If 

the Administrator approves that SIP 

revision by October 1, 2012, the 

Administrator will record the statedetermined existing-unit allocations for 

2013, and, in the absence of such 

approval by that date, the Administrator 

will record the EPA-determined 

existing-unit allocations for 2013. By 

July 1, 2013, the Administrator must 

record existing-unit allowance 

allocations (whether EPA- or statedetermined) for each Transport Rule 

trading program for 2014 and 2015. By 

July 1, 2014, the Administrator must 


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record existing-unit allowance 

allocations for each Transport Rule 

trading program for 2016 and 2017. By 

July 1, 2015, the Administrator must 

record existing-unit allowance 

allocations for each Transport Rule 

trading program for 2018 and 2019. By 

July 1, 2016 and July 1 of each year 

thereafter, the Administrator must 

record existing-unit allowance 

allocations for each Transport Rule 

trading program for the control period 

in the fourth year after the year of the 

applicable recordation deadline. By 

August 1, 2012 and August 1 of each 

year thereafter, the Administrator must 

record new-unit allowance allocations 

for each Transport Rule trading program 

for that year. These recordation 

deadlines differ from those in the 

proposed rules for two reasons. First, as 

discussed elsewhere in this preamble, 

EPA is adopting provisions that allow 

states to submit, and EPA to approve, 

SIP revisions (abbreviated or full SIPs) 

under which the state, rather than the 

Administrator, determines the 

distribution of allowances under one or 

more of the Transport Rule trading 

programs applicable in the state. In 

selecting allocation recordation 

deadlines, EPA took into account and 

balanced certain countervailing factors. 

On one hand, EPA considered the need 

to provide a reasonable time for a state 

to develop, propose, and finalize, and 

for EPA to review and propose and 

finalize approval of, the SIP revision 

and the desirability of providing a 

reasonable opportunity for state 

distributions to become effective for a 

year relatively soon after the 2012 

commencement of the Transport Rule 

trading programs. EPA’s experience 

with prior trading programs has shown 

that the process for development and 

submission of SIP revisions by states 

and approval by EPA in many cases is 

about 18 months and in some cases even 

longer. On the other hand, EPA 

considered the desirability of owners 

and operators having allocations in their 

compliance accounts a reasonable time 

before the year for which the allocations 

are made (i.e., the vintage year). Having 

the allocations recorded, to the extent 

possible, before the vintage year 

facilitates compliance decisions and use 

of the allowance market in 

implementing such decisions. EPA 

believes that optimally allocations 

would be recorded at least 3 years in 

advance of the vintage year. 

In balancing these countervailing 

factors, EPA is adopting an allocation 

recordation schedule that provides 

initially for recordation ranging from 6 

months to 18 months before the 

beginning of the control period in the 

first 2 years (i.e., 2012 and 2013) for 

which allocations are made and that, as 

allocations for control periods in 

subsequent years are recorded, 

gradually increases the amount of time 

between recordation and the beginning 

of the year of the control period 

involved until allocations are recorded 

about three and one-half years in 

advance. With regard to the need to 

facilitate states’ distribution of 

allowances, this approach gives states 

multiple opportunities to develop, 

submit, and obtain EPA approval for 

SIPs under which the states (rather than 

EPA) will distribute allowances under 

the Transport Rule trading programs for 

control periods relatively early in the 

programs. Because of time (which has in 

the past ranged from about 6 months to 

about 2 years) it may take for a state to 

develop and submit such a SIP and 

because of the time (which has in the 

past been at least 6 months) it will likely 

take EPA to review and approve such a 

SIP, EPA believes that 2013 is the first 

year for which a state can determine 

allowance distributions and have them 

recorded some minimal time before the 

control period involved. With regard to 

the need to record allowances in 

advance, this approach achieves 

recordation at least 6 months in advance 

and eventually achieves recordation by 

what EPA believes is an optimal amount 

of time (greater than 3 years) before the 

control period for which recorded 

allowances are issued. 

As discussed elsewhere in this 

preamble, the approach to allowance 

recordation in the final rules results in 

following schedule for submission of 

abbreviated or full SIPs under the final 

Transport Rule. SIP revisions with 

existing-unit allocations for 2013 

control periods must be submitted to the 

Administrator by April 1, 2012. 

Complete abbreviated and full SIPs 

must be submitted to the Administrator 

by: December 1, 2012 in order to govern 

allowance allocation and auction for 

control periods in 2014 and 2015; 

December 1, 2013 in order to govern 

control periods in 2016 and 2017; 

December 1, 2014 in order to govern 

allowance allocation and auction for 

control periods in 2018 and 2019; and 

December 1, 2015 and by January 1 of 

any year thereafter in order to govern 

allowance allocation and auction for 

control periods in the fifth year after the 

year of such submission deadline. 

The second reason for the differences 

in the recordation deadlines in the final 

rules, as compared to the proposed 

rules, is that, in order to simplify the 

recordation schedule for owners and 

operators and EPA, EPA set uniform 

recordation deadlines for all of the 

Transport Rule trading programs. EPA 

believes that these deadlines provide 

the Agency sufficient time, after receipt 

of any information necessary to 

determine allocations (e.g., for new unit 

set-aside allocations, the emission data 

from the control period in the prior 

year), to complete the recordation of 

allocations and, as discussed above, 

makes the allocations available to 

owners and operators before the year for 

which the allocations are made. EPA 

notes that these are deadlines and that 

the Administrator has the discretion, 

where feasible and appropriate, to 

record allocations before such 

deadlines. 

Under the final rules (as under the 

proposed rules), the process for 

transferring allowances from one 

account to another is quite simple. A 

transfer is submitted providing, in a 

format prescribed by the Administrator, 

the account numbers of the accounts 

involved, the serial numbers of the 

allowances involved, and the name and 

signature of the transferring authorized 

account representative or alternate. If 

the transfer form containing all the 

required information is submitted to the 

Administrator and, when the 

Administrator attempts to record the 

transfer, the transferor account includes 

the allowances identified in the form, 

the Administrator records the transfer 

by moving the allowances from the 

transferor account to the transferee 

account within 5 business days of the 

receipt of the transfer form. 

(iii) §§ 97.424, 97.524, 97.624, and 

97.724—Compliance With Emissions 

Limitations 

Under the final rules (as under the 

proposed rules), once a control period 

has ended (i.e., December 31 for the 

Transport Rule NOX and SO2 annual 

trading programs and September 30 for 

the ozone-season NOX trading program), 

covered sources have a window of 

opportunity—until the allowance 

transfer deadline of midnight on March 

1 or December 1 following the control 

period for the annual and ozone season 

trading programs respectively—to 

evaluate their reported 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 


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properly submit a transfer that moves 

into its compliance account, enough 

allowances usable for compliance to 

authorize the source’s total emissions 

for the control period. 

If a source fails to hold sufficient 

allowances for compliance to cover the 

emissions, then the owners and 

operators must provide, for deduction 

by the Administrator, two allowances 

allocated for the control period, in the 

year of when the emissions occurred, 

any prior year, or the year immediately 

after the year of the emissions, for every 

allowance that the owners and operators 

failed to hold as required to cover 

emissions. In addition, the owners and 

operators are subject to discretionary 

civil penalties for each violation. 

(iv) §§ 97.425, 97.525, 97.625, and 

97.725—Compliance With Assurance 

Provisions 

Under the final rules (as under the 

proposed rules), the assurance 

provisions ensure that each state will 

eliminate its significant contribution to 

nonattainment and interference with 

maintenance that EPA identifies in this 

action. A requirement that owners and 

operators surrender allowances under 

the assurance provisions is triggered 

only for certain owners and operators of 

sources and units in a state where the 

total state covered-unit emissions for a 

control period exceed the applicable 

state trading budget with the variability 

limit. Moreover, the surrender 

requirement is implemented based on 

groups of sources and units with a 

common designated representative. For 

each group of sources and units with a 

common designated representative, the 

owners and operators of such sources 

and units must surrender allowances 

only if the units’ emissions (referred to 

as the common designated 

representative’s share of emissions) 

during the control period involved 

exceed the units’ allocations plus share 

of the state variability limit (referred to 

as the common designated 

representative’s share of the state 

trading budget with variability). 

As discussed elsewhere in this 

preamble, EPA decided to implement 

the assurance provisions on a common 

designated representative basis, rather 

than on an owner basis. The final rules 

implement in a series of steps the 

process of determining which states 

have total covered-unit emissions 

sufficient to trigger the allowance 

surrender requirement for a given 

control period and determining, using 

the approach based on common 

designated representatives, which 

owners and operators are subject to the 

allowance surrender and whether those 

owners and operators are in compliance. 

This common-designatedrepresentative-based 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 

1-year variability limit. As discussed 

elsewhere in this preamble, EPA 

decided not to use a 3-year variability 

limit because, among other things, such 

a limit seems unnecessary to ensuring 

elimination of significant contribution 

to nonattainment and interference with 

maintenance and would make 

compliance planning extremely difficult 

for owners and operators. By June 1, 

2013 and June 1 of each year thereafter, 

the Administrator promulgates a notice 

of data availability of the results of these 

calculations. 

Second, by July 1, for states identified 

in the June 1 notice of data availability 

as having emissions exceeding the state 

trading budget with variability, the 

designated representative of each new 

unit in the state that operated during but 

did not receive an allocation for the year 

involved must submit a statement to the 

Administrator with certain information 

about the unit. This information—i.e., 

the unit’s allowable emission rate for 

the pollutant involved (NOX or SO2) and 

heat rate—is used to calculate a 

surrogate allocation for the unit to be 

used solely for the purposes of 

determining whether the group of units 

with a common designated 

representative that includes the unit had 

emissions exceeding allocations plus 

share of the state’s variability limit. 

Third, the Administrator calculates, 

for each state identified in the June 1 

notice of data availability and for each 

common designated representative of a 

group of units (which groups can 

include one or more units and sources) 

in the state, the common designated 

representative’s share of emissions, the 

common designated representative’s 

share of the state trading budget with 

the variability limit, and the amount (if 

any) that the groups of owners and 

operators of units represented by the 

common designated representative 

(which groups can include one or more 

owners and operators) in the state must 

surrender under the assurance 

provisions (i.e., the common designated 

representative’s proportionate share of 

the excess of state emissions over the 

state trading budget with the variability 

limit). The Administrator promulgates 

by August 1 a notice of data availability 

of the results of these calculations, 

provides an opportunity for submission 

of objections, and promulgates by 

October 1 a second notice of data 

availability of any necessary 

adjustments to the calculations. In 

contrast with the proposed rules, 

objections may be submitted concerning 

information in the August 1 notice, 

whether or not that information was 

also provided in the June 1 notice. In 

short, the process of issuing notices is 

shortened in the final rules by providing 

one, comprehensive opportunity to 

submit objections to the June 1 and 

August 1 notices, rather than two 

separate opportunities, one for each 

notice. 

Also in contrast with the proposed 

rules, the deadlines for issuance of 

notices of data availability for 

implementation of the assurance 

provisions are made uniform under the 

final rules for all of the Transport Rule 

trading programs. EPA is taking this 

approach for the same reasons that the 

deadlines for issuance of notices of data 

availability for new unit set-aside 

allocations are made uniform for all of 

these trading programs. 

Fourth, the owners and operators 

identified in the October 1 notice of data 

availability as being required to 

surrender allowances under the 

assurance provisions must transfer, by 

November 1, to the assurance account 

created by the Administrator for such 

owners and operators the amount of 

allowances (usable for compliance) that 

the Administrator determined in the 

October 1 notice of data availability. 

Where the October 1 notice indicates 

that a specified surrender amount is 

owed by a group of two or more owners 

and operators, all the group members 

are liable for the surrender amount, and 

it is up to the owners and operators in 

the group to decide who will actually 

surrender allowances. This is analogous 

to the situation where a group of two or 

more owners and operators of covered 

units at a source is required to hold 

allowances covering the unit’s 

emissions and therefore the group of 

owners and operators is liable. See 58 

FR 3590, 3599 (January 11, 1993) 

(discussing liability of owners and 

operators under allowance-holding 

requirements of the Acid Rain Program). 

EPA believes that the approach of 

making the owners and operators 

responsible for deciding which of them 

will actually surrender the necessary 

allowances under the assurance 

provisions is reasonable because the 

identity of who is an owner or operator 

(particularly who is an owner) of a unit 

or source and the percentage of an 

owner’s share can change during the 

year and this information is available to 

the owners and operators on an ongoing 


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basis, and not to EPA unless EPA were 

to impose new requirements for 

reporting this information. Further, EPA 

believes that it is reasonable to leave to 

private agreements the establishment of 

procedures for determining when, and 

under what conditions, specific owners 

and operators will provide the 

allowances for surrender. Owners and 

operators already make these types of 

determinations with regard to the 

surrender requirements in meeting the 

emissions limitations and any excess 

emission penalties. 

As part of implementing the commondesignated-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 and sources with a common 

designated representative in each state 

where the assurance provisions are 

triggered. Because the final rules require 

owners and operators to transfer 

surrendered allowances to the 

appropriate assurance account (rather 

than requiring the Administrator to 

deduct from accounts established by the 

owners), there is no need for the 

proposed rule provisions concerning 

identification of which allowances are 

to be deducted and first-in, first-out 

deduction in the absence of such 

identification. 

The final rules provide that, in 

general, the surrender amounts 

specified in the October 1 notice for 

owners and operators are final and will 

not be revised even if the underlying 

data (e.g., emission data) used in the 

calculations underlying the October 1 

notice are subsequently revised. 

However, the final rules set forth 

limited exceptions to this: Where such 

data are revised as a result of a decision 

in or settlement of litigation concerning 

the data on appeal. EPA believes that 

the limitation on revisions of the 

surrender amounts specified in the 

October 1 notice are necessary to 

provide some certainty to owners and 

operators and avoid the potential for 

multiple changes in owners’ and 

operators’ required surrender amounts. 

Because the surrender amount for each 

group of owners and operators of units 

and sources with a common designated 

representative in a state is calculated 

using emission data from all of the 

covered units in that state, each change 

in one or a few units’ emission data that 

might occur after issuance of the 

October 1 notice could otherwise 

change the calculated surrender 

amounts for all or many groups in the 

state. For the limited exceptions where 

the final rules provide that the 

surrender amounts specified in the 

August 1 notice may be revised, the 

final rules require the Administrator to 

set a new surrender deadline for any 

additional surrender required and to 

transfer allowances back out of the 

assurance account involved for any 

reduced surrender requirement, as 

appropriate. 

Under the final rules (as under the 

proposed rules), it is not a violation of 

the CAA for total state covered-unit 

emissions to exceed the state trading 

budget with the variability limit or for 

a group of owners and operators to 

become subject to the allowance 

surrender requirement under the 

assurance provisions. However, the 

failure of any group of owners and 

operators to surrender the required 

amount of allowances in the assurance 

account created for such owners and 

operators violates the CAA and is 

subject to discretionary penalties, with 

each required allowance that was not 

surrendered and each day of the control 

period involved constituting a violation. 

(v) §§ 97.426 Through 97.428, 97.526 

Through 97.528, 97.626 Through 

97.628, and 97.726 Through 97.728— 

Miscellaneous Provisions 

These sections in the final rules (as in 

the proposed rules) include provisions 

allowing banking of the allowances 

issued in the Transport Rule trading 

programs, i.e., the retention of unused 

Transport Rule allowances allocated for 

a given control period for use or trading 

in a later control period. While this can 

potentially cause emissions from 

sources in some states in some control 

periods to be greater than the 

allowances allocated for those control 

periods, the assurance provisions limit 

such emissions in a way that ensures 

that each state’s significant contribution 

to nonattainment and interference with 

maintenance that EPA has identified in 

this action will be eliminated. 

These sections also include 

provisions stating that the 

Administrator can, at his or her 

discretion and on his or her own 

motion, correct any type of error that he 

or she finds in an account in the 

Allowance Management System. In 

addition, the Administrator can review 

any submission under the Transport 

Rule trading programs, make 

adjustments to the information in the 

submission, and deduct or transfer 

allowances based on such adjusted 

information. 

(5) Emissions Monitoring, 

Recordkeeping, and Reporting 

Sections 97.430 through 97.435, 

97.530 through 97.535, 97.630 through 

97.635, and 97.730 through 97.735 

establish emissions monitoring, 

recordkeeping, and reporting 

requirements for Transport Rule units. 

These provisions reference the relevant 

sections of Part 75 (40 CFR part 75), 

where the specific procedures and 

requirements for monitoring and 

reporting NOX and SO2 mass emissions 

are set forth. The provisions in the final 

rules are virtually the same as the 

monitoring, recordkeeping, and 

reporting requirements in the proposed 

rules and under previous EPAadministered 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 require electronic 

submission, to the Administrator and in 

a format prescribed by the 

Administrator, of a quarterly emissions 

report. 

The final rules include revised 

language in §§ 97.430(b)(3), 97.530(b)(3), 

97.630(b)(3), and 97.730(b)(3) that 

incorporates by reference, and thereby 

applies to units in the Transport Rule 

trading programs, clarification that EPA 

recently adopted in § 75.4(e) of Part 75 

(for Acid Rain Program units) 


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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 

The projected impacts of this final 

rule as presented throughout the 

preamble do not reflect minor technical 

corrections to SO2 budgets in three 

states (KY, MI, and NY) made after the 

impact analyses were conducted. These 

projections also assumed preliminary 

variability limits that were smaller than 

the variability limits finalized in this 

rule. EPA conducted sensitivity analysis 

confirming that these differences do not 

meaningfully alter any of the Agency’s 

findings or conclusions based on the 

projected cost, benefit, and air quality 

impacts presented for the final 

Transport Rule. The results of this 

sensitivity analysis are presented in 

Appendix F in the final Transport Rule 

RIA. 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

Under EO 12866 (58 FR 51735, 

October 4, 1993), this action is an 

‘‘economically significant regulatory 

action’’ because it is likely to have an 

annual effect on the economy of $100 

million or more or adversely affect in a 

material way the economy, a sector of 

the economy, productivity, competition, 

jobs, the environment, public health or 

safety, or state, local, or tribal 

governments or communities. 

Accordingly, EPA submitted this 

action to the OMB for review under EO 

12866 and EO 13563 (76 FR 3821, 

January 21, 2011) and any changes in 

response to OMB recommendations 

have been documented in the docket for 

this action. In addition, EPA prepared 

an analysis of the potential costs and 

benefits for this action. This analysis is 

contained in the Regulatory Impact 

Analysis (RIA) for this action. For more 

information on the costs and benefits for 

this rule, please refer to Table VIII.C–3 

of this preamble. 

When estimating the human health 

benefits and compliance costs in Table 

VIII.C–3 of this preamble, EPA applied 

methods and assumptions consistent 

with the state-of-the-science for human 

health impact assessment, economics, 

and air quality analysis. EPA applied its 

best professional judgment in 

performing this analysis and believes 

that these estimates provide a 

reasonable indication of the expected 

benefits and costs to the nation of this 

rulemaking. The RIA available in the 

docket describes in detail the empirical 

basis for EPA’s assumptions and 

characterizes the various sources of 

uncertainties affecting the estimates 

below. In doing what is laid out above 

in this paragraph, EPA adheres to EO 

13563, ‘‘Improving Regulation and 

Regulatory Review,’’ (76 FR 3,821, 

January 21, 2011), which is a 

supplement to EO 12866. 

In addition to estimating costs and 

benefits, EO 13563 focuses on the 

importance of a ‘‘regulatory system 

[that] * * * promote[s] predictability 

and reduce[s] uncertainty’’ and that 

‘‘identify[ies] and use[s] the best, most 

innovative, and least burdensome tools 

for achieving regulatory ends.’’ EO 

13563 also states that ‘‘[i]n developing 

regulatory actions and identifying 

appropriate approaches, each agency 

shall attempt to promote such 

coordination, simplification, and 

harmonization. Each agency shall also 

seek to identify, as appropriate, means 

to achieve regulatory goals that are 

designed to promote innovation.’’ We 

recognize that the utility sector has 

compliance obligations related to 

multiple environmental statutes 

authorizing regulatory action, including 

this rule’s requirements to reduce 

interstate transport of harmful ozone 

and fine particles and their precursors, 

as well as other rules’ requirements to 

reduce air toxic emissions, to reduce 

greenhouse gas emissions, to safely 

manage coal combustion wastes, and to 

protect aquatic wildlife from water 

intake procedures. In the wake of 

promulgating this final rule, EPA 

recognizes that moving forward the 

agency needs to approach these 

rulemakings in ways that allow the 

industry to make practical investment 

decisions that minimize costs in 

complying with all of the final rules, 

while still securing the fundamentally 

important environmental and public 

health benefits that led Congress to 

enact those authorities in the first place. 

At the same time, EPA notes that the 

flexibility inherent in the allowancetrading mechanism included in this rule 

affords utilities themselves a degree of 

latitude to determine how best to 

integrate compliance with the emission 

reduction requirements of this rule and 

those of the other rules. 

The final rule will also reduce 

emissions of directly emitted PM and 

ozone precursors, and estimates of the 

PM2.5-related benefits of these air 

quality improvements may be found in 

Tables VIII.C–1 and VIII.C–2 of this 

preamble. When characterizing 

uncertainty in the PM-mortality 

relationship, EPA has historically 

presented a sensitivity analysis applying 

alternate assumed thresholds in the PM 

concentration-response relationship. In 

its synthesis of the current state of the 

PM science, EPA’s 2009 Integrated 

Science Assessment for Particulate 

Matter concluded that a no-threshold 

log-linear model most adequately 

portrays the PM-mortality 

concentration-response relationship. In 

the RIA accompanying this rulemaking, 

rather than segmenting out impacts 

predicted to be associated levels above 

and below a ‘‘bright line’’ threshold, 

EPA includes a ‘‘lowest measured level’’ 

(LML) analysis that illustrates the 

increasing uncertainty that characterizes 

exposure attributed to levels of PM2.5

below the LML of each epidemiological 

study used to estimate PM2.5-related 

premature death. Figures provided in 

the RIA show the distribution of 

baseline exposure to PM2.5, as well as 

the lowest air quality levels measured in 

each of the epidemiology cohort studies. 

This information provides a context for 

considering the likely portion of PMrelated 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 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, 


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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 compliance with all 

such requirements, such as the 

requirement for industry to monitor, 

record, and report emission data to EPA. 

The ICR for the final Transport Rule 

has been submitted for approval by 

OMB under the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq., and the 

information collection requirements it 

documents are not enforceable until 

such approval has been granted. An ICR 

was also submitted to OMB in support 

of the proposed Transport Rule; no 

adverse comment was received by EPA 

on either the information collection 

requirements or their associated cost 

estimates as described in that document. 

The costs associated with the 

information collection requirements of 

the Transport Rule include start-up and 

capital costs for units newly affected by 

an emission trading program, or whose 

reporting status has changed (e.g., from 

ozone-season-only to annual reporting), 

as well as the additional operation and 

maintenance costs for Transport Ruleaffected 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 emission limits and other 

requirements. Such records and reports 

are also helpful to EPA and states in 

both identifying affected facilities that 

may not be in compliance with 

applicable requirements 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 programs 

are approximately $26 million annually 

in 2010 dollars. The total number of 

burden hours associated with the 

recordkeeping and reporting burden to 

Transport Rule-affected sources in states 

participating in the Transport Rule 

trading programs is approximately 

185,000 hours annually. These estimates 

include the annualized cost of installing 

and operating appropriate SO2 and NOX

emission monitoring equipment to 

measure and report the total emissions 

of these pollutants from affected EGUs 

(serving generators greater than 25 MW). 

The burden to state and local air 

agencies, as documented in the ICR, 

includes any necessary SIP revisions, 

performance of monitor certifications, 

and fulfillment of audit responsibilities. 

Burden is defined at 5 CFR 1320.3(b). 

The amendments do not require any 

notifications or reports beyond those 

required by the General Provisions. The 

recordkeeping requirements require 

only the specific information needed to 

determine compliance, which is 

specifically authorized by CAA section 

114 (42 U.S.C. 7414). All information 

submitted to EPA for which a claim of 

confidentiality is made will be 

safeguarded according to EPA policies 

in 40 CFR part 2, subpart B, 

Confidentiality of Business Information. 

An Agency may not conduct or sponsor, 

and a person is not required to respond 

to a collection of information unless it 

displays a currently valid OMB control 

number. The OMB control numbers for 

EPA’s regulations in 40 CFR are listed 

in 40 CFR part 9. When this ICR is 

approved by OMB, the Agency will 

publish a technical amendment to 40 

CFR part 9 in the Federal Register to 

display the OMB control number for the 

approved information collection 

requirements contained in this final 

rule. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of this final rule on small entities, small 

entity is defined as: 

(1) A small business as defined by the 

Small Business Administration’s (SBA) 

regulations at 13 CFR 121.201. For the 

electric power generation industry, the 

small business size standard is an 

ultimate parent entity defined as having 

a total electric output of 4 million 

megawatt-hours (MWh) or less in the 

previous fiscal year. 

(2) A small governmental jurisdiction 

that is a government of a city, county, 

town, school district or special district 

with a population of less than 50,000; 

and 

(3) A small organization that is any 

not-for-profit enterprise which is 

independently owned and operated and 

is not dominant in its field. 

TABLE XII.C–1—POTENTIALLY REGULATED CATEGORIES AND ENTITIES a

Category NAICS code b Examples of potentially regulated entities 

Industry ............................................... 221112 Fossil-fuel-fired electric utility steam generating units. 

Federal Government .......................... c 221112 Fossil-fuel-fired electric utility steam generating units owned by the federal government. 

State/Local Government .................... 2c 21112 Fossil-fuel-fired electric utility steam generating units owned by municipalities. 

Tribal Government ............................. 921150 Fossil-fuel-fired electric utility steam generating units in Indian Country. 

a Include NAICS categories for source categories that own and operate electric generating units only. 

b North American Industry Classification System. 

cFederal, state, or local government-owned and operated establishments are classified according to the activity in which they are engaged. 


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EPA used Velocity Suite’s Ventyx 

data as a basis for identifying plant 

ownership and compiling the list of 

potentially affected small entities. For 

plants burning fossil fuel as the primary 

fuel, plant-level boiler and generator 

capacity, heat input, generation, and 

emission data were aggregated by owner 

and then parent company. For 

cooperatives, investor-owned utilities, 

and subdivisions that generate less than 

4 billion kWh of electricity annually but 

may be part of a large entity, additional 

research on power sales, operating 

revenues, and other business activities 

was performed to make a final 

determination regarding size. 

After considering the economic 

impacts of this final rule on small 

entities, EPA certifies that this action 

will not have a significant economic 

impact on a substantial number of small 

entities (No SISNOSE). This 

certification is based on the economic 

impact of this final rule to all affected 

small entities across all industries 

affected. EPA assessed the potential 

impact of this action on small entities 

and found that there are about 660 

potentially affected small units (i.e., 

greater than 25 MW and generating less 

than 4 million MWh) out of 3,625 

existing units in the Transport Rule 

states. The majority of these EGUs are 

owned by entities that do not meet the 

small entity definition. The remaining 

271 of the 660 EGUs are owned by 108 

potentially affected small entities and 

are likely to be affected by this rule. 

EPA estimates that 24 of the 108 

identified small entities will have 

annualized costs greater than 1 percent 

of their revenues, and the other 84 are 

projected to incur costs less than 1 

percent of revenues. Eleven small 

entities out of 108—approximately 10 

percent—are estimated to have 

annualized costs greater than 3 percent 

of their revenues. EPA has lessened the 

impacts for small entities by excluding 

all units smaller than 25 MWe. This 

exclusion, in addition to the exemptions 

for cogeneration units and solid waste 

incineration units, eliminates the 

burden of higher costs for a substantial 

number of small entities located in the 

Transport Rule states. 

While the total number of small 

entities has increased compared to the 

proposal as a result of updated 

modeling and changes in geographic 

coverage, the number with compliance 

costs greater than 1 percent of revenues 

has fallen, and both the number and 

percentage of significantly impacted 

small entities (costs greater than 3 

percent of revenues) are lower—now 10 

percent compared to 17 percent in the 

proposal. The share of significantly 

impacted small entities has fallen 

because of updated modeling and the 

change in the allowance allocation 

methodology (see section VII.D for more 

information about allowance 

allocations). 

Although this final rule will not have 

a significant economic impact on a 

substantial number of small entities, 

EPA nonetheless has tried to reduce the 

impact of this rule on small entities. In 

EPA’s modeling, most of the cost 

impacts for these small entities and 

their associated units are driven by 

lower electricity generation relative to 

the base case. Specifically, two small 

units reduce their generation by 

significant amounts, driving the bulk of 

the costs for all small entities. Excluding 

these two units, one of the main drivers 

of small entity impacts is higher fuel 

costs, which the affected units would 

incur irrespective of whether they had 

to comply with this rule. In addition, 

EPA’s decision to exclude units smaller 

than 25 MWe has already significantly 

reduced the burden on approximately 

390 small entities. 

For more information on the small 

entity impacts associated with the final 

rule, refer to the Regulatory Impact 

Analysis for this final rule, which can 

be found in the docket for this rule and 

on the Web site http://www.epa.gov/ 

airtransport. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), 2 U.S.C. 

1531–1538, requires federal agencies, 

unless otherwise prohibited by law, to 

assess the effects of their regulatory 

actions on state, local, and tribal 

governments, and the private sector. 

This rule contains a federal mandate 

that may result in expenditures of $100 

million or more for state, local, and 

tribal governments, in the aggregate, or 

the private sector in any 1 year. 

Accordingly, EPA has prepared, under 

section 202 of the UMRA, a written 

statement which is summarized later. 

Consistent with the intergovernmental 

consultation provisions of section 204 of 

the UMRA, EPA held consultations with 

the governmental entities affected by 

this rule during the proposal phase. 

Subsequently, EPA sent a letter to the 

ten Representative National 

Organizations to draw their attention to 

the Transport Rule Notice of Data 

Availability (NODA) on allowance 

allocations and other related matters 

and to invite their comments. During 

the NODA comment period, EPA 

participated in informational calls with 

the 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 setaside provision to this final rule 

specifically for EGUs constructed in 

Indian country to ensure allowances are 

available to tribes and tribal sovereignty 

is respected. 

Consistent with section 205, EPA 

identified and considered a reasonable 

number of regulatory alternatives. In the 

proposal, EPA included three remedy 

options that it considered when 

developing this final rule: (1) The 

preferred remedy trading programs, (2) 

State Budgets/Intrastate Trading, and (3) 

Direct Controls. Moreover, section 205 

allows EPA to adopt an alternative other 

than the least costly, most cost-effective, 

or least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. 

EPA examined the potential economic 

impacts on state- and municipalityowned 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 subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. 


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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 NODA 

on allowance allocations and other 

related matters and to invite their 

comments. Following that letter in early 

2011, EPA participated in informational 

calls with the Environmental Council of 

the States (ECOS) and the National 

Governors Association to provide 

information about the NODA directly to 

state and local officials. There were no 

new concerns raised during these 

informational calls. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Under Executive Order 13175 (65 FR 

67249, November 9, 2000), EPA may not 

issue a regulation that has tribal 

implications, that imposes substantial 

direct compliance costs, and that is not 

required by statute, unless the federal 

government provides the funds 

necessary to pay the direct compliance 

costs incurred by tribal governments, or 

EPA consults with tribal officials early 

in the process of developing the 

proposed regulation and develops a 

tribal summary impact statement. 

EPA has concluded that this action 

may have tribal implications if a new 

unit covered by the rule is built in 

Indian country. Additionally, tribes 

have a vested interest in how this final 

rule affects their air quality. However, it 

will neither impose substantial direct 

compliance costs on tribal governments, 

nor preempt tribal law. EPA consulted 

with tribal officials during the process 

of finalizing this regulation to permit 

them to have meaningful and timely 

input into its development. 

EPA received comments on the 

proposed Transport Rule that the 

Agency did not properly conduct 

consultation during the proposal phase 

of the rulemaking process. In response 

to these comments, EPA sent a letter to 

all federally-recognized tribes in the 

country offering consultation. In 

addition, several commenters also noted 

that the Agency did not adequately 

consider opportunities for tribes to enter 

into any of the trading programs and, in 

particular, did not consider sovereignty 

issues when addressing how to 

distribute allowances to potential new 

units in Indian country. On January 7, 

2011, EPA issued a NODA requesting 

comment on allocations for new units in 

Indian country, among other topics. 

The Agency held a consultation call 

with three tribes on January 21, 2011. A 

follow-up call was held on February 4, 

2011 with two of the three original 

tribes plus 13 additional tribes, as well 

as representatives from the National 

Tribal Air Association. In all ten tribes 

participated in these calls as 

consultation and six participated as 

information-sharing. EPA considered 

the additional input from these 

consultation and information calls, in 

conjunction with the public comments, 

in the development of the final rule. 

Accordingly, EPA created an Indian 

country new unit set-aside to 

specifically address tribes’ concerns 

regarding the protection of tribal 

sovereignty in the distribution of 

allowances for new units in Indian 

country. See section VII.D.2 of this 

preamble for details on the Indian 

country set-aside for new units 

constructed in Indian country within 

states covered by the Transport Rule. 

As required by section 7(a) of the 

Executive Order, EPA’s Tribal 

Consultation Official has certified that 

the requirements of the Executive Order 

have been met in a meaningful and 

timely manner. A copy of the 

certification is included in the docket 

for this action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

and Safety Risks 

Executive Order 13045 (62 FR 19,885, 

April 23, 1997) applies to any rule that: 

(1) Is determined to be ‘‘economically 

significant’’ as defined under EO 12866, 

and (2) concerns an environmental 

health or safety risk that EPA has reason 

to believe may have a disproportionate 

effect on children. If the regulatory 

action meets both criteria, the Agency 

must evaluate the environmental health 

or safety effects of this planned rule on 

children, and explain why this planned 

regulation is preferable to other 

potentially effective and reasonably 

feasible alternatives considered by the 

Agency. 

This action is not subject to Executive 

Order 13045 because it does not involve 

decisions on environmental health or 

safety risks that may disproportionately 

affect children. EPA believes that the 

emission reductions from the strategies 

in this rule will further improve air 

quality and will further improve 

children’s health. Analyses by EPA that 

show how the emission reductions from 

the strategies in this rule will further 

improve air quality and children’s 

health can be found in the RIA for this 

rule. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

Executive Order 13211 (66 FR 28355, 

May 22, 2001) provides that agencies 

shall prepare and submit to the 

Administrator of the Office of 

Regulatory Affairs, OMB, a Statement of 

Energy Effects for certain actions 

identified as ‘‘significant energy 

actions.’’ Section 4(b) of Executive 

Order 13211 defines ‘‘significant energy 

action’’ as ‘‘any action by an agency 

(normally published in the Federal 

Register) that promulgates or is 

expected to lead to the promulgation of 

a final rule or regulation, including 

notices of inquiry, advance notices of 

proposed rulemaking, and notices of 

proposed rulemaking: (1)(i) That is a 

significant regulatory action under 

Executive Order 12866 or any successor 

order, and (ii) is likely to have a 

significant adverse effect on the supply, 

distribution, or use of energy; or (2) that 

is designated by the Administrator of 

the Office of Information and Regulatory 

Affairs as a significant energy action.’’ 

This rule is a significant regulatory 

action under Executive Order 12866, 

and this 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 infrequentlyused generating units dispersed 

throughout the area affected by the rule. 

If current forecasts of either natural gas 

prices or electricity demand were 

revised in the future to be higher, that 

would create a greater incentive to keep 

these units operational. 

EPA estimates that average retail 

electricity prices could increase in the 


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contiguous U.S. by about 1.7 percent in 

2012 and 0.8 percent in 2014. This is 

generally less of an increase than often 

occurs with fluctuating fuel prices and 

other market factors. Related to this, 

EPA projects limited impacts on coal 

and gas prices. The average delivered 

coal price decreases by about 1.4 

percent in 2012 and 0.9 percent in 2014 

relative to the base case as a result of 

decreased coal demand and shifts in the 

type of coal demanded. EPA also 

projects that the electric power sectordelivered natural gas price will increase 

by about 0.3 percent over the 2012–2030 

timeframe and that natural gas use for 

electricity generation will increase by 

approximately 200 billion cubic feet 

(BCF) by 2014. These impacts are well 

within the range of price variability that 

is regularly experienced in natural gas 

markets. Finally, under the Transport 

Rule, EPA projects that coal production 

for use by the power sector will increase 

above 2009 levels by 21 million tons in 

2012 and a further 14 million tons in 

2014, as opposed to 30 million tons in 

2012 and a further 26 million tons in 

2014 without the Transport Rule in 

place. The Transport Rule is not 

projected to impact production of coal 

for uses outside the power sector (e.g., 

export, industrial sources), which 

represent approximately 6 percent of 

total coal production in 2009. EPA does 

not believe that this rule will have any 

other impacts (e.g., on oil markets) that 

exceed the significance criteria. 

EPA believes that a number of 

features of the rulemaking serve to 

reduce its impact on energy supply. 

First, the trading component of the 

Transport Rule provides flexibility to 

the power sector and enables industry to 

comply with the emission reduction 

requirements in the most cost-effective 

manner compared to the alternative 

remedy approaches on which EPA took 

comment in the proposal, thus 

minimizing overall costs and the 

ultimate impact on energy supply. 

Second, the more stringent budgets for 

SO2 are set in two phases, providing 

adequate time for EGUs to install 

pollution controls. In addition, both the 

operational flexibility of trading and the 

ability to bank allowances for future 

years helps industry plan for and ensure 

reliability in the electrical system. 

For more details concerning energy 

impacts, see the RIA for the Transport 

Rule. 

I. National Technology Transfer 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104– 

113, 12(d) (15 U.S.C. 272 note) directs 

EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. This rule will 

require all sources to meet the 

applicable monitoring requirements of 

40 CFR part 75. Part 75 already 

incorporates a number of voluntary 

consensus standards. Consistent with 

the Agency’s Performance Based 

Measurement System (PBMS), Part 75 

sets forth performance criteria that 

allow the use of alternative methods to 

the ones set forth in Part 75. The PBMS 

approach is intended to be more flexible 

and cost effective for the regulated 

community; it is also intended to 

encourage innovation in analytical 

technology and improved data quality. 

At this time, EPA is not recommending 

any revisions to Part 75; however, EPA 

periodically revises the test procedures 

set forth in Part 75. When EPA revises 

the test procedures set forth in Part 75 

in the future, EPA will address the use 

of any new voluntary consensus 

standards that are equivalent. Currently, 

even if a test procedure is not set forth 

in Part 75, EPA is not precluding the use 

of any method, whether it constitutes a 

voluntary consensus standard or not, as 

long as it meets the performance criteria 

specified; however, any alternative 

methods must be approved through the 

petition process under 40 CFR 75.66 

before they are used. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order (EO) 12898 (59 FR 

7629 (Feb. 16, 1994)) establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority, lowincome, and Tribal populations in the 

United States. During development of 

this final Transport Rule, EPA 

considered its impacts on low-income, 

minority, and tribal communities in 

several ways and provided multiple 

opportunities for these communities to 

meaningfully participate in the 

rulemaking process. The proposed 

Transport Rule included an analysis of 

its effects on these populations; this 

section describes additional analysis 

conducted since proposal, EPA’s 

responses to key comments on 

environmental justice issues raised 

during the comment period, and the 

public outreach and comment 

opportunities for this rule. 

A summary of the history, statutory 

authority, and key components of this 

final Transport Rule are described in the 

Executive Summary (section III) of this 

preamble. That section also summarizes 

a supplemental notice of proposed 

rulemaking (SNPR) that EPA is 

publishing to correct a procedural flaw 

by providing an opportunity for public 

comment on issues that arose from new 

analyses with updated inventories and 

modeling platforms. 

Briefly, this final Transport Rule will 

reduce emissions of SO2 and NOX in 23 

eastern and central states in 2012 and 

2014 that contribute to annual and/or 

24-hour PM2.5 nonattainment or 

interfere with maintenance in 

downwind states. It will also reduce 

emissions of ozone-season NOX in 20 

eastern and central states in 2012 and 

2014 that contribute to the 1997 ozone 

nonattainment or interfere with 

maintenance in downwind states. This 

rule is replacing an earlier rule (the 

2005 Clean Air Interstate Rule (CAIR)) 

that was first vacated and then 

remanded to EPA by the U.S. Court of 

Appeals for the District of Columbia 

Circuit in 2008. 

1. Consideration of Environmental 

Justice in the Transport Rule 

Development Process and Response to 

Comments 

The effects of this final Transport 

Rule on the most highly exposed 

populations were integral in its 

development. This rule uses EPA’s 

authority in CAA section 110(a)(2)(d) to 

reduce sulfur dioxide (SO2) and 

(nitrogen oxides) NOX pollution that 

significantly contributes to downwind 

PM2.5 and ozone nonattainment or 

maintenance areas. As a result, the rule 

will reduce exposures to ozone and 

PM2.5 in the most-contaminated areas 

(i.e., areas that are not meeting the 1997 

ozone and 1997 and 2006 PM2.5

National Ambient Air Quality Standards 

(NAAQS)). In addition, the rule 

separately identifies both nonattainment 

areas and maintenance areas 

(maintenance areas are those that are 

projected to meet the NAAQS but that, 

based on past data, are in danger of 


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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 healthbased standards in the future. 

This final Transport Rule implements 

these emission reductions using an 

emission trading mechanism with 

assurance provisions for power plants. 

EPA recognizes that many 

environmental justice communities 

have voiced concerns in the past about 

emission trading and the potential for 

any emission increases in any location. 

EPA also received several comments on 

this issue during the comment period 

for the proposed Transport Rule. As 

described below, we believe this final 

rule addresses the concerns raised on 

this issue during the comment period. 

PM2.5 and ozone pollution from power 

plants have both local and regional 

components: Part of the pollution in a 

given location—even in locations near 

emission sources—is due to emissions 

from nearby sources and part is due to 

emissions that travel hundreds of miles 

and mix with emissions from other 

sources. Therefore, in many instances 

the exact location of the upwind 

reductions does not affect the levels of 

air pollution downwind. 

It is important to note that the section 

of the Clean Air Act providing authority 

for this rule, section 110(a)(2)(D), unlike 

some other provisions, does not dictate 

levels of control for particular facilities. 

As at least one commenter noted, none 

of the alternatives put forward by EPA 

in the proposed rule could have ensured 

no emission increases at any facility. 

Under the direct control alternative, the 

emission rate for each facility would 

have been limited but each facility 

could emit more by increasing their 

power output in order to meet 

electricity reliability or other goals. 

Under the intrastate trading option, 

sources could not trade allowances with 

sources in other states but individual 

facilities within each state could have 

increased their emissions as long as 

another facility in the state had 

decreased theirs at some time. 

The final Transport Rule allows 

sources to trade allowances with other 

sources in the same or different states 

while firmly constraining any emissions 

shifting that may occur by requiring a 

strict emission ceiling in each state (the 

budget plus variability limit). In 

addition, assurance provisions in the 

rule outline the allowance surrender 

penalties for failing to meet the budget 

plus variability limits; there are 

additional allowance penalties as well 

as financial penalties for failing to hold 

an adequate number of allowances to 

cover emissions. This approach 

eliminates emissions in each state that 

significantly contribute to downwind 

nonattainment or maintenance areas, 

while allowing power companies to 

adjust generation as needed and ensure 

that the country’s electricity needs will 

continue to be met. EPA maintains that 

the existence of these assurance 

provisions, including the penalties 

imposed when triggered, will ensure 

that state emissions will stay below the 

level of the budget plus variability limit. 

In addition, all sources must hold 

enough allowances to cover their 

emissions. Therefore, if a source emits 

more than its allocation in a given year, 

either another source must have used 

less than its allocation and be willing to 

sell some of its excess allowances, or the 

source itself had emitted less than its 

allocation in one or more previous years 

(i.e., banked allowances for future use). 

In summary, the final remedy 

addresses commenter concerns about 

localized hot spots and reduces ambient 

concentrations of pollution where they 

are most needed by sensitive and 

vulnerable populations by: Considering 

the science of ozone and PM2.5 transport 

to set strict state budgets to eliminate 

significant contributions to ozone and 

PM2.5 nonattainment and maintenance 

(i.e., the most polluted) areas; 

implementing air quality-assured 

trading; requiring any emissions above 

the level of the allocations to be offset 

by emission decreases; and imposing 

strict penalties for sources that 

contribute to a state’s exceedance of its 

budget plus variability limit. In 

addition, it is important to note that 

nothing in this final rule allows sources 

to violate their title V permit or any 

other federal, state, or local emissions or 

air quality requirements. 

EPA received comments from several 

tribal commenters regarding the lack of 

allocations in the proposal to new units 

in Indian Country. EPA responded to 

these comments by changing the 

allocation approach in the final rule to 

create Indian country new unit setasides. In order to protect tribal 

sovereignty, these set-asides will be 

managed and distributed by the federal 

government regardless of whether the 

Transport Rule in the adjoining or 

surrounding state is implemented 

through a FIP or SIP. While there are no 

existing power plants in Indian country 

covered by this Transport Rule, the 

Indian country set-asides will ensure 

that any future new units built in Indian 

country will be able to get the necessary 

allowances. A full discussion of the 

Indian country new unit set-asides can 

be found in section VII.D.2. 

EPA also received several comments 

during the comment period from 

individuals and groups requesting 

additional emission reductions to 

further protect sensitive and vulnerable 

communities. While EPA has adjusted 

the emission requirements somewhat in 

the final rule to accommodate revised 

data and updated modeling results, we 

are finalizing emission reductions very 

similar to the level in the proposal. This 

is because EPA believes that the 

emission reductions required by this 

final rule are appropriate to meet the 

statutory requirements of CAA section 

110(a)(2)(d) and respond to the concerns 

raised by the Court’s opinion in North 

Carolina that remanded CAIR to the 

Agency in 2008. 

In addition, it is important to note 

that CAA section 110(a)(2)(d), which 

addresses transport of criteria pollutants 

between states, is only one of many 

provisions of the CAA that provide EPA, 

states, and local governments with 

authorities to reduce exposure to ozone 

and PM2.5 in communities. These legal 

authorities work together to reduce 

exposure to these pollutants in 

communities, including for minority, 

low-income, and tribal populations, and 

provide substantial health benefits to 

both the general public and sensitive 

sub-populations. 

For example, the recently-proposed 

Mercury and Air Toxics Standards 

(MATS) would also result in significant 

reductions in SO2 emissions and 

provide significant health and 

environmental benefits nationwide. 

This and other actions described in 

section III will have substantial and 

long-term effects on both the U.S. power 

industry and on communities currently 

breathing dirty air. Therefore, we 

anticipate significant interest in many, if 

not most, of these actions from 

environmental justice communities, 

among many others. EPA will continue 

to provide multiple opportunities for 

comment on these actions, similar to the 

opportunities provided during the 

comment process for this rule, detailed 

at the end of this section. We encourage 

environmental justice communities to 

review and comment on these actions. 

2. Potential Environmental and Public 

Health Impacts Among Populations 

Susceptible or Vulnerable to Air 

Pollution 

EPA expects that this final rule will 

provide significant health and 

environmental benefits to, among 

others, people with asthma, people with 

heart disease, and people living in 

ozone or PM2.5 nonattainment areas. 

EPA’s analysis of the effects of this rule, 

including information on air quality 

changes and the resulting health 

benefits, is presented both in section 


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VIII of this preamble and in the 

Regulatory Impact Analysis (RIA) for 

this rule. These documents can be 

accessed through the rule docket No. 

EPA–HQ–OAR–2009–0491 and from the 

main EPA webpage for the rule at 

http://www.epa.gov/airtransport. 

EPA considered several aspects of the 

effects of the Transport Rule on 

minority, low-income, and tribal 

populations. These included: amount of 

emission reductions and where they 

take place (including any potential for 

areas of increased emissions); the 

changes in ambient concentrations 

across the affected area; the estimated 

health benefits; and how the estimated 

health benefits are distributed among 

different populations, including those 

susceptible and vulnerable to air 

pollution health impacts. 

a. Emission Reductions 

EPA’s emission modeling data 

indicate that implementation of the 

Transport Rule will substantially reduce 

SO2 emissions from electric generating 

units (EGUs). As noted in section III, 

emissions in states covered by the 

Transport Rule will decrease by 6.4 

million tons (73 percent) in 2014 

compared to 2005 (the year the Clean 

Air Interstate Rule was finalized). 

Emissions are also projected to decrease 

when compared to the base case (the 

base case estimates emissions in 2014 in 

the absence of this rule or the Clean Air 

Interstate Rule it is replacing). EPA 

estimates that SO2 emissions in 2014 in 

covered states will be 3.9 million tons 

lower (62 percent lower) compared to 

the base case. 

EPA also assessed emission changes 

in states not covered by the Transport 

Rule. Emissions in the states not 

covered by the Transport Rule are also 

projected to decrease substantially 

compared to 2005 levels; in 2014 SO2

emissions are projected to be 

approximately 430,000 tons lower (30 

percent lower) than in 2005. 

As described in section VI.C, EPA’s 

modeling does project that some states 

not covered by any of the fine particle 

control programs in the final Transport 

Rule may experience increases of SO2

emissions greater than 5,000 tons 

compared to the base case. These states 

are Arkansas, Colorado, Louisiana, 

Montana, and Wyoming. These 

emission increases are the result of 

forecasted changes in operation of 

power plant units outside of the 

Transport Rule states due to the 

interconnected nature of the utility grid 

(i.e., shifts in generation of electricity to 

sources outside the Transport Rule 

states) or influence of the rule on the 

market for lower sulfur coal. For 

example, EPA projects that the rule will 

raise demand for lower sulfur coal in 

the states covered by the Transport Rule 

for PM2.5 (thereby raising its price), 

which may lead sources in states not 

covered for PM2.5 to choose highersulfur coals that increase SO2 emissions 

in those states. 

EPA is not requiring SO2 emission 

reductions in these states under this 

rule because our modeling indicates 

none of these states’ contributions 

would increase enough to cause them to 

meet or exceed the thresholds described 

in section V.D for either of the PM2.5

standards. EPA’s authority under CAA 

section 110(a)(2)(d) is limited to 

addressing this significant contribution 

to nonattainment and interference with 

maintenance. However, as noted above, 

EPA has recently proposed the Mercury 

and Air Toxics Standards that will 

apply nationwide and result in 

substantial additional SO2 emission 

reductions, including in states not 

covered by the Transport Rule. 

EPA’s emission modeling data 

indicates that ozone-season NOX

emissions from EGUs in states covered 

by the Transport Rule will be 

approximately 340,000 tons lower (36 

percent lower) in 2014 than they were 

in 2005. Emissions in states not covered 

by the Transport Rule are also expected 

to decrease somewhat (approximately 

82,000 tons or 25 percent). EPA’s 

modeling does project that two states 

(California and Pennsylvania) may 

experience increases of NOX emissions 

greater than 5,000 tons in 2014 

compared to 2005 levels. California is 

not covered by the Transport Rule; in 

Pennsylvania, 2005 was an unusually 

low-emitting year and sources are 

projected to increase their heat input 

slightly (usually meaning they are 

generating more power) after the rule 

takes effect. 

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. Ozoneseason NOX emissions in covered states 

are projected to decrease by 

approximately 74,000 tons (11 percent); 

ozone-season NOX emissions in nonTransport Rule states are projected to 

decrease by approximately 10,000 tons 

(4 percent). Both California and 

Pennsylvania are projected to have 

lower NOX emissions in 2014 under the 

Transport Rule as compared to the base 

case. In addition, EPA anticipates that 

additional upcoming actions, including 

likely additional interstate transport 

reductions to help states attain the 

upcoming new ozone NAAQS, will 

result in significant additional NOX

reductions in the future. 

b. Air Quality Improvements 

EPA assessed the air quality metrics 

(called ‘‘design values’’) for each 

NAAQS addressed in this rule: 24-hour 

PM2.5, annual PM2.5, and ozone. We 

then compared these metrics for the 

final rule to the same metrics in the 

recent past (2003–2007 average ambient 

air quality) and for the 2014 base case 

to assess improvements in air quality. 

EPA’s modeling indicates that there 

will be significant improvements in air 

quality as measured by the 24-hour 

PM2.5 standard. Throughout much of the 

eastern half of the U.S., 24-hour PM2.5

design values are projected to improve 

more than 10 μg/m3 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/m3 in a 

broad swath of states stretching from far 

southwestern New York through 

Pennsylvania, Ohio, West Virginia, 

Maryland, Indiana, southern Illinois, 

eastern Missouri, eastern Arkansas, 

Kentucky, Tennessee, northern 

Alabama, and northern Mississippi. 

Isolated areas of Virginia and northern 

New Jersey are also expected to see this 

level of improvement. Improvements of 

2–6 μg/m3 are projected in surrounding 

states stretching from New England and 

New York to Minnesota, Iowa, the far 

eastern edge of Nebraska, Missouri, 

eastern Kansas, Oklahoma, Texas, the 

Gulf of Mexico states, and the states 

bordering the Atlantic Ocean from 

Florida to New Hampshire. 

EPA modeling indicates that air 

quality as measured by the annual PM2.5

design value will also improve. 

Improvements range from 2 to over 4 

μg/m3 compared to the 2003–2007 

average levels throughout the eastern 

half of the U.S. Annual PM2.5 air quality 

with the Transport Rule is also 

projected to improve compared to the 

2014 base case levels. The largest 

improvements of up to 4 μg/m3 are 

projected to occur in northern West 

Virginia and a small area in 

northwestern Tennessee. Improvements 

of up to 3 μg/m3 are projected for 

portions of the Ohio River valley areas 

of southwestern Pennsylvania, Ohio, 

West Virginia, Kentucky, central 

Tennessee, and southern Indiana. 

Improvements of up to 2 μg/m3 are 

projected to take place in a ring of 

surrounding states including all or most 

of New York, Michigan, Indiana, 


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48350 Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations 

123Neighborhood of Residence and Incidence of 

Coronary Heart Disease Ana V. Diez Roux, M.D., 

PhD et al. N Engl J Med 2001; 345:99–106; July 12, 

2001. 

124Centers 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. 

125R. Nelson, Eds. National Institute of Medicine, 

2003. 

126 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. 

Illinois, Missouri, Arkansas, the far 

eastern edge of Oklahoma, the 

northeastern edge of Texas, Louisiana, 

Mississippi, Alabama, Georgia, South 

Carolina, North Carolina, Virginia, 

Maryland, Delaware, Pennsylvania, and 

New Jersey. Smaller improvements are 

projected in New England, Wisconsin, 

the Plains states, southeastern New 

Mexico, and Florida. 

EPA modeling indicates that ozone air 

quality will improve greatly (10–12 ppb 

or more) across much of the eastern U.S. 

between the average levels seen in 

2003–2007 and implementation of the 

Transport Rule. Most of the 

improvements take place in the base 

case; that is, they are the result of 

federal and state programs other than 

the Transport Rule. However, ozone air 

quality is projected to improve 

somewhat as a direct result of the 

Transport Rule. Improvements in ozone 

design values compared to the base case 

of more than 1 ppb are projected for 

portions of Florida, eastern Oklahoma, 

and areas along the upper reaches of the 

Ohio River. In addition, improvements 

in ozone design values of up to 1 ppb 

are projected over a wide area across the 

eastern U.S. from New England to Texas 

and north to Minnesota. Improvements 

are also projected in north-central 

Colorado. 

EPA’s modeling does indicate small 

increases in annual PM2.5 air quality 

design values in the final rule compared 

to the 2014 base case in two counties 

outside of the Transport Rule states: one 

county in northern Colorado and one 

county in eastern Montana. As 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 

should be noted that 2003–2007 average 

air quality levels in these counties are 

well below the level of the NAAQS. In 

addition, other actions, including 

federal rules such as the recently 

proposed Mercury and Air Toxics 

Standards, state, or local actions may 

also improve air quality in these areas 

over the next few years. 

As described in section VIII.B, EPA 

anticipates that this final rule will 

reduce, but not eliminate, the number of 

nonattainment and maintenance areas 

for the 1997 ozone and PM2.5 and 2006 

PM2.5 NAAQS. As noted above, ozone 

and PM2.5 concentrations are the result 

of both local emissions and long-range 

transport of pollution. Even when the 

significant contributions of upwind 

states are fully eliminated, additional 

emission reductions within the 

nonattainment area and/or the 

downwind state will be needed for some 

areas to attain and maintain the 

NAAQS. 

c. Estimated Health Benefits 

This rule reduces concentrations of 

PM2.5 and ozone pollution. Exposure to 

these pollutants can cause, or contribute 

to, adverse health effects that affect 

many minority, low-income, and tribal 

individuals and communities. PM2.5 and 

ozone are particularly (but not 

exclusively) harmful to children, the 

elderly, and people with existing heart 

and lung diseases, including asthma. 

Exposure to these pollutants can cause 

premature death and trigger heart 

attacks, asthma attacks in those with 

asthma, chronic and acute bronchitis, 

emergency room visits and 

hospitalizations, as well as milder 

illnesses that keep children home from 

school and adults home from work. 

High rates of heart disease (e.g., high 

blood pressure) 123 and asthma 124 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 

illnesses.125

We estimate that in 2014 the PMrelated annual benefits of the final rule 

include approximately 13,000 to 34,000 

fewer premature mortalities, 8,700 fewer 

cases of chronic bronchitis, 15,000 

fewer non-fatal heart attacks, 8,500 

fewer hospitalizations (for respiratory 

and cardiovascular disease combined), 

10 million fewer days of restricted 

activity due to respiratory illness, and 

approximately 1.7 million fewer lost 

work days. We also estimate substantial 

health improvements for children in the 

form of fewer cases of upper and lower 

respiratory illness, acute bronchitis, and 

asthma attacks. 

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 and 34,000 fewer 

premature mortalities. 

It should be noted that, as discussed 

in the RIA, there are other benefits to 

the emission reductions discussed here, 

including many other health benefits 

beyond reducing the risk of premature 

mortality. Additional benefits of 

reducing emissions of SO2 include 

improved visibility, reduced 

acidification of lakes and streams, and 

reduced mercury methylation in 

contaminated waters; additional 

benefits of NOX reductions include 

improved visibility, reduced 

acidification of lakes and streams, and 

reduced coastal eutrophication. 

d. Distribution of Health Benefits 

Among Different Populations 

EPA also estimated the PM2.5

mortality risks according to race, 

income, and educational attainment 

before and after implementation of this 

Transport Rule. We used premature 

mortality for this analysis 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 colleagues 126

note in their analysis of this relationship 

that the level of education attainment is 

likely to be a surrogate for the effects of 

complex socioeconomic processes 

(including factors such as race and 

income) on mortality. 

In the first step of the analysis, we 

estimated baseline (2005) PM2.5

mortality risk by race (White, Black, 

Asian, Native American) among people 

living in the counties with the highest 

(top 5 percent) PM2.5 mortality risk. We 


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also estimated baseline PM2.5 mortality 

risk by race among people living in the 

counties with both the highest (top 5 

percent) poverty rate and the highest 

(top 5 percent) PM2.5 mortality risk in 

2005. And, we estimated the baseline 

(2005) PM2.5 mortality risk by 

educational attainment for people living 

in the highest PM2.5 mortality risk 

counties. In the second step, we 

estimated the changes in risk for 

different races among the people living 

in these ‘‘high-risk’’ and ‘‘high risk and 

high-poverty’’ counties resulting from 

implementation of other existing rules 

in 2014 and from implementation of just 

the Transport Rule in 2014. Finally, in 

the third step, we compared the effects 

of the Transport Rule by race in the 

high-risk and high risk/high-poverty 

counties with the effects on people (by 

race) living in all other counties. 

In 2005, people living in the highestrisk counties and in the high risk/high 

poverty counties had substantially 

greater risks of PM2.5-related death than 

people living in the other 95 percent of 

counties. This was true regardless of 

race: The difference among races in both 

groups of counties was very small and 

dwarfed by the large difference between 

the two groups of counties for all races. 

For educational attainment, in contrast, 

our analysis found that people with less 

than high school education had 

significantly greater risks from PM2.5

mortality than people with a greater 

than high school education. This was 

especially true for people living in the 

highest-risk counties, but also held true 

for people living in all other counties. 

In summary, in 2005, having less than 

a high school or high school education, 

living in one of the poorest counties, 

and living in a high air pollution risk 

county are associated with higher PM2.5

mortality risk; race is not. 

Our analysis of the effects of the 

Transport Rule on this underlying 

exposure pattern finds that the rule will 

significantly reduce the PM2.5 mortality 

among all populations of different races 

living throughout the U.S. compared to 

both 2005 and 2014 pre-rule (i.e., base 

case) levels. No group will experience 

any increases in PM2.5 related deaths as 

a result of implementing the Transport 

Rule. 

The analysis indicates that the 

populations with the largest 

improvement (i.e., largest decline) in 

PM2.5 mortality risk as a result of the 

Transport Rule in 2014 (compared to the 

base case in 2014) are people living in 

the highest-risk counties. Among these 

counties, the largest improvements are 

for people with less than high school or 

high school education. These reductions 

in risk within the highest-risk counties, 

as well as the reductions in risk within 

the other 95 percent of counties, are 

distributed among populations of 

different races fairly evenly. Therefore, 

there is no indication that people of 

particular race receive a greater benefit 

(or smaller benefit) than others. 

The analysis indicates that people 

living in the high risk/high poverty 

counties will experience larger 

improvements in risk from the 

Transport Rule compared to their 

counterparts in the other counties. This 

result suggests that the Transport Rule 

is providing the greatest risk reduction 

improvements among counties 

containing the poorest, and highest risk, 

populations. There is also little 

difference in the improvement in risk 

among races; in other words, people in 

the high risk/high poverty counties 

experience the same improvement in 

risk regardless of race. 

The analysis also indicates that this 

rule, in conjunction with the 

implementation of existing or proposed 

rules (e.g., the proposed Mercury and 

Air Toxics Standards), will reduce the 

disparity in risk between the highestrisk counties and the other 95 percent 

of counties for all races and educational 

levels. In addition, implementation of 

this Transport Rule and other rules will, 

together, reduce risks in the poorest and 

highest risk counties to the approximate 

level of risk for the rest of the counties 

before implementation. This analysis is 

presented in more detail in the RIA for 

this rule which is available in the rule 

docket No. EPA–HQ–OAR–2009–0491 

and from the main EPA webpage for the 

rule at http://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 rulemaking process. These 

stakeholders included a number of 

environmental groups who requested 

that EPA consider several potential 

environmental justice issues during 

development of this rule. In addition, 

many environmental justice 

organizations were represented at a 

November 2009 EPA-Health and Human 

Services White House Stakeholder 

Briefing titled, ‘‘The Public Health 

Benefits of Energy Reform’’ in which 

EPA discussed our intention to propose 

this rule in the spring of 2010 and 

participants had the opportunity to 

respond. Finally, EPA notified Indian 

Tribes of our intent to propose this rule 

in the fall of 2009 during a regularly 

scheduled meeting to update the 

National Tribal Air Association 

members of upcoming EPA policies and 

regulations and to receive input from 

them on the effects of these efforts in 

Indian country. These were not 

opportunities for stakeholders to 

comment on the specifics of the 

proposal, as they took place prior to its 

development, but they provided 

valuable information that EPA used in 

developing the proposal. 

Just after the rule was proposed in 

July 2010, EPA presented a summary of 

information related to the proposed 

Transport Rule at the National 

Environmental Justice Advisory Council 

(NEJAC) meeting in Washington, DC, 

and responded to questions from NEJAC 

members regarding the proposed rule. 

EPA also solicited suggestions for how 

to engage environmental justice 

communities during the rule comment 

period. 

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 (9 a.m.–8 p.m.) to 

accommodate commenters with various 

work schedules. All three hearings were 

well-attended by members of the general 

public. During hearing breaks, EPA staff 

spent time talking with individuals, 

including those representing 

environmental justice organizations or 

communities, to understand their 

perspectives in greater detail. As noted 

above, several commenters at each 

hearing made comments related to the 

need to protect communities living near 

power plants and the most vulnerable 


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individuals. Some of these commenters 

specifically mentioned environmental 

justice; others mentioned issues often of 

concern to environmental justice 

communities, such as hot spots, interest 

in additional emission reductions and 

greater environmental protection, and 

concern over the effects of the rule on 

the most sensitive and vulnerable 

populations. 

In September 2010, during the 

comment period, EPA held a webinar 

for EJ communities on the proposed 

Transport Rule. A presentation tailored 

for an audience of environmental 

justice, community, and tribal 

representatives was specifically 

designed for this webinar. 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 bimonthly 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 federallyrecognized Tribes in the country 

offering consultation on the proposed 

Transport Rule. In addition, the January 

7 NODA on allowance allocation 

methodologies specifically requested 

comment on allocating allowances to 

new units in Indian Country. EPA held 

two consultation and informationsharing calls with 16 interested Tribes 

in late January and early February 2011. 

Tribes participating on these 

consultation and information calls 

provided comments on the proposed 

rule and the allowance allocation 

NODA. As noted above, this additional 

input from the consultation process was 

taken into account in the development 

of the final rule. See Section XII.F for 

more information on tribal consultation. 

4. Summary 

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 shows evidence of 

adverse effects. As a result, EPA 

concludes that we do not expect 

disproportionately high and adverse 

human health or environmental effects 

on minority, 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 October 7, 2011. 

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 October 7, 2011. 

Section 307(b)(1) of the CAA indicates 

which Federal Courts of Appeal have 

venue for petitions of review of final 

actions by EPA. This section provides, 

in part, that petitions for review must be 

filed in the Court of Appeals for the 

District of Columbia Circuit if (i) the 

agency action consists of ‘‘nationally 

applicable regulations promulgated, or 

final action taken, by the 

Administrator,’’ or (ii) such action is 

locally or regionally applicable, if ‘‘such 

action is based on a determination of 

nationwide scope or effect and if in 

taking such action the Administrator 

finds and publishes that such action is 

based on such a determination.’’ 

Any final action related to the 

Transport Rule is ‘‘nationally 

applicable’’ within the meaning of 

section 307(b)(1). Through this rule, 

EPA interprets section 110 of the CAA, 

a provision which has nationwide 

applicability. In addition, the Transport 

Rule applies to 27 States. The Transport 

Rule is also based on a common core of 

factual findings and analyses 

concerning the transport of pollutants 

between the different states subject to it. 

For these reasons, the Administrator 

also is determining that any final action 

regarding the Transport Rule is of 

nationwide scope and effect for 

purposes of section 307(b)(1). Thus, 

pursuant to section 307(b) any petitions 

for review of final actions regarding the 

Transport Rule must be filed in the 

Court of Appeals for the District of 

Columbia Circuit within 60 days from 

the date final action is published in the 

Federal Register. 

Filing a petition for reconsideration of 

this action does not affect the finality of 

this rule for the purposes of judicial 

review nor does it extend the time 

within which a petition for judicial 

review may be filed and shall not 

postpone the effectiveness of such rule 

or action. In addition, pursuant to CAA 

section 307(b)(2) this action may not be 

challenged later in proceedings to 

enforce its requirements. 

In addition, this action is subject to 

the provisions of section 307(d). CAA 

section 307(d)(1)(B) provides that 

section 307(d) applies to, among other 

things, to ‘‘the promulgation or revision 

of an implementation plan by the 

Administrator under CAA section 

110(c)’’ (42 U.S.C. 7407(d)(1)(B)). The 

Agency has complied with procedural 

requirements of CAA section 307(d) 

during the course of this rulemaking. 

List of Subjects 

40 CFR Part 51 

Administrative practice and 

procedure, Air pollution control, 

Incorporation by reference, 

Intergovernmental relations, Nitrogen 

oxides, Ozone, Particulate matter, 

Regional haze, Reporting and 

recordkeeping requirements, Sulfur 

dioxide. 

40 CFR Part 52 

Administrative practice and 

procedure, Air pollution control, 

Incorporation by reference, 

Intergovernmental relations, Nitrogen 


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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations 48353 

oxides, Ozone, Particulate matter, 

Regional haze, Reporting and 

recordkeeping requirements, Sulfur 

dioxide. 

40 CFR Part 72 

Acid rain, Administrative practice 

and procedure, Air pollution control, 

Electric utilities, Incorporation by 

reference, Intergovernmental relations, 

Nitrogen oxides, Reporting and 

recordkeeping requirements, Sulfur 

dioxide. 

40 CFR Part 78 

Acid rain, Administrative practice 

and procedure, Air pollution control, 

Electric utilities, Intergovernmental 

relations, Nitrogen oxides, Reporting 

and recordkeeping requirements, Sulfur 

dioxide. 

40 CFR Part 97 

Administrative practice and 

procedure, Air pollution control, 

Electric utilities, Nitrogen oxides, 

Reporting and recordkeeping 

requirements, Sulfur dioxide. 

Dated: July 6, 2011. 

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] 

■ 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. In § 51.121 paragraph (r)(2) is 

amended by removing the words 

‘‘§ 51.123(bb)’’ and adding, in their 

place, the words ‘‘§ 51.123(bb) with 

regard to an ozone season that occurs 

before January 1, 2012’’. 

■ 3. Section 51.123 is amended by 

adding a new paragraph (ff) to read as 

follows: 

§ 51.123 Findings and requirements for 

submission of State implementation plan 

revisions relating to emissions of oxides of 

nitrogen pursuant to the Clean Air Interstate 

Rule. 

* * * * * 

(ff) Notwithstanding any provisions of 

paragraphs (a) through (ee) of this 

section, subparts AA through II and 

AAAA through IIII of part 96 of this 

chapter, subparts AA through II and 

AAAA through IIII of part 97 of this 

chapter, and any State’s SIP to the 

contrary: 

(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 November 7, 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 holding or surrender of 

CAIR NOX allowances will be required 

with regard to emissions or excess 

emissions for such control periods; and 

(4) By November 7, 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 

holding or surrender of CAIR NOX

Ozone Season allowances will be 

required with regard to emissions or 

excess emissions for such control 

periods. 

■ 4. Section 51.124 is amended by 

adding a new paragraph (s) to read as 

follows: 

§ 51.124 Findings and requirements for 

submission of State implementation plan 

revisions relating to emissions of sulfur 

dioxide pursuant to the Clean Air Interstate 

Rule. 

* * * * * 

(s) Notwithstanding any provisions of 

paragraphs (a) through (r) of this 

section, subparts AAA through III of 

part 96 of this chapter, subparts AAA 

through III of part 97 of this chapter, 

and any State’s SIP to the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, the 

Administrator: 

(i) Rescinds the determination in 

paragraph (a) of this section that the 

States identified in paragraph (c) of this 

section must submit a SIP revision with 

respect to the fine particles (PM2.5) 

NAAQS meeting the requirements of 

paragraphs (b) through (r) of this 

section; and 

(ii) Will not carry out any of the 

functions set forth for the Administrator 

in subparts AAA through III of part 96 

of this chapter, subparts AAA through 

III of part 97 of this chapter, or in any 

emissions trading program in a State’s 

SIP approved under this section; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

§ 51.125 [Reserved] 

■ 5. Section 51.125 is removed and 

reserved. 

PART 52—[AMENDED] 

■ 6. The authority citation for part 52 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

Subpart A—General Provisions 

■ 7. Section 52.35 is amended by adding 

a new paragraph (f) to read as follows: 

§ 52.35 What are the requirements of the 

Federal Implementation Plans (FIPs) for the 

Clean Air Interstate Rule (CAIR) relating to 

emissions of nitrogen oxides? 

* * * * * 

(f) Notwithstanding any provisions of 

paragraphs (a) through (d) of this 

section, subparts AA through II and 

AAAA through IIII of part 97 of this 

chapter, and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraphs (a) 

through (d) of this section relating to 

NOX annual or ozone season emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

and AAAA through IIII of part 97 of this 

chapter; 

(2) The Administrator will not deduct 

for excess emissions any CAIR NOX

allowances or CAIR NOX Ozone Season 

allowances allocated for 2012 or any 

year thereafter; 

(3) By November 7, 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 holding or surrender of 

CAIR NOX allowances will be required 

with regard to emissions or excess 

emissions for such control periods; and 


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(4) By November 7, 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 

holding or surrender of CAIR NOX

allowances will be required with regard 

to emissions or excess emissions for 

such control periods. 

■ 8. Section 52.36 is amended by adding 

a new paragraph (e) to read as follows: 

§ 52.36 What are the requirements of the 

Federal Implementation Plans (FIPs) for the 

Clean Air Interstate Rule (CAIR) relating to 

emissions of sulfur dioxide? 

* * * * * 

(e) Notwithstanding any provisions of 

paragraphs (a) through (c) of this 

section, subparts AAA through III of 

part 97 of this chapter and any State’s 

SIP to the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraphs (a) 

through (e) of this section relating to 

SO2 emissions shall not be applicable; 

and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

■ 9. Sections §§ 52.38 and 52.39 are 

added to subpart A to read as follows: 

§ 52.38 What are the requirements of the 

Federal Implementation Plans (FIPs) under 

the Transport Rule (TR) relating to 

emissions of nitrogen oxides? 

(a)(1) The TR NOX Annual Trading 

Program provisions set forth in subpart 

AAAAA of part 97 of this chapter 

constitute the TR Federal 

Implementation Plan provisions that 

relate to annual emissions of nitrogen 

oxides (NOX). 

(2) The provisions of subpart AAAAA 

of part 97 of this chapter apply to the 

sources in the following States and 

Indian country located within the 

borders of such States: Alabama, 

Georgia, Illinois, Indiana, Iowa, Kansas, 

Kentucky, Maryland, Michigan, 

Minnesota, Missouri, Nebraska, New 

Jersey, New York, North Carolina, Ohio, 

Pennsylvania, South Carolina, 

Tennessee, Texas, Virginia, West 

Virginia, and Wisconsin. 

(3) Notwithstanding the provisions of 

paragraph (a)(1) of this section, a State 

listed in paragraph (a)(2) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, as TR NOX Annual allowance 

allocation provisions replacing the 

provisions in § 97.411(a) of this chapter 

with regard to the State and the control 

period in 2013, a list of TR NOX Annual 

units and the amount of TR NOX

Annual allowances allocated to each 

unit on such list, provided that the list 

of units and allocations meets the 

following requirements: 

(i) All of the units on the list must be 

units that are in the State and 

commenced commercial operation 

before January 1, 2010; 

(ii) The total amount of TR NOX

Annual allowance allocations on the list 

must not exceed the amount, under 

§ 97.410(a) of this chapter for the State 

and the control period in 2013, of TR 

NOX Annual trading budget minus the 

sum of the new unit set-aside and 

Indian country new unit set-aside; 

(iii) The list must be submitted 

electronically in a format specified by 

the Administrator; and 

(iv) The SIP revision must not provide 

for any change in the units and 

allocations on the list after approval of 

the SIP revision by the Administrator 

and must not provide for any change in 

any allocation determined and recorded 

by the Administrator under subpart 

AAAAA of part 97 of this chapter; 

(v) Provided that: 

(A) By October 17, 2011, 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) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, regulations revising subpart 

AAAAA of part 97 of this chapter as 

follows and not making any other 

substantive revisions of that subpart: 

(i) The State may adopt, as TR NOX

Annual allowance allocation or auction 

provisions replacing the provisions in 

§§ 97.411(a) and (b)(1) and 97.412(a) of 

this chapter with regard to the State and 

the control period in 2014 or any 

subsequent year, any methodology 

under which the State or the permitting 

authority allocates or auctions TR NOX

Annual allowances, and may adopt, in 

addition to the definitions in § 97.402 of 

this chapter, one or more definitions 

that shall apply only to terms as used in 

the adopted TR NOX Annual allowance 

allocation or auction provisions, if such 

methodology— 

(A) Requires the State or the 

permitting authority to allocate and, if 

applicable, auction a total amount of TR 

NOX Annual allowances for any such 

control period not exceeding the 

amount, under §§ 97.410(a) and 97.421 

of this chapter for the State and such 

control period, of the TR NOX Annual 

trading budget minus the sum of the 

Indian country new unit set-aside and 

the amount of any TR NOX Annual 

allowances already allocated and 

recorded by the Administrator. 

(B) Requires, to the extent the State 

adopts provisions for allocations or 

auctions of TR NOX Annual allowances 

for any such control period to any TR 

NOX Annual units covered by 

§ 97.411(a) of this chapter, that the State 

or the permitting authority submit such 

allocations or the results of such 

auctions for such control period (except 

allocations or results of auctions to such 

units of TR NOX Annual allowances 

remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator no later 

than the following dates: 

Year of the control 

period for which TR 

NOX annual allowances are allocated or 

auctioned 

Deadline for submission of allocations or 

auction results to 

administrator 

2014 .......................... June 1, 2013. 

2015 .......................... June 1, 2013. 

2016 .......................... June 1, 2014. 

2017 .......................... June 1, 2014. 

2018 .......................... June 1, 2015. 

2019 .......................... June 1, 2015. 

2020 and any year 

thereafter.

June 1 of the fourth 

year before the 

year of the control 

period. 

(C) Requires, to the extent the State 

adopts provisions for allocations or 

auctions of TR NOX Annual allowances 

for any such control period to any TR 

NOX Annual units covered by 

§§ 97.411(b)(1) and 97.412(a) of this 

chapter, that the State or the permitting 

authority submit such allocations or the 

results of such auctions (except 

allocations or results of auctions to such 

units of TR NOX Annual allowances 

remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator by July 1 

of the year of such control period. 

(D) Does not provide for any change, 

after the submission deadlines in 

paragraphs (a)(4)(i)(B) and (C) of this 

section, in the allocations submitted to 

the Administrator by such deadlines 

and does not provide for any change in 


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any allocation determined and recorded 

by the Administrator under subpart 

AAAAA of part 97 of this chapter; 

(ii) Provided that the State must 

submit a complete SIP revision meeting 

the requirements of paragraph (a)(4)(i) of 

this section by December 1 of the year 

before the year of the deadlines for 

submission of allocations or auction 

results under paragraphs (a)(4)(i)(B) and 

(C) of this section for the first control 

period for which the State wants to 

make allocations or hold an auction 

under paragraph (a)(4)(i) of this section. 

(5) Notwithstanding the provisions of 

paragraph (a)(1) of this section, a State 

listed in paragraph (a)(2) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, as correcting in whole or in 

part, as appropriate, the deficiency in 

the SIP that is the basis for the TR 

Federal Implementation Plan set forth in 

paragraphs (a)(1) through (4) of this 

section, regulations that are 

substantively identical to the provisions 

of the TR NOX Annual Trading Program 

set forth in §§ 97.402 through 97.435 of 

this chapter, except that the SIP 

revision: 

(i) May adopt, as TR NOX Annual 

allowance allocation or auction 

provisions replacing the provisions in 

§§ 97.411(a) and (b)(1) and 97.412(a) of 

this chapter with regard to the State and 

the control period in 2014 or any 

subsequent year, any methodology 

under which the State or the permitting 

authority allocates or auctions TR NOX

Annual allowances and that— 

(A) Requires the State or the 

permitting authority to allocate and, if 

applicable, auction a total amount of TR 

NOX Annual allowances for any such 

control period not exceeding the 

amount, under §§ 97.410(a) and 97.421 

of this chapter for the State and such 

control period, of the TR NOX Annual 

trading budget minus the sum of the 

Indian country new unit set-aside and 

the amount of any TR NOX Annual 

allowances already allocated and 

recorded by the Administrator. 

(B) Requires, to the extent the State 

adopts provisions for allocations or 

auctions of TR NOX Annual allowances 

for any such control period to any TR 

NOX Annual units covered by 

§ 97.411(a) of this chapter, that the State 

or the permitting authority submit such 

allocations or the results of such 

auctions for such control period (except 

allocations or results of auctions to such 

units of TR NOX Annual allowances 

remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator no later 

than the following dates: 

Year of the control 

period for which TR 

NOX annual allowances are allocated or 

auctioned 

Deadline for submission of allocations or 

auction results to 

administrator 

2014 .......................... June 1, 2013. 

2015 .......................... June 1, 2013. 

2016 .......................... June 1, 2014. 

2017 .......................... June 1, 2014. 

2018 .......................... June 1, 2015. 

2019 .......................... June 1, 2015. 

2020 and any year 

thereafter.

June 1 of the fourth 

year before the 

year of the control 

period. 

(C) Requires, to the extent the State 

adopts provisions for allocations or 

auctions of TR NOX Annual allowances 

for any such control period to any TR 

NOX Annual units covered by 

§§ 97.411(b)(1) and 97.412(a) of this 

chapter, that the State or the permitting 

authority submit such allocations or the 

results of such auctions (except 

allocations or results of auctions to such 

units of TR NOX Annual allowances 

remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator by July 1 

of the year of such control period. 

(D) Does not provide for any change, 

after the submission deadlines in 

paragraphs (a)(5)(i)(B) and (C) of this 

section, in the allocations submitted to 

the Administrator by such deadlines 

and does not provide for any change in 

any allocation determined and recorded 

by the Administrator under subpart 

AAAAA of part 97 of this chapter; 

(ii) May adopt, in addition to the 

definitions in § 97.402 of this chapter, 

one or more definitions that shall apply 

only to terms as used in the TR NOX

Annual allowance allocation or auction 

provisions adopted under paragraph 

(a)(5)(i) of this section; 

(iii) May substitute the name of the 

State for the term ‘‘State’’ as used in 

subpart AAAAA of part 97 of this 

chapter, to the extent the Administrator 

determines that such substitutions do 

not make substantive changes in the 

provisions in §§ 97.402 through 97.435 

of this chapter; and 

(iv) Must not include any of the 

references to, or requirements imposed 

on, any unit in Indian country within 

the borders of the State in the provisions 

in §§ 97.402 through 97.435 of this 

chapter and must not include the 

provisions in §§ 97.411(b)(2) and 

97.412(b), all of which provisions will 

continue to apply under the portion of 

the TR Federal Implementation Plan 

that is not replaced by the SIP revision; 

(v) Provided that, if and when any 

covered unit is located in Indian 

country within the borders of the State, 

the Administrator may modify his or her 

approval of the SIP revision to exclude 

the provisions in §§ 97.402 (definitions 

of ‘‘common designated representative’’, 

‘‘common designated representative’s 

assurance level’’, and ‘‘common 

designated representative’s share’’), 

97.406(c)(2), 97.425, and the portions of 

other provisions referencing these 

sections and may modify the portion of 

the TR Federal Implementation Plan 

that is not replaced by the SIP revision 

to include these provisions; 

(vi) Provided that the State must 

submit a complete SIP revision meeting 

the requirements of paragraphs (a)(5)(i) 

through (iv) of this section by December 

1 of the year before the year of the 

deadlines for submission of allocations 

or auction results under paragraphs 

(a)(5)(i)(B) and (C) of this section 

applicable to the first control period for 

which the State wants to make 

allocations or hold an auction under 

paragraphs (a)(5)(i) and (ii) of this 

section. 

(6) Following promulgation of an 

approval by the Administrator of a 

State’s SIP revision as correcting in 

whole or in part, as appropriate, the 

SIP’s deficiency that is the basis for the 

TR Federal Implementation Plan 

described in paragraphs (a)(1) through 

(5) of this section, the provisions of 

paragraph (a)(2) of this section will no 

longer apply to the sources in the State, 

unless the Administrator’s approval of 

the SIP revision is partial or conditional, 

and will continue to apply to sources in 

any Indian country within the borders 

of the State. 

(7) Notwithstanding the provisions of 

paragraph (a)(6) of this section, if, at the 

time of such approval of the State’s SIP 

revision, the Administrator has already 

started recording any allocations of TR 

NOX Annual allowances under subpart 

AAAAA of part 97 of this chapter to 

units in a State for a control period in 

any year, the provisions of subpart 

AAAAA of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b)(1) The TR NOX Ozone Season 

Trading Program provisions set forth in 

part 97 of this chapter constitute the TR 

Federal Implementation Plan provisions 

that relate to emissions of NOX during 

the ozone season, defined as May 1 

through September 30 of a calendar 

year. 

(2) The provisions of subpart BBBBB 

of part 97 of this chapter apply to 


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sources in each of the following States 

and Indian country located within the 

borders of such States: Alabama, 

Arkansas, Florida, Georgia, Illinois, 

Indiana, Kentucky, Louisiana, 

Maryland, Mississippi, New Jersey, New 

York, North Carolina, Ohio, 

Pennsylvania, South Carolina, 

Tennessee, Texas, Virginia, and West 

Virginia. 

(3) Notwithstanding the provisions of 

paragraph (b)(1) of this section, a State 

listed in paragraph (b)(2) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, as TR NOX Ozone Season 

allowance allocation provisions 

replacing the provisions in § 97.511(a) 

of this chapter with regard to the State 

and the control period in 2013, a list of 

TR NOX Ozone Season units and the 

amount of TR NOX Ozone Season 

allowances allocated to each unit on 

such list, provided that the list of units 

and allocations meets the following 

requirements: 

(i) All of the units on the list must be 

units that are in the State and 

commenced commercial operation 

before January 1, 2010; 

(ii) The total amount of TR NOX

Ozone Season allowance allocations on 

the list must not exceed the amount, 

under § 97.510(a) of this chapter for the 

State and the control period in 2013, of 

TR NOX Ozone Season trading budget 

minus the sum of the new unit set-aside 

and Indian country new unit set-aside; 

(iii) The list must be submitted 

electronically in a format specified by 

the Administrator; and 

(iv) The SIP revision must not provide 

for any change in the units and 

allocations on the list after approval of 

the SIP revision by the Administrator 

and must not provide for any change in 

any allocation determined and recorded 

by the Administrator under subpart 

BBBBB of part 97 of this chapter; 

(v) Provided that: 

(A) By October 17, 2011, the State 

must notify the Administrator 

electronically in a format specified by 

the Administrator of the State’s intent to 

submit to the Administrator a complete 

SIP revision meeting the requirements 

of paragraph (b)(3)(i) through (iv) of this 

section by April 1, 2012; and 

(B) The State must submit to the 

Administrator a complete SIP revision 

described in paragraph (b)(3)(v)(A) of 

this section by April 1, 2012. 

(4) Notwithstanding the provisions of 

paragraph (b)(1) of this section, a State 

listed in paragraph (b)(2) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, regulations revising subpart 

BBBBB of part 97 of this chapter as 

follows and not making any other 

substantive revisions of that subpart: 

(i) The State may adopt, as 

applicability provisions replacing the 

provisions in §§ 97.504(a)(1) and (2) of 

this chapter, provisions substantively 

identical to those provisions, except that 

the words ‘‘more than 25 MWe’’ are 

replaced, whenever such words appear, 

by words specifying a uniform lower 

limit on the amount of megawatts that 

is not greater than the amount specified 

by the words ‘‘more than 25 MWe’’ and 

is not less than the amount specified by 

the words ‘‘15 MWe or more’’; or 

(ii) The State may adopt, as TR NOX

Ozone Season allowance allocation or 

auction provisions replacing the 

provisions in §§ 97.511(a) and (b)(1) and 

97.512(a) of this chapter with regard to 

the control period in 2014 or any 

subsequent year, any methodology 

under which the State or the permitting 

authority allocates or auctions TR NOX

Ozone Season allowances, and may 

adopt, in addition to the definitions in 

§ 97.502 of this chapter, one or more 

definitions that shall apply only to 

terms as used in the adopted TR NOX

Ozone Season allowance allocation or 

auction provisions, if such 

methodology— 

(A) Requires the State or the 

permitting authority to allocate and, if 

applicable, auction a total amount of TR 

NOX Ozone Season allowances for any 

such control period not exceeding the 

amount, under §§ 97.510(a) and 97.521 

of this chapter for the State and such 

control period, of the TR NOX Ozone 

Season trading budget minus the sum of 

the Indian country new unit set-aside 

and the amount of any TR NOX Ozone 

Season allowances already allocated 

and recorded by the Administrator. 

(B) Requires, to the extent the State 

adopts provisions for allocations or 

auctions of TR NOX Ozone Season 

allowances for any such control period 

to any TR NOX Ozone Season units 

covered by § 97.511(a) of this chapter, 

that the State or the permitting authority 

submit such allocations or the results of 

such auctions for such control period 

(except allocations or results of auctions 

to such units of TR NOX Ozone Season 

allowances remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator no later 

than the following dates: 

Year of the control 

period for which TR 

NOX Ozone Season 

allowances are allocated or auctioned 

Deadline for submission of allocations or 

auction results to 

administrator 

2014 .......................... June 1, 2013. 

2015 .......................... June 1, 2013. 

Year of the control 

period for which TR 

NOX Ozone Season 

allowances are allocated or auctioned 

Deadline for submission of allocations or 

auction results to 

administrator 

2016 .......................... June 1, 2014. 

2017 .......................... June 1, 2014. 

2018 .......................... June 1, 2015. 

2019 .......................... June 1, 2015. 

2020 and any year 

thereafter.

June 1 of the fourth 

year before the 

year of the control 

period. 

(C) Requires, to the extent the State 

adopts provisions for allocations or 

auctions of TR NOX Ozone Season 

allowances for any such control period 

to any TR NOX Ozone Season units 

covered by §§ 97.511(b)(1) and 97.512(a) 

of this chapter, that the State or the 

permitting authority submit such 

allocations or the results of such 

auctions (except allocations or results of 

auctions to such units of TR NOX Ozone 

Season allowances remaining in a setaside after completion of the allocations 

or auctions for which the set-aside was 

created) to the Administrator by July 1 

of the year of such control period. 

(D) Does not provide for any change, 

after the submission deadlines in 

paragraphs (b)(4)(ii)(B) and (C) of this 

section, in the allocations submitted to 

the Administrator by such deadlines 

and does not provide for any change in 

any allocation determined and recorded 

by the Administrator under subpart 

BBBBB of part 97 of this chapter; 

(iii) Provided that the State must 

submit a complete SIP revision meeting 

the requirements of paragraph (b)(4)(i) 

or (ii) of this section by December 1 of 

the year before the year of the deadlines 

for submission of allocations or auction 

results under paragraphs (b)(4)(ii)(B) 

and (C) of this section applicable to the 

first control period for which the State 

wants to replace the applicability 

provisions, make allocations, or hold an 

auction under paragraph (b)(4)(i) or (ii) 

of this section. 

(5) Notwithstanding the provisions of 

paragraph (b)(1) of this section, a State 

listed in paragraph (b)(2) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, as correcting in whole or in 

part, as appropriate, the deficiency in 

the SIP that is the basis for the TR 

Federal Implementation Plan set forth in 

paragraphs (b)(1) through (4) of this 

section, regulations that are 

substantively identical to the provisions 

of the TR NOX Ozone Season Trading 

Program set forth in §§ 97.502 through 

97.535 of this chapter, except that the 

SIP revision: 


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(i) May adopt, as applicability 

provisions replacing the provisions in 

§§ 97.504(a)(1) and (2) of this chapter, 

provisions substantively identical to 

those provisions, except that the words 

‘‘more than 25 MWe’’ are replaced, 

whenever such words appear, by words 

specifying a uniform lower limit on the 

amount of megawatts that is not greater 

than the amount specified by the words 

‘‘more than 25 MWe’’ and is not less 

than the amount specified by the words 

‘‘15 MWe or more’’; or 

(ii) May adopt, as TR NOX Ozone 

Season allowance allocation provisions 

replacing the provisions in §§ 97.511(a) 

and (b)(1) and 97.512(a) of this chapter 

with regard to the control period in 

2014 and any subsequent year, any 

methodology under which the State or 

the permitting authority allocates 

auctions TR NOX Ozone Season 

allowances and that— 

(A) Requires the State or the 

permitting authority to allocate and, if 

applicable, auction a total amount of TR 

NOX Ozone Season allowances for any 

such control period not exceeding the 

amount, under §§ 97.510(a) and 97.521 

of this chapter for the State and such 

control period, of the TR NOX Ozone 

Season trading budget minus the sum of 

the Indian country new unit set-aside 

and the amount of any TR NOX Ozone 

Season allowances already allocated 

and recorded by the Administrator. 

(B) Requires, to the extent the State 

adopts provisions for allocations or 

auction of TR NOX Ozone Season 

allowances for any such control period 

to any TR NOX Ozone Season units 

covered by § 97.511(a) of this chapter, 

that the State or the permitting authority 

submit such allocations or the results of 

such auctions for such control period 

(except allocations or results of auctions 

to such units of TR NOX Ozone Season 

allowances remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator no later 

than the following dates: 

Year of the control 

period for which TR 

NOX Ozone Season 

allowances are allocated or auctioned 

Deadline for submission of allocations or 

auction results to 

administrator 

2014 .......................... June 1, 2013. 

2015 .......................... June 1, 2013. 

2016 .......................... June 1, 2014. 

2017 .......................... June 1, 2014. 

2018 .......................... June 1, 2015. 

2019 .......................... June 1, 2015. 

2020 and any year 

thereafter.

June 1 of the fourth 

year before the 

year of the control 

period. 

(C) Requires, to the extent the State 

adopts provisions for allocations or 

auctions of TR NOX Ozone Season 

allowances for any control period to any 

TR NOX Ozone Season units covered by 

§§ 97.511(b)(1) and 97.512(a) of this 

chapter, that the State or the permitting 

authority submit such allocations or the 

results of such auctions (except 

allocations or results of auctions to such 

units of TR NOX Ozone Season 

allowances remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator by July 1 

of the year of such control period. 

(D) Does not provide for any change, 

after the submission deadlines in 

paragraphs (b)(5)(ii)(B) and (C) of this 

section, in the allocations submitted to 

the Administrator by such deadlines 

and does not provide for any change in 

any allocation determined and recorded 

by the Administrator under subpart 

BBBBB of part 97 of this chapter; 

(iii) May adopt in addition to the 

definitions in § 97.502 of this chapter, 

one or more definitions that shall apply 

only to terms as used in the TR NOX

Ozone Season allowance allocation or 

auction provisions adopted under 

paragraph (b)(5)(ii) of this section; 

(iv) May substitute the name of the 

State for the term ‘‘State’’ as used in 

subpart BBBBB of part 97 of this 

chapter, to the extent the Administrator 

determines that such substitutions do 

not make substantive changes in the 

provisions in §§ 97.502 through 97.535 

of this chapter; and 

(v) Must not include any of the 

references to, or requirements imposed 

on, any unit in Indian country within 

the borders of the State in the provisions 

in §§ 97.502 through 97.535 of this 

chapter and must not include the 

provisions in §§ 97.511(b)(2) and 

97.512(b), all of which provisions will 

continue to apply under the portion of 

the TR Federal Implementation Plan 

that is not replaced by the SIP revision; 

(vi) Provided that, if and when any 

covered unit is located in Indian 

country within the borders of the State, 

the Administrator may modify his or her 

approval of the SIP revision to exclude 

the provisions in §§ 97.502 (definitions 

of ‘‘common designated representative’’, 

‘‘common designated representative’s 

assurance level’’, and ‘‘common 

designated representative’s share’’), 

97.506(c)(2), 97.525, and the portions of 

other provisions referencing these 

sections and may modify the portion of 

the TR Federal Implementation Plan 

that is not replaced by the SIP revision 

to include these provisions; 

(vii) Provided that the State must 

submit a complete SIP revision meeting 

the requirements of paragraph (b)(5)(i) 

through (v) of this section by December 

1 of the year before the year of the 

deadlines for submission of allocations 

or auction results under paragraphs 

(5)(ii)(B) and (C) of this section 

applicable to the first control period for 

which the State wants to replace the 

applicability provisions, make 

allocations, or hold an auction under 

paragraphs (b)(5)(ii) and (iii) of this 

section. 

(6) Following promulgation of an 

approval by the Administrator of a 

State’s SIP revision as correcting in 

whole or in part, as appropriate, the 

SIP’s deficiency that is the basis for the 

TR Federal Implementation Plan set 

forth in paragraphs (b)(1) through (5) of 

this section, the provisions of paragraph 

(b)(2) of this section will no longer 

apply to sources in the State, unless the 

Administrator’s approval of the SIP 

revision is partial or conditional, and 

will continue to apply to sources in any 

Indian country within the borders of the 

State. 

(7) Notwithstanding the provisions of 

paragraph (b)(6) of this section, if, at the 

time of such approval of the State’s SIP 

revision, the Administrator has already 

started recording any allocations of TR 

NOX Ozone Season allowances under 

subpart BBBBB of part 97 of this chapter 

to units in a State for a control period 

in any year, the provisions of subpart 

BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

§ 52.39 What are the requirements of the 

Federal Implementation Plans (FIPs) for the 

Transport Rule (TR) relating to emissions of 

sulfur dioxide? 

(a) The TR SO2 Group 1 Trading 

Program provisions and the TR SO2

Group 2 Trading Program provisions set 

forth respectively in subparts CCCCC 

and DDDDD of part 97 of this chapter 

constitute the TR Federal 

Implementation Plan provisions that 

relate to emissions of sulfur dioxide 

(SO2). 

(b) The provisions of subpart CCCCC 

of part 97 of this chapter apply to 

sources in each of the following States 

and Indian country located within the 

borders of such States: Illinois, Indiana, 

Iowa, Kentucky, Maryland, Michigan, 

Missouri, New Jersey, New York, North 

Carolina, Ohio, Pennsylvania, 

Tennessee, Virginia, West Virginia, and 

Wisconsin. 


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(c) The provisions of subpart DDDDD 

of part 97 of this chapter apply to 

sources in each of the following States 

and Indian country located within the 

borders of such States: Alabama, 

Georgia, Kansas, Minnesota, Nebraska, 

South Carolina, and Texas. 

(d) Notwithstanding the provisions of 

paragraph (a) of this section, a State 

listed in paragraph (b) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, as TR SO2 Group 1 allowance 

allocation provisions replacing the 

provisions in § 97.611(a) of this chapter 

with regard to the State and the control 

period in 2013, a list of TR SO2 Group 

1 units and the amount of TR SO2 Group 

1 allowances allocated to each unit on 

such list, provided that the list of units 

and allocations meets the following 

requirements: 

(1) All of the units on the list must be 

units that are in the State and 

commenced commercial operation 

before January 1, 2010; 

(2) The total amount of TR SO2 Group 

1 allowance allocations on the list must 

not exceed the amount, under 

§ 97.610(a) of this chapter for the State 

and the control period in 2013, of TR 

SO2 Group 1 trading budget minus the 

sum of the new unit set-aside and 

Indian country new unit set-aside; 

(3) The list must be submitted 

electronically in a format specified by 

the Administrator; and 

(4) The SIP revision must not provide 

for any change in the units and 

allocations on the list after approval of 

the SIP revision by the 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 October 17, 2011, the State must 

notify the Administrator electronically 

in a format specified by the 

Administrator of the State’s intent to 

submit to the Administrator a complete 

SIP revision meeting the requirements 

of paragraph (d)(1) through (4) of this 

section by April 1, 2012; and 

(ii) The State must submit to the 

Administrator a complete SIP revision 

described in paragraph (d)(5)(i) of this 

section by April 1, 2012. 

(e) Notwithstanding the provisions of 

paragraph (a) of this section, a State 

listed in paragraph (b) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, regulations revising subpart 

CCCCC of part 97 of this chapter as 

follows and not making any other 

substantive revisions of that subpart: 

(1) The State may adopt, as TR SO2

Group 1 allowance allocation or auction 

provisions replacing the provisions in 

§§ 97.611(a) and (b)(1) and 97.612(a) of 

this chapter with regard to the control 

period in 2014 or any subsequent year, 

any methodology under which the State 

or the permitting authority allocates or 

auctions TR SO2 Group 1 allowances 

and may adopt, in addition to the 

definitions in § 97.602 of this chapter, 

one or more definitions that shall apply 

only to terms as used in the adopted TR 

SO2 Group 1 allowance allocation or 

auction provisions, if such 

methodology— 

(i) Requires the State or the permitting 

authority to allocate and, if applicable, 

auction a total amount of TR SO2 Group 

1 allowances for any such control 

period not exceeding the amount, under 

§§ 97.610(a) and 97.621 of this chapter 

for the State and such control period, of 

the TR SO2 Group 1 trading budget 

minus the sum of the Indian country 

new unit set-aside and the amount of 

any TR SO2 Group 1 allowances already 

allocated and recorded by the 

Administrator. 

(ii) Requires, to the extent the State 

adopts provisions for allocations or 

auction of TR SO2 Group 1 allowances 

for any such control period to any TR 

SO2 Group 1 units covered by 

§ 97.611(a) of this chapter, that the State 

or the permitting authority submit such 

allocations or the results of such 

auctions for such control period (except 

allocations or results of auctions to such 

units of TR SO2 Group 1 allowances 

remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator no later 

than the following dates: 

Year of the control 

period for which TR 

SO2 Group 1 allowances are allocated or 

auctioned 

Deadline for submission of allocations or 

auction results to 

administrator 

2014 .......................... June 1, 2013. 

2015 .......................... June 1, 2013. 

2016 .......................... June 1, 2014. 

2017 .......................... June 1, 2014. 

2018 .......................... June 1, 2015. 

2019 .......................... June 1, 2015. 

2020 and any year 

thereafter.

June 1 of the fourth 

year before the 

year of the control 

period. 

(iii) Requires, to the extent the State 

adopts provisions for allocations or 

auctions of TR SO2 Group 1 allowances 

for any such control period to any TR 

SO2 Group 1 units covered by 

§§ 97.611(b)(1) and 97.612(a) of this 

chapter, that the State or the permitting 

authority submit such allocations or the 

results of such auctions (except 

allocations or results of auctions to such 

units of TR SO2 Group 1 allowances 

remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator by July 1 

of the year of such control period. 

(iv) Does not provide for any change, 

after the submission deadlines in 

paragraphs (e)(1)(ii) and (iii) of this 

section, in the allocations submitted to 

the Administrator by such deadlines 

and does not provide for any change in 

any allocation determined and recorded 

by the Administrator under subpart 

CCCCC of part 97 of this chapter; 

(2) Provided that the State must 

submit a complete SIP revision meeting 

the requirements of paragraph (e)(1) of 

this section by December 1 of the year 

before the year of the deadlines for 

submission of allocations or auction 

results under paragraphs (e)(1)(ii) and 

(iii) of this section applicable to the first 

control period for which the State wants 

to make allocations or hold an auction 

under paragraph (e)(1) of this section. 

(f) Notwithstanding the provisions of 

paragraph (a) of this section, a State 

listed in paragraph (b) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, as correcting in whole or in 

part, as appropriate, the deficiency in 

the SIP that is the basis for the TR 

Federal Implementation Plan set forth in 

paragraphs (a), (b), (d), and (e) of this 

section, regulations that are 

substantively identical to the provisions 

of the TR SO2 Group 1 Trading Program 

set forth in §§ 97.602 through 97.635 of 

this chapter, except that the SIP 

revision: 

(1) May adopt, as TR SO2 Group 1 

allowance allocation or auction 

provisions replacing the provisions in 

§§ 97.611(a) and (b)(1) and 97.612(a) of 

this chapter with regard to the control 

period in 2014 and any subsequent year, 

any methodology under which the State 

or the permitting authority allocates or 

auctions TR SO2 Group 1 allowances 

and that— 

(i) Requires the State or the permitting 

authority to allocate and, if applicable, 

auction a total amount of TR SO2 Group 

1 allowances for such control period not 

exceeding the amount, under 

§§ 97.610(a) and 97.621 of this chapter 

for the State and such control period, of 

the TR SO2 Group 1 trading budget 

minus the sum of the Indian country 

new unit set-aside and the amount of 

any TR SO2 Group 1 allowances already 

allocated and recorded by the 

Administrator. 

(ii) Requires, to the extent the State 

adopts provisions for allocations or 

auction of TR SO2 Group 1 allowances 

for any such control period to any TR 


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SO2 Group 1 units covered by 

§ 97.611(a) of this chapter, that the State 

or the permitting authority submit such 

allocations or the results of such 

auctions for such control period (except 

allocations or results of auctions to such 

units of TR SO2 Group 1 allowances 

remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator no later 

than the following dates: 

Year of the control 

period for which TR 

SO2 Group 1 allowances are allocated or 

auctioned 

Deadline for submission of allocations or 

auction results to 

administrator 

2014 .......................... June 1, 2013. 

2015 .......................... June 1, 2013. 

2016 .......................... June 1, 2014. 

2017 .......................... June 1, 2014. 

2018 .......................... June 1, 2015. 

2019 .......................... June 1, 2015. 

2020 and any year 

thereafter.

June 1 of the fourth 

year before the 

year of the control 

period. 

(iii) Requires, to the extent the State 

adopts provisions for allocations or 

auctions of TR SO2 Group 1 allowances 

for any such control period to any TR 

SO2 Group 1 units covered by 

§§ 97.611(b)(1) and 97.612(a) of this 

chapter, that the State or the permitting 

authority submit such allocations or the 

results of such auctions (except 

allocations or results of auctions to such 

units of TR SO2 Group 1 allowances 

remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator by July 1 

of the year of such control period. 

(iv) Does not provide for any change, 

after the submission deadlines in 

paragraphs (f)(2)(ii) and (iii) of this 

section, in the allocations submitted to 

the Administrator by such deadlines 

and does not provide for any change in 

any allocation determined and recorded 

by the Administrator under subpart 

CCCCC of part 97 of this chapter; 

(2) May adopt, in addition to the 

definitions in § 97.602 of this chapter, 

one or more definitions that shall apply 

only to terms as used in the TR SO2

Group 1 allowance allocation or auction 

provisions adopted under paragraph 

(f)(1) of this section; 

(3) May substitute the name of the 

State for the term ‘‘State’’ as used in 

subpart CCCCC of part 97 of this 

chapter, to the extent the Administrator 

determines that such substitutions do 

not make substantive changes in the 

provisions in §§ 97.602 through 97.635 

of this chapter; and 

(4) Must not include any of the 

references to, or requirements imposed 

on, any unit in Indian country within 

the borders of the State in the provisions 

in §§ 97.602 through 97.635 of this 

chapter and must not include the 

provisions in §§ 97.611(b)(2) and 

97.612(b), all of which provisions will 

continue to apply under the portion of 

the TR Federal Implementation Plan 

that is not replaced by the SIP revision; 

(5) Provided that, if and when any 

covered unit is located in Indian 

country within the borders of the State, 

the Administrator may modify his or her 

approval of the SIP revision to exclude 

the provisions in §§ 97.602 (definitions 

of ‘‘common designated representative’’, 

‘‘common designated representative’s 

assurance level’’, and ‘‘common 

designated representative’s share’’), 

97.606(c)(2), 97.625, and the portions of 

other provisions referencing these 

sections and may modify the portion of 

the TR Federal Implementation Plan 

that is not replaced by the SIP revision 

to include these provisions; 

(6) Provided that the State must 

submit a complete SIP revision meeting 

the requirements of paragraphs (f)(1) 

through (4) of this section by December 

1 of the year before the year of the 

deadlines for submission of allocations 

or auction results under paragraphs 

(f)(1)(ii) and (iii) of this section 

applicable to the first control period for 

which the State wants to make 

allocations or hold an auction under 

paragraph (f)(1)(ii) and (iii) of this 

section. 

(g) Notwithstanding the provisions of 

paragraph (a) of this section, a State 

listed in paragraph (c) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, as TR SO2 Group 2 allowance 

allocation provisions replacing the 

provisions in § 97.711(a) of this chapter 

with regard to the control period in 

2013, a list of TR SO2 Group 2 units and 

the amount of TR SO2 Group 2 

allowances allocated to each unit on 

such list, provided that the list of units 

and allocations meets the following 

requirements: 

(1) All of the units on the list must be 

units that are in the State and 

commenced commercial operation 

before January 1, 2010; 

(2) The total amount of TR SO2 Group 

2 allowance allocations on the list must 

not exceed the amount, under 

§ 97.710(a) of this chapter for the State 

and the control period in 2013, of TR 

SO2 Group 2 trading budget minus the 

sum of the new unit set-aside and 

Indian country new unit set-aside; 

(3) The list must be submitted 

electronically in a format specified by 

the Administrator; and 

(4) The SIP revision must not provide 

for any change in the units and 

allocations on the list after approval of 

the SIP revision by the Administrator 

and must not provide for any change in 

any allocation determined and recorded 

by the Administrator under subpart 

DDDDD of part 97 of this chapter; 

(5) Provided that: 

(i) By October 17, 2011, 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 

(ii) The State must submit to the 

Administrator a complete SIP revision 

described in paragraph (g)(5)(i) of this 

section by April 1, 2012. 

(h) Notwithstanding the provisions of 

paragraph (a) of this section, a State 

listed in paragraph (c) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, regulations revising subpart 

DDDDD of part 97 of this chapter as 

follows and not making any other 

substantive revisions of that subpart: 

(1) The State may adopt, as TR SO2

Group 2 allowance allocation or auction 

provisions replacing the provisions in 

§§ 97.711(a) and (b)(1) and 97.712(a) of 

this chapter with regard to the control 

period in 2014 and any subsequent year, 

any methodology under which the State 

or the permitting authority allocates or 

auctions TR SO2 Group 2 allowances 

and may adopt, in addition to the 

definitions in § 97.702 of this chapter, 

one or more definitions that shall apply 

only to terms as used in the adopted TR 

SO2 Group 2 allowance allocation or 

auction provisions, if such 

methodology— 

(i) Requires the State or the permitting 

authority to allocate and, if applicable, 

auction a total amount of TR SO2 Group 

2 allowances for any such control 

period not exceeding the amount, under 

§§ 97.710(a) and 97.721 of this chapter 

for the State and such control period, of 

the TR SO2 Group 2 trading budget 

minus the sum of the Indian country 

new unit set-aside and the amount of 

any TR SO2 Group 2 allowances already 

allocated and recorded by the 

Administrator. 

(ii) Requires, to the extent the State 

adopts provisions for allocations or 

auction of TR SO2 Group 2 allowances 

for any such control period to any TR 

SO2 Group 2 units covered by 

§ 97.711(a) of this chapter, that the State 

or the permitting authority submit such 


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48360 Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations 

allocations or the results of such 

auctions for such control period (except 

allocations or results of auctions to such 

units of TR SO2 Group 2 allowances 

remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator no later 

than the following dates: 

Year of the control 

period for which TR 

SO2 Group 2 allowances are allocated or 

auctioned 

Deadline for submission of allocations or 

auction results to 

administrator 

2014 .......................... June 1, 2013. 

2015 .......................... June 1, 2013. 

2016 .......................... June 1, 2014. 

2017 .......................... June 1, 2014. 

2018 .......................... June 1, 2015. 

2019 .......................... June 1, 2015. 

2020 and any year 

thereafter.

June 1 of the fourth 

year before the 

year of the control 

period. 

(iii) Requires, to the extent the State 

adopts provisions for allocations or 

auctions of TR SO2 Group 2 allowances 

for any such control period to any TR 

SO2 Group 2 units covered by 

§§ 97.711(b)(1) and 97.712(a) of this 

chapter, that the State or the permitting 

authority submit such allocations or the 

results of such auctions (except 

allocations or results of auctions to such 

units of TR SO2 Group 2 allowances 

remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator by July 1 

of the year of such control period. 

(iv) Does not provide for any change, 

after the submission deadlines in 

paragraphs (h)(1)(ii) and (iii) of this 

section, in the allocations submitted to 

the Administrator by such deadlines 

and does not provide for any change in 

any allocation determined and recorded 

by the Administrator under subpart 

DDDDD of part 97 of this chapter; 

(2) Provided that the State must 

submit a complete SIP revision meeting 

the requirements of paragraph (h)(1) of 

this section by December 1 of the year 

before the year of the deadlines for 

submission of allocations or auction 

results under paragraphs (h)(1)(ii) and 

(iii) of this section applicable to the first 

control period for which the State wants 

to make allocations or hold an auction 

under paragraph (h)(1)(ii) and (iii) of 

this section. 

(i) Notwithstanding the provisions of 

paragraph (a) of this section, a State 

listed in paragraph (c) of this section 

may adopt and include in a SIP 

revision, and the Administrator will 

approve, as correcting in whole or in 

part, as appropriate, the deficiency in 

the SIP that is the basis for the TR 

Federal Implementation Plan set forth in 

paragraphs (a), (c), (g), and (h) of this 

section, regulations that are 

substantively identical to the provisions 

of the TR SO2 Group 2 Trading Program 

set forth in §§ 97.702 through 97.735 of 

this chapter, except that the SIP 

revision: 

(1) May adopt, as TR SO2 Group 2 

allowance allocation or auction 

provisions replacing the provisions in 

§§ 97.711(a) and (b)(1) and 97.712(a) of 

this chapter with regard to the control 

period in 2014 and any subsequent year, 

any methodology under which the State 

or the permitting authority allocates or 

auctions TR SO2 Group 2 allowances 

and that— 

(i) Requires the State or the permitting 

authority to allocate and, if applicable, 

auction a total amount of TR SO2 Group 

2 allowances for any such control 

period not exceeding the amount, under 

§§ 97.710(a) and 97.721 of this chapter 

for the State and such control period, of 

the TR SO2 Group 2 trading budget 

minus the sum of the Indian country 

new unit set-aside and the amount of 

any TR SO2 Group 2 allowances already 

allocated and recorded by the 

Administrator. 

(ii) Requires, to the extent the State 

adopts provisions for allocations or 

auction of TR SO2 Group 2 allowances 

for any such control period to any TR 

SO2 Group 2 units covered by 

§ 97.711(a) of this chapter, that the State 

or the permitting authority submit such 

allocations or the results of such 

auctions for such control period (except 

allocations or results of auctions to such 

units of TR SO2 Group 1 allowances 

remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator no later 

than the following dates: 

Year of the control 

period for which TR 

SO2 Group 2 allowances are allocated or 

auctioned 

Deadline for submission of allocations or 

auction results to 

administrator 

2014 .......................... June 1, 2013. 

2015 .......................... June 1, 2013. 

2016 .......................... June 1, 2014. 

2017 .......................... June 1, 2014. 

2018 .......................... June 1, 2015. 

2019 .......................... June 1, 2015. 

2020 and any year 

thereafter.

June 1 of the fourth 

year before the 

year of the control 

period. 

(iii) Requires, to the extent the State 

adopts provisions for allocations or 

auctions of TR SO2 Group 2 allowances 

for any such control period to any TR 

SO2 Group 2 units covered by 

§§ 97.711(b)(1) and 97.712(a) of this 

chapter, that the State or the permitting 

authority submit such allocations or the 

results of such auctions (except 

allocations or results of auctions to such 

units of TR SO2 Group 2 allowances 

remaining in a set-aside after 

completion of the allocations or 

auctions for which the set-aside was 

created) to the Administrator by July 1 

of the year of such control period. 

(iv) Does not provide for any change, 

after the submission deadlines in 

paragraphs (i)(1)(ii) and (iii) of this 

section, in the allocations submitted to 

the Administrator by such deadlines 

and does not provide for any change in 

any allocation determined and recorded 

by the Administrator under subpart 

DDDDD of part 97 of this chapter; 

(2) May adopt, in addition to the 

definitions in § 97.702 of this chapter, 

one or more definitions that shall apply 

only to terms as used in the TR SO2

Group 2 allowance allocation or auction 

provisions adopted under paragraph 

(i)(1) of this section; 

(3) May substitute the name of the 

State for the term ‘‘State’’ as used in 

subpart DDDDD of part 97 of this 

chapter, to the extent the Administrator 

determines that such substitutions do 

not make substantive changes in the 

provisions in §§ 97.702 through 97.735 

of this chapter; and 

(4) Must not include any of the 

references to, or requirements imposed 

on, any unit in Indian country within 

the borders of the State in the provisions 

in §§ 97.702 through 97.735 of this 

chapter and must not include the 

provisions in §§ 97.711(b)(2) and 

97.712(b), all of which provisions will 

continue to apply under the portion of 

the TR Federal Implementation Plan 

that is not replaced by the SIP revision; 

(5) Provided that, if and when any 

covered unit is located in Indian 

country within the borders of the State, 

the Administrator may modify his or her 

approval of the SIP revision to exclude 

the provisions in §§ 97.702 (definitions 

of ‘‘common designated representative’’, 

‘‘common designated representative’s 

assurance level’’, and ‘‘common 

designated representative’s share’’), 

97.706(c)(2), 97.725, and the portions of 

other provisions referencing these 

sections and may modify the portion of 

the TR Federal Implementation Plan 

that is not replaced by the SIP revision 

to include these provisions; 

(6) Provided that the State must 

submit a complete SIP revision meeting 

the requirements of paragraphs (i)(1) 

through (4) of this section by December 

1 of the year before the year of the 

deadlines for submission of allocations 

or auction results under paragraphs 


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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations 48361 

(i)(1)(ii) and (iii) of this section 

applicable to the first control period for 

which the State wants to make 

allocations or hold an auction under 

paragraphs (i)(1)(ii) and (iii) of this 

section. 

(j) Following promulgation of an 

approval by the Administrator of a 

State’s SIP revision as correcting in 

whole or in part, as appropriate, the 

SIP’s deficiency that is the basis for the 

TR Federal Implementation Plan, the 

provisions of paragraph (b) and (c) of 

this section, as applicable, will no 

longer apply to sources in the State, 

unless the Administrator’s approval of 

the SIP revision is partial or conditional, 

and will continue to apply to sources in 

any Indian country within the borders 

of the State. 

(k) Notwithstanding the provisions of 

paragraph (j) of this section, if, at the 

time of such approval of the State’s SIP 

revision, the Administrator has already 

started recording any allocations of TR 

SO2 Group 1 allowances under subpart 

CCCCC of part 97 of this chapter, or 

allocations of TR SO2 Group 2 

allowances under subpart DDDDD of 

part 97 of this chapter, to units in a 

State for a control period in any year, 

the provisions of subpart CCCCC of part 

97 of this chapter authorizing the 

Administrator to complete the 

allocation and recordation of TR SO2

Group 1 allowances, or of subpart 

DDDDD of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 2 allowances, as 

applicable, to units in the State for each 

such control period shall continue to 

apply, unless provided otherwise by 

such approval of the State’s SIP 

revision. 

Subpart B—Alabama 

■ 10. Section 52.54 is added to read as 

follows: 

§ 52.54 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of Alabama and for which requirements 

are set forth under the TR NOX Annual 

Trading Program in subpart AAAAA of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Alabama’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.38(a), except to the extent the 

Administrator’s approval is partial or 

conditional. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of Alabama’s SIP 

revision described in paragraph (a)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b)(1) The owner and operator of each 

source and each unit located in the State 

of Alabama and for which requirements 

are set forth under the TR NOX Ozone 

Season Trading Program in subpart 

BBBBB of part 97 of this chapter must 

comply with such requirements. The 

obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Alabama’s 

State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is 

the basis for the TR Federal 

Implementation Plan under § 52.38(b), 

except to the extent the Administrator’s 

approval is partial or conditional. 

(2) Notwithstanding the provisions of 

paragraph (b)(1) of this section, if, at the 

time of the approval of the Alabama’s 

SIP revision described in paragraph 

(b)(1) of this section, the Administrator 

has already started recording any 

allocations of TR NOX Ozone Season 

allowances under subpart BBBBB of 

part 97 of this chapter to units in the 

State for a control period in any year, 

the provisions of subpart BBBBB of part 

97 of this chapter authorizing the 

Administrator to complete the 

allocation and recordation of TR NOX

Ozone Season allowances to units in the 

State for each such control period shall 

continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

■ 11. Section 52.55 is added to read as 

follows: 

§ 52.55 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of Alabama and for which requirements 

are set forth under the TR SO2 Group 2 

Trading Program in subpart DDDDD of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Alabama’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.39, except to the extent the 

Administrator’s approval is partial or 

conditional. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Alabama’s SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 2 allowances under 

subpart DDDDD of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart DDDDD of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 2 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart E—Arkansas 

■ 12. Section 52.184 is added to read as 

follows: 

§ 52.184 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a) The owner and operator of each 

source and each unit located in the State 

of Arkansas and for which requirements 

are set forth under the TR NOX Ozone 

Season Trading Program in subpart 

BBBBB of part 97 of this chapter must 

comply with such requirements. The 

obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Arkansas’ 

State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is 

the basis for the TR Federal 

Implementation Plan under § 52.38(b), 

except to the extent the Administrator’s 

approval is partial or conditional. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Arkansas’ SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 


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units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

Subpart 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: 

(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 November 7, 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 holding or surrender of 

CAIR NOX allowances will be required 

with regard to emissions or excess 

emissions for such control periods; and 

(4) By November 7, 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 

holding or surrender of CAIR NOX

Ozone Season allowances will be 

required with regard to emissions or 

excess emissions for such control 

periods. 

■ 14. Section 52.441 is amended by 

designating the existing text as 

paragraph (a) and adding a new 

paragraph (b) to read as follows: 

§ 52.441 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

Subpart J—District of Columbia 

■ 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 

(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 November 7, 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 holding or surrender of 

CAIR NOX allowances will be required 

with regard to emissions or excess 

emissions for such control periods; and 

(4) By November 7, 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 

holding or surrender of CAIR NOX

Ozone Season allowances will be 

required with regard to emissions or 

excess emissions for such control 

periods. 

■ 16. Section 52.485 is amended by 

designating the existing text as 

paragraph (a) and adding a new 

paragraph (b) to read as follows: 

§ 52.485 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

Subpart 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 Indian country within the 

borders of the State and for which 

requirements are set forth under the TR 

NOX Ozone Season Trading Program in 

subpart BBBBB of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements with regard to sources and 

units located in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Florida’s State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.38(b), except to the 

extent the Administrator’s approval is 

partial or conditional. The obligation to 

comply with such requirements with 

regard to sources and units located in 

Indian country within the borders of the 

State will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Florida’s 

SIP. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 


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time of the approval of Florida’s SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

Subpart L—Georgia 

■ 18. Section 52.584 is added to read as 

follows: 

§ 52.584 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of Georgia and for which requirements 

are set forth under the TR NOX Annual 

Trading Program in subpart AAAAA of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Georgia’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.38(a), except to the extent the 

Administrator’s approval is partial or 

conditional. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of Georgia’s SIP 

revision described in paragraph (a)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b)(1) The owner and operator of each 

source and each unit located in the State 

of Georgia and for which requirements 

are set forth under the TR NOX Ozone 

Season Trading Program in subpart 

BBBBB of part 97 of this chapter must 

comply with such requirements. The 

obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Georgia’s 

State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is 

the basis for the TR Federal 

Implementation Plan under § 52.38(b), 

except to the extent the Administrator’s 

approval is partial or conditional. 

(2) Notwithstanding the provisions of 

paragraph (b)(1) of this section, if, at the 

time of the approval of Georgia’s SIP 

revision described in paragraph (b)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

■ 19. Section 52.585 is added to read as 

follows: 

§ 52.585 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of Georgia and for which requirements 

are set forth under the TR SO2 Group 2 

Trading Program in subpart DDDDD of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Georgia’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.39, except to the extent the 

Administrator’s approval is partial or 

conditional. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Georgia’s SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 2 allowances under 

subpart DDDDD of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart DDDDD of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 2 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart O—Illinois 

■ 20. Section 52.745 is added to read as 

follows: 

§ 52.745 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of Illinois and for which requirements 

are set forth under the TR NOX Annual 

Trading Program in subpart AAAAA of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Illinois’ State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.38(a), except to the extent the 

Administrator’s approval is partial or 

conditional. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of Illinois’ SIP 

revision described in paragraph (a)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b)(1) The owner and operator of each 

source and each unit located in the State 

of Illinois and for which requirements 

are set forth under the TR NOX Ozone 

Season Trading Program in subpart 

BBBBB of part 97 of this chapter must 

comply with such requirements. The 

obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Illinois’ 

State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is 

the basis for the TR Federal 

Implementation Plan under § 52.38(b), 

except to the extent the Administrator’s 

approval is partial or conditional. 

(2) Notwithstanding the provisions of 

paragraph (b)(1) of this section, if, at the 

time of the approval of Illinois’ SIP 

revision described in paragraph (b)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 


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chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

■ 21. Section 52.746 is added to read as 

follows: 

§ 52.746 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of Illinois and for which requirements 

are set forth under the TR SO2 Group 1 

Trading Program in subpart CCCCC of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Illinois’ State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.39, except to the extent the 

Administrator’s approval is partial or 

conditional. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Illinois’ SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart P—Indiana 

■ 22. Section 52.789 is added to read as 

follows: 

§ 52.789 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of Indiana and for which requirements 

are set forth under the TR NOX Annual 

Trading Program in subpart AAAAA of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Indiana’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.38(a), except to the extent the 

Administrator’s approval is partial or 

conditional. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of Indiana’s SIP 

revision described in paragraph (a)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b)(1) The owner and operator of each 

source and each unit located in the State 

of Indiana and for which requirements 

are set forth under the TR NOX Ozone 

Season Trading Program in subpart 

BBBBB of part 97 of this chapter must 

comply with such requirements. The 

obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Indiana’s 

State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is 

the basis for the TR Federal 

Implementation Plan under § 52.38(b), 

except to the extent the Administrator’s 

approval is partial or conditional. 

(2) Notwithstanding the provisions of 

paragraph (b)(1) of this section, if, at the 

time of the approval of Indiana’s SIP 

revision described in paragraph (b)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

■ 23. Section 52.790 is added to read as 

follows: 

§ 52.790 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of Indiana and for which requirements 

are set forth under the TR SO2 Group 1 

Trading Program in subpart CCCCC of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Indiana’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.39 except to the extent the 

Administrator’s approval is partial or 

conditional. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Indiana’s SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart Q—Iowa 

■ 24. Section 52.840 is added to read as 

follows: 

§ 52.840 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of Iowa and Indian country within the 

borders of the State and for which 

requirements are set forth under the TR 

NOX Annual Trading Program in 

subpart AAAAA of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Iowa’s State Implementation 

Plan (SIP) as correcting in part the SIP’s 

deficiency that is the basis for the TR 

Federal Implementation Plan under 

§ 52.38(a), except to the extent the 

Administrator’s approval is partial or 

conditional. The obligation to comply 

with such requirements with regard to 


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sources and units located in Indian 

country within the borders of the State 

will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Iowa’s 

SIP. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of Iowa’s SIP 

revision described in paragraph (a)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b) [Reserved] 

■ 25. Section 52.841 is added to read as 

follows: 

§ 52.841 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of Iowa and Indian country within the 

borders of the State and for which 

requirements are set forth under the TR 

SO2 Group 1 Trading Program in 

subpart CCCCC of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements with regard to sources and 

units in the State will be eliminated by 

the promulgation of an approval by the 

Administrator of a revision to Iowa’s 

State Implementation Plan (SIP) as 

correcting in part the SIP’s deficiency 

that is the basis for the TR Federal 

Implementation Plan under § 52.39, 

except to the extent the Administrator’s 

approval is partial or conditional. The 

obligation to comply with such 

requirements with regard to sources and 

units located in Indian country within 

the borders of the State will not be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Iowa’s SIP. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Iowa’s SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart R—Kansas 

■ 26. Section 52.882 is added to read as 

follows: 

§ 52.882 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of Kansas and Indian country within the 

borders of the State and for which 

requirements are set forth under the TR 

NOX Annual Trading Program in 

subpart AAAAA of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Kansas’ State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.38(a), except to the 

extent the Administrator’s approval is 

partial or conditional. The obligation to 

comply with such requirements with 

regard to sources and units located in 

Indian country within the borders of the 

State will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Kansas’ 

SIP. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of Kansas’ SIP 

revision described in paragraph (a)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b) [Reserved] 

■ 27. Section 52.883 is added to read as 

follows: 

§ 52.883 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of Kansas and Indian country within the 

borders of the State and for which 

requirements are set forth under the TR 

SO2 Group 2 Trading Program in 

subpart DDDDD of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements will be 

eliminated with regard to sources and 

units in the State by the promulgation 

of an approval by the Administrator of 

a revision to Kansas’ State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.39, except to the extent 

the Administrator’s approval is partial 

or conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in Indian 

country within the borders of the State 

will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Kansas’ 

SIP. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Kansas’ SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 2 allowances under 

subpart DDDDD of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart DDDDD of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 2 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart S—Kentucky 

■ 28. Section 52.940 is added to read as 

follows: 

§ 52.940 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of Kentucky and for which requirements 

are set forth under the TR NOX Annual 

Trading Program in subpart AAAAA of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Kentucky’s State 


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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(a), except to the extent the 

Administrator’s approval is partial or 

conditional. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of Kentucky’s SIP 

revision described in paragraph (a)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b)(1) The owner and operator of each 

source and each unit located in the State 

of Kentucky and for which requirements 

are set forth under the TR NOX Ozone 

Season Trading Program in subpart 

BBBBB of part 97 of this chapter must 

comply with such requirements. The 

obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Kentucky’s State Implementation Plan 

(SIP) as correcting the SIP’s deficiency 

that is the basis for the TR Federal 

Implementation Plan under § 52.38(b), 

except to the extent the Administrator’s 

approval is partial or conditional. 

(2) Notwithstanding the provisions of 

paragraph (b)(1) of this section, if, at the 

time of the approval of Kentucky’s SIP 

revision described in paragraph (b)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

■ 29. Section 52.941 is added to read as 

follows: 

§ 52.941 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of Kentucky and for which requirements 

are set forth under the TR SO2 Group 1 

Trading Program in subpart CCCCC of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Kentucky’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.39, except to the extent the 

Administrator’s approval is partial or 

conditional. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Kentucky’s SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart T—Louisiana 

■ 30. Section 52.984 is amended by 

adding new paragraphs (c) and (d) to 

read as follows: 

§ 52.984 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c) Notwithstanding any provisions of 

paragraphs (a) and (b) of this section 

and subparts AA through II and AAAA 

through IIII of part 97 of this chapter to 

the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraphs (a) 

and (b) of this section relating to NOX

annual or ozone season emissions shall 

not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

and AAAA through IIII of part 97 of this 

chapter; 

(2) The Administrator will not deduct 

for excess emissions any CAIR NOX

allowances or CAIR NOX Ozone Season 

allowances allocated for 2012 or any 

year thereafter; 

(3) By November 7, 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 holding or surrender of 

CAIR NOX allowances will be required 

with regard to emissions or excess 

emissions for such control periods; and 

(4) By November 7, 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 

holding or surrender of CAIR NOX

Ozone Season allowances will be 

required with regard to emissions or 

excess emissions for such control 

periods. 

(d)(1) The owner and operator of each 

source and each unit located in the State 

of Louisiana and Indian country within 

the borders of the State and for which 

requirements are set forth under the TR 

NOX Ozone Season Trading Program in 

subpart BBBBB of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements with regard to sources and 

units in the State will be eliminated by 

the promulgation of an approval by the 

Administrator of a revision to 

Louisiana’s State Implementation Plan 

(SIP) as correcting in part the SIP’s 

deficiency that is the basis for the TR 

Federal Implementation Plan under 

§ 52.38(b), except to the extent the 

Administrator’s approval is partial or 

conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in Indian 

country within the borders of the State 

will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Louisiana’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (d)(1) of this section, if, at the 

time of the approval of Louisiana’s SIP 

revision described in paragraph (d)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

Subpart V—Maryland 

■ 31. Section 52.1084 is added to read 

as follows: 


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§ 52.1084 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of Maryland and for which requirements 

are set forth under the TR NOX Annual 

Trading Program in subpart AAAAA of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Maryland’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.38(a), except to the extent the 

Administrator’s approval is partial or 

conditional. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of Maryland’s SIP 

revision described in paragraph (a)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b)(1) The owner and operator of each 

source and each unit located in the State 

of Maryland and for which requirements 

are set forth under the TR NOX Ozone 

Season Trading Program in subpart 

BBBBB of part 97 of this chapter must 

comply with such requirements. The 

obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Maryland’s State Implementation Plan 

(SIP) as correcting the SIP’s deficiency 

that is the basis for the TR Federal 

Implementation Plan under § 52.38(b), 

except to the extent the Administrator’s 

approval is partial or conditional. 

(2) Notwithstanding the provisions of 

paragraph (b)(1) of this section, if, at the 

time of the approval of Maryland’s SIP 

revision described in paragraph (b)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

■ 32. Section 52.1085 is added to read 

as follows: 

§ 52.1085 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of Maryland and for which requirements 

are set forth under the TR SO2 Group 1 

Trading Program in subpart CCCCC of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Maryland’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.39, except to the extent the 

Administrator’s approval is partial or 

conditional. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Maryland’s SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart X—Michigan 

■ 33. Section 52.1186 is amended by 

adding new paragraphs (c) and (d) to 

read as follows: 

§ 52.1186 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c) Notwithstanding any provisions of 

paragraphs (a) and (b) of this section 

and subparts AA through II and AAAA 

through IIII of part 97 of this chapter to 

the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraphs (a) 

and (b) of this section relating to NOX

annual or ozone season emissions shall 

not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

and AAAA through IIII of part 97 of this 

chapter; 

(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 November 7, 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 holding or surrender of 

CAIR NOX allowances will be required 

with regard to emissions or excess 

emissions for such control periods; and 

(4) By November 7, 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 

holding or surrender of CAIR NOX

Ozone Season allowances will be 

required with regard to emissions or 

excess emissions for such control 

periods. 

(d)(1) The owner and operator of each 

source and each unit located in the State 

of Michigan and Indian country within 

the borders of the State and for which 

requirements are set forth under the TR 

NOX Annual Trading Program in 

subpart AAAAA of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Michigan’s State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.38(a), except to the 

extent the Administrator’s approval is 

partial or conditional. The obligation to 

comply with such requirements with 

regard to sources and units located in 

Indian country within the borders of the 

State will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Michigan’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (d)(1) of this section, if, at the 

time of the approval of Michigan’s SIP 

revision described in paragraph (d)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 


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48368 Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(e) [Reserved] 

■ 34. Section 52.1187 is amended by 

designating the existing text as 

paragraph (a) and adding new 

paragraphs (b) and (c) to read as follows: 

§ 52.1187 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

(c)(1) The owner and operator of each 

source and each unit located in the State 

of Michigan and Indian country within 

the borders of the State and for which 

requirements are set forth under the TR 

SO2 Group 1 Trading Program in 

subpart CCCCC of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements with regard to sources and 

units in the State will be eliminated by 

the promulgation of an approval by the 

Administrator of a revision to 

Michigan’s State Implementation Plan 

(SIP) as correcting in part the SIP’s 

deficiency that is the basis for the TR 

Federal Implementation Plan under 

§ 52.39, except to the extent the 

Administrator’s approval is partial or 

conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in Indian 

country within the borders of the State 

will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Michigan’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (c)(1) of this section, if, at the 

time of the approval of Maryland’s SIP 

revision described in paragraph (c)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart Y—Minnesota 

■ 35. Section 52.1240 is amended by 

adding paragraph (c) to read as follows: 

§ 52.1240 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c)(1) The owner and operator of each 

source and each unit located in the State 

of Minnesota and Indian country within 

the borders of the State and for which 

requirements are set forth under the TR 

NOX Annual Trading Program in 

subpart AAAAA of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Minnesota’s State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.38(a), except to the 

extent the Administrator’s approval is 

partial or conditional. The obligation to 

comply with such requirements with 

regard to sources and units located in 

Indian country within the borders of the 

State will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Minnesota’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (c)(1) of this section, if, at the 

time of the approval of Minnesota’s SIP 

revision described in paragraph (c)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

■ 36. Section 52.1241 is amended by 

adding paragraph (c) to read as follows: 

§ 52.1241 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(c)(1) The owner and operator of each 

source and each unit located in the State 

of Minnesota and Indian country within 

the borders of the State and for which 

requirements are set forth under the TR 

SO2 Group 2 Trading Program in 

subpart DDDDD of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Minnesota’s State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.39, except to the extent 

the Administrator’s approval is partial 

or conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in Indian 

country within the borders of the State 

will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Minnesota’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (c)(1) of this section, if, at the 

time of the approval of Minnesota’s SIP 

revision described in paragraph (c)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 2 allowances under 

subpart DDDDD of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart DDDDD of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 2 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart Z—Mississippi 

■ 37. Section 52.1284 is added to read 

as follows: 

§ 52.1284 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a) The owner and operator of each 

source and each unit located in the State 

of Mississippi and Indian country 

within the borders of the State and for 

which requirements are set forth under 

the TR NOX Ozone Season Trading 

Program in subpart BBBBB of part 97 of 


ebenthall on DSK6TPTVN1PROD with RULES2
Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations 48369 

this chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Mississippi’s State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.38(b), except to the 

extent the Administrator’s approval is 

partial or conditional. The obligation to 

comply with such requirements with 

regard to sources and units located in 

Indian country within the borders of the 

State will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Mississippi’s SIP. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Mississippi’s SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

Subpart AA—Missouri 

■ 38. Section 52.1326 is added to read 

as follows: 

§ 52.1326 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of Missouri and for which requirements 

are set forth under the TR NOX Annual 

Trading Program in subpart AAAAA of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Missouri’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.38(a), except to the extent the 

Administrator’s approval is partial or 

conditional. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of Missouri’s SIP 

revision described in paragraph (a)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b) [Reserved] 

■ 39. Section 52.1327 is added to read 

as follows: 

§ 52.1327 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of Missouri and for which requirements 

are set forth under the TR SO2 Group 1 

Trading Program in subpart CCCCC of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Missouri’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.39, except to the extent the 

Administrator’s approval is partial or 

conditional. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Missouri’s SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart CC—Nebraska 

■ 40. Section 52.1428 is added to read 

as follows: 

§ 52.1428 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a) The owner and operator of each 

source and each unit located in the State 

of Nebraska and Indian country within 

the borders of the State and for which 

requirements are set forth under the TR 

NOX Annual Trading Program in 

subpart AAAAA of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Nebraska’s State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.38(a), except to the 

extent the Administrator’s approval is 

partial or conditional. The obligation to 

comply with such requirements with 

regard to sources and units located in 

Indian country within the borders of the 

State will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Nebraska’s SIP. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Nebraska’s SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

■ 41. Section 52.1429 is added to read 

as follows: 

§ 52.1429 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of Nebraska and Indian country within 

the borders of the State and for which 

requirements are set forth under the TR 

SO2 Group 2 Trading Program in 

subpart DDDDD of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Nebraska’s State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.39, except to the extent 

the Administrator’s approval is partial 

or conditional. The obligation to comply 

with such requirements with regard to 


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sources and units located in Indian 

country within the borders of the State 

will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Nebraska’s SIP. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Nebraska’s SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 2 allowances under 

subpart DDDDD of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart DDDDD of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 2 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart FF—New Jersey 

■ 42. Section 52.1584 is amended by 

adding new paragraphs (c), (d), and (e) 

to read as follows: 

§ 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 November 7, 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 holding or surrender of 

CAIR NOX allowances will be required 

with regard to emissions or excess 

emissions for such control periods; and 

(4) By November 7, 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 

holding or surrender of CAIR NOX

Ozone Season allowances will be 

required with regard to emissions or 

excess emissions for such control 

periods. 

(d)(1) The owner and operator of each 

source and each unit located in the State 

of New Jersey and for which 

requirements are set forth under the TR 

NOX Annual Trading Program in 

subpart AAAAA of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to New Jersey’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.38(a), except to the extent the 

Administrator’s approval is partial or 

conditional. 

(2) Notwithstanding the provisions of 

paragraph (d)(1) of this section, if, at the 

time of the approval of New Jersey’s SIP 

revision described in paragraph (d)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(e)(1) The owner and operator of each 

source and each unit located in the State 

of New Jersey and for which 

requirements are set forth under the TR 

NOX Ozone Season Trading Program in 

subpart BBBBB of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to New 

Jersey’s State Implementation Plan (SIP) 

as correcting the SIP’s deficiency that is 

the basis for the TR Federal 

Implementation Plan under § 52.38(b), 

except to the extent the Administrator’s 

approval is partial or conditional. 

(2) Notwithstanding the provisions of 

paragraph (e)(1) of this section, if, at the 

time of the approval of New Jersey’s SIP 

revision described in paragraph (e)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

■ 43. Section 52.1585 is amended by 

designating the existing text as 

paragraph (a) and adding new 

paragraphs (b) and (c) to read as follows: 

§ 52.1585 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

(c)(1) The owner and operator of each 

source and each unit located in the State 

of New Jersey and for which 

requirements are set forth under the TR 

SO2 Group 1 Trading Program in 

subpart CCCCC of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to New 

Jersey’s State Implementation Plan (SIP) 

as correcting the SIP’s deficiency that is 

the basis for the TR Federal 

Implementation Plan under § 52.39, 

except to the extent the Administrator’s 

approval is partial or conditional. 

(2) Notwithstanding the provisions of 

paragraph (c)(1) of this section, if, at the 

time of the approval of New Jersey’s SIP 

revision described in paragraph (c)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 


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of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart HH—New York 

■ 44. Section 52.1684 is revised to read 

as follows: 

§ 52.1684 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of New York and Indian country within 

the borders of the State and for which 

requirements are set forth under the TR 

NOX Annual Trading Program in 

subpart AAAAA of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to New York’s State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.38(a), except to the 

extent the Administrator’s approval is 

partial or conditional. The obligation to 

comply with such requirements with 

regard to sources and units located in 

Indian country within the borders of the 

State will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to New 

York’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of New York’s SIP 

revision described in paragraph (a)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b)(1) The owner and operator of each 

source and each unit located in the State 

of New York and Indian country within 

the borders of the State and for which 

requirements are set forth under the TR 

NOX Ozone Season Trading Program in 

subpart BBBBB of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements with regard to sources and 

units in the State will be eliminated by 

the promulgation of an approval by the 

Administrator of a revision to New 

York’s State Implementation Plan (SIP) 

as correcting in part the SIP’s deficiency 

that is the basis for the TR Federal 

Implementation Plan under § 52.38(b), 

except to the extent the Administrator’s 

approval is partial or conditional. The 

obligation to comply with such 

requirements with regard to sources and 

units located in Indian country within 

the borders of the State will not be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to New York’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (b)(1) of this section, if, at the 

time of the approval of New York’s SIP 

revision described in paragraph (b)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

■ 45. Section 52.1685 is added to read 

as follows: 

§ 52.1685 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of New York and Indian country within 

the borders of the State and for which 

requirements are set forth under the TR 

SO2 Group 1 Trading Program in 

subpart CCCCC of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements with regard to sources and 

units in the State will be eliminated by 

the promulgation of an approval by the 

Administrator of a revision to New 

York’s State Implementation Plan (SIP) 

as correcting in part the SIP’s deficiency 

that is the basis for the TR Federal 

Implementation Plan under § 52.39, 

except to the extent the Administrator’s 

approval is partial or conditional. The 

obligation to comply with such 

requirements with regard to sources and 

units located in Indian country within 

the borders of the State will not be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to New York’s SIP. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of New York’s SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart II—North Carolina 

■ 46. Section 52.1784 is revised to read 

as follows: 

§ 52.1784 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of North Carolina and Indian country 

within the borders of the State and for 

which requirements are set forth under 

the TR NOX Annual Trading Program in 

subpart AAAAA of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to North Carolina’s State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.38(a), except to the 

extent the Administrator’s approval is 

partial or conditional. The obligation to 

comply with such requirements with 

regard to sources and units located in 

Indian country within the borders of the 

State will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to North 

Carolina’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of North Carolina’s 

SIP revision described in paragraph 

(a)(1) of this section, the Administrator 

has already started recording any 

allocations of TR NOX Annual 

allowances under subpart AAAAA of 

part 97 of this chapter to units in the 

State for a control period in any year, 

the provisions of subpart AAAAA of 

part 97 of this chapter authorizing the 

Administrator to complete the 

allocation and recordation of TR NOX

Annual allowances to units in the State 

for each such control period shall 


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48372 Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations 

continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b)(1) The owner and operator of each 

source and each unit located in the State 

of North Carolina and Indian country 

within the borders of the State and for 

which requirements are set forth under 

the TR NOX Ozone Season Trading 

Program in subpart BBBBB of part 97 of 

this chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to North Carolina’s State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.38(b), except to the 

extent the Administrator’s approval is 

partial or conditional. The obligation to 

comply with such requirements with 

regard to sources and units located in 

Indian country within the borders of the 

State will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to North 

Carolina’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (b)(1) of this section, if, at the 

time of the approval of North Carolina’s 

SIP revision described in paragraph 

(b)(1) of this section, the Administrator 

has already started recording any 

allocations of TR NOX Ozone Season 

allowances under subpart BBBBB of 

part 97 of this chapter to units in the 

State for a control period in any year, 

the provisions of subpart BBBBB of part 

97 of this chapter authorizing the 

Administrator to complete the 

allocation and recordation of TR NOX

Ozone Season allowances to units in the 

State for each such control period shall 

continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

■ 47. Section 52.1785 is revised to read 

as follows: 

§ 52.1785 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of North Carolina and Indian country 

within the borders of the State and for 

which requirements are set forth under 

the TR SO2 Group 1 Trading Program in 

subpart CCCCC of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements with regard to sources and 

units in the State will be eliminated by 

the promulgation of an approval by the 

Administrator of a revision to North 

Carolina’s State Implementation Plan 

(SIP) as correcting in part the SIP’s 

deficiency that is the basis for the TR 

Federal Implementation Plan under 

§ 52.39, except to the extent the 

Administrator’s approval is partial or 

conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in Indian 

country within the borders of the State 

will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to North 

Carolina’s SIP. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of North Carolina’s 

SIP revision described in paragraph (a) 

of this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart KK—Ohio 

■ 48. Section 52.1882 is added to read 

as follows: 

§ 52.1882 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of Ohio and for which requirements are 

set forth under the TR NOX Annual 

Trading Program in subpart AAAAA of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Ohio’s State Implementation 

Plan (SIP) as correcting the SIP’s 

deficiency that is the basis for the TR 

Federal Implementation Plan under 

§ 52.38(a), except to the extent the 

Administrator’s approval is partial or 

conditional. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of Ohio’s SIP 

revision described in paragraph (a)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b)(1) The owner and operator of each 

source and each unit located in the State 

of Ohio and for which requirements are 

set forth under the TR NOX Ozone 

Season Trading Program in subpart 

BBBBB of part 97 of this chapter must 

comply with such requirements. The 

obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Ohio’s 

State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is 

the basis for the TR Federal 

Implementation Plan under § 52.38(b), 

except to the extent the Administrator’s 

approval is partial or conditional. 

(2) Notwithstanding the provisions of 

paragraph (b)(1) of this section, if, at the 

time of the approval of Ohio’s SIP 

revision described in paragraph (b)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

■ 49. Section 52.1883 is added to read 

as follows: 

§ 52.1883 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of Ohio and for which requirements are 

set forth under the TR SO2 Group 1 

Trading Program in subpart CCCCC of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Ohio’s State Implementation 

Plan (SIP) as correcting the SIP’s 

deficiency that is the basis for the TR 

Federal Implementation Plan under 

§ 52.39, except to the extent the 

Administrator’s approval is partial or 

conditional. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Ohio’s SIP 


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revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart NN—Pennsylvania 

■ 50. Section 52.2040 is added to read 

as follows: 

§ 52.2040 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of Pennsylvania and for which 

requirements are set forth under the TR 

NOX Annual Trading Program in 

subpart AAAAA of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Pennsylvania’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.38(a), except to the extent the 

Administrator’s approval is partial or 

conditional. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of Pennsylvania’s 

SIP revision described in paragraph 

(a)(1) of this section, the Administrator 

has already started recording any 

allocations of TR NOX Annual 

allowances under subpart AAAAA of 

part 97 of this chapter to units in the 

State for a control period in any year, 

the provisions of subpart AAAAA of 

part 97 of this chapter authorizing the 

Administrator to complete the 

allocation and recordation of TR NOX

Annual allowances to units in the State 

for each such control period shall 

continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b)(1) The owner and operator of each 

source and each unit located in the State 

of Pennsylvania and for which 

requirements are set forth under the TR 

NOX Ozone Season Trading Program in 

subpart BBBBB of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Pennsylvania’s State Implementation 

Plan (SIP) as correcting the SIP’s 

deficiency that is the basis for the TR 

Federal Implementation Plan under 

§ 52.38(b), except to the extent the 

Administrator’s approval is partial or 

conditional. 

(2) Notwithstanding the provisions of 

paragraph (b)(1) of this section, if, at the 

time of the approval of Pennsylvania’s 

SIP revision described in paragraph 

(b)(1) of this section, the Administrator 

has already started recording any 

allocations of TR NOX Ozone Season 

allowances under subpart BBBBB of 

part 97 of this chapter to units in the 

State for a control period in any year, 

the provisions of subpart BBBBB of part 

97 of this chapter authorizing the 

Administrator to complete the 

allocation and recordation of TR NOX

Ozone Season allowances to units in the 

State for each such control period shall 

continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

■ 51. Section 52.2041 is added to read 

as follows: 

§ 52.2041 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of Pennsylvania and for which 

requirements are set forth under the TR 

SO2 Group 1 Trading Program in 

subpart CCCCC of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Pennsylvania’s State Implementation 

Plan (SIP) as correcting the SIP’s 

deficiency that is the basis for the TR 

Federal Implementation Plan under 

§ 52.39, except to the extent the 

Administrator’s approval is partial or 

conditional. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Pennsylvania’s 

SIP revision described in paragraph (a) 

of this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart PP—South Carolina 

■ 52. Section 52.2140 is revised to read 

as follows: 

§ 52.2140 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of South Carolina and Indian country 

within the borders of the State and for 

which requirements are set forth under 

the TR NOX Annual Trading Program in 

subpart AAAAA of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to South Carolina’s State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.38(a), except to the 

extent the Administrator’s approval is 

partial or conditional. The obligation to 

comply with such requirements with 

regard to sources and units located in 

Indian country within the borders of the 

State will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to South 

Carolina’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of South Carolina’s 

SIP revision described in paragraph 

(a)(1) of this section, the Administrator 

has already started recording any 

allocations of TR NOX Annual 

allowances under subpart AAAAA of 

part 97 of this chapter to units in the 

State for a control period in any year, 

the provisions of subpart AAAAA of 

part 97 of this chapter authorizing the 

Administrator to complete the 

allocation and recordation of TR NOX

Annual allowances to units in the State 

for each such control period shall 

continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b)(1) The owner and operator of each 

source and each unit located in the State 

of South Carolina and Indian country 

within the borders of the State and for 

which requirements are set forth under 

the TR NOX Ozone Season Trading 

Program in subpart BBBBB of part 97 of 

this chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 


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eliminated by the promulgation of an 

approval by the Administrator of a 

revision to South Carolina’s State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.38(b), except to the 

extent the Administrator’s approval is 

partial or conditional. The obligation to 

comply with such requirements with 

regard to sources and units located in 

Indian country within the borders of the 

State will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to South 

Carolina’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (b)(1) of this section, if, at the 

time of the approval of South Carolina’s 

SIP revision described in paragraph 

(b)(1) of this section, the Administrator 

has already started recording any 

allocations of TR NOX Ozone Season 

allowances under subpart BBBBB of 

part 97 of this chapter to units in the 

State for a control period in any year, 

the provisions of subpart BBBBB of part 

97 of this chapter authorizing the 

Administrator to complete the 

allocation and recordation of TR NOX

Ozone Season allowances to units in the 

State for each such control period shall 

continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

■ 53. Section 52.2141 is revised to read 

as follows: 

§ 52.2141 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of South Carolina and Indian country 

within the borders of the State and for 

which requirements are set forth under 

the TR SO2 Group 2 Trading Program in 

subpart DDDDD of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to South Carolina’s State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.39, except to the extent 

the Administrator’s approval is partial 

or conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in Indian 

country within the borders of the State 

will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to South 

Carolina’s SIP. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of South Carolina’s 

SIP revision described in paragraph (a) 

of this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart RR—Tennessee 

■ 54. Section 52.2240 is amended by 

adding new paragraphs (c), (d), and (e) 

to read as follows: 

§ 52.2240 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c) Notwithstanding any provisions of 

paragraphs (a) and (b) of this section 

and subparts AA through II and AAAA 

through IIII of part 97 of this chapter to 

the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraphs (a) 

and (b) of this section relating to NOX

annual or ozone season emissions shall 

not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

and AAAA through IIII of part 97 of this 

chapter; and 

(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 November 7, 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 holding or surrender of 

CAIR NOX allowances will be required 

with regard to emissions or excess 

emissions for such control periods; and 

(4) By November 7, 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 

holding or surrender of CAIR NOX

Ozone Season allowances will be 

required with regard to emissions or 

excess emissions for such control 

periods. 

(d)(1) The owner and operator of each 

source and each unit located in the State 

of Tennessee and for which 

requirements are set forth under the TR 

NOX Annual Trading Program in 

subpart AAAAA of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Tennessee’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.38(a), except to the extent the 

Administrator’s approval is partial or 

conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in Indian 

country within the borders of the State 

will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Tennessee’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (d)(1) of this section, if, at the 

time of the approval of Tennessee’s SIP 

revision described in paragraph (d)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(e)(1) The owner and operator of each 

source and each unit located in the State 

of Tennessee and for which 

requirements are set forth under the TR 

NOX Ozone Season Trading Program in 

subpart BBBBB of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Tennessee’s State Implementation Plan 

(SIP) as correcting the SIP’s deficiency 

that is the basis for the TR Federal 

Implementation Plan under § 52.38(b), 

except to the extent the Administrator’s 

approval is partial or conditional. The 

obligation to comply with such 

requirements with regard to sources and 

units located in Indian country within 

the borders of the State will not be 

eliminated by the promulgation of an 


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approval by the Administrator of a 

revision to Tennessee’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (e)(1) of this section, if, at the 

time of the approval of Tennessee’s SIP 

revision described in paragraph (e)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

■ 55. Section 52.2241 is amended by 

designating the existing text as 

paragraph (a) and adding new 

paragraphs (b) and (c) to read as follows: 

§ 52.2241 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

(c)(1) The owner and operator of each 

source and each unit located in the State 

of Tennessee and for which 

requirements are set forth under the TR 

SO2 Group 1 Trading Program in 

subpart CCCCC of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Tennessee’s State Implementation Plan 

(SIP) as correcting the SIP’s deficiency 

that is the basis for the TR Federal 

Implementation Plan under § 52.39, 

except to the extent the Administrator’s 

approval is partial or conditional. The 

obligation to comply with such 

requirements with regard to sources and 

units located in Indian country within 

the borders of the State will not be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Tennessee’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (c)(1) of this section, if, at the 

time of the approval of Tennessee’s SIP 

revision described in paragraph (c)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart SS—Texas 

■ 56. Section 52.2283 is amended by 

adding new paragraphs (b), (c) and (d) 

to read as follows: 

§ 52.2283 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AA through II of part 97 of this 

chapter to the contrary: 

(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 November 7, 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 holding or surrender of 

CAIR NOX allowances will be required 

with regard to emissions or excess 

emissions for such control periods. 

(c)(1) The owner and operator of each 

source and each unit located in the State 

of Texas and Indian country within the 

borders of the State and for which 

requirements are set forth under the TR 

NOX Annual Trading Program in 

subpart AAAAA of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Texas’ State Implementation 

Plan (SIP) as correcting in part the SIP’s 

deficiency that is the basis for the TR 

Federal Implementation Plan under 

§ 52.38(a), except to the extent the 

Administrator’s approval is partial or 

conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in Indian 

country within the borders of the State 

will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Texas’ 

SIP. 

(2) Notwithstanding the provisions of 

paragraph (c)(1) of this section, if, at the 

time of the approval of Texas’ SIP 

revision described in paragraph (c)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(d)(1) The owner and operator of each 

source and each unit located in the State 

of Texas and Indian country within the 

borders of the State and for which 

requirements are set forth under the TR 

NOX Ozone Season Trading Program in 

subpart BBBBB of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements with regard to sources and 

units in the State will be eliminated by 

the promulgation of an approval by the 

Administrator of a revision to Texas’ 

State Implementation Plan (SIP) as 

correcting in part the SIP’s deficiency 

that is the basis for the TR Federal 

Implementation Plan under § 52.38(b), 

except to the extent the Administrator’s 

approval is partial or conditional. The 

obligation to comply with such 

requirements with regard to sources and 

units located in Indian country within 

the borders of the State will not be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Texas’ SIP. 

(2) Notwithstanding the provisions of 

paragraph (d)(1) of this section, if, at the 

time of the approval of Texas’ SIP 

revision described in paragraph (d)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 


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chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

■ 57. Section 52.2284 is amended by 

designating the existing text as 

paragraph (a) and adding new 

paragraphs (b) and (c) to read as follows: 

§ 52.2284 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

(c)(1) The owner and operator of each 

source and each unit located in the State 

of Texas and Indian country within the 

borders of the State and for which 

requirements are set forth under the TR 

SO2 Group 2 Trading Program in 

subpart DDDDD of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Texas’ State Implementation 

Plan (SIP) as correcting in part the SIP’s 

deficiency that is the basis for the TR 

Federal Implementation Plan under 

§ 52.39, except to the extent the 

Administrator’s approval is partial or 

conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in Indian 

country within the borders of the State 

will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Texas’ 

SIP. 

(2) Notwithstanding the provisions of 

paragraph (c)(1) of this section, if, at the 

time of the approval of Texas’ SIP 

revision described in paragraph (c)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 2 allowances under 

subpart DDDDD of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart DDDDD of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 2 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart VV—Virginia 

■ 58. Section 52.2440 is added to read 

as follows: 

§ 52.2440 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of Virginia and for which requirements 

are set forth under the TR NOX Annual 

Trading Program in subpart AAAAA of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Virginia’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.38(a), except to the extent the 

Administrator’s approval is partial or 

conditional. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of Virginia’s SIP 

revision described in paragraph (a)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b)(1) The owner and operator of each 

source and each unit located in the State 

of Virginia and for which requirements 

are set forth under the TR NOX Ozone 

Season Trading Program in subpart 

BBBBB of part 97 of this chapter must 

comply with such requirements. The 

obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to Virginia’s 

State Implementation Plan (SIP) as 

correcting the SIP’s deficiency that is 

the basis for the TR Federal 

Implementation Plan under § 52.38(b), 

except to the extent the Administrator’s 

approval is partial or conditional. 

(2) Notwithstanding the provisions of 

paragraph (b)(1) of this section, if, at the 

time of the approval of Virginia’s SIP 

revision described in paragraph (b)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Ozone Season allowances 

under subpart BBBBB of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart BBBBB of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Ozone Season allowances to 

units in the State for each such control 

period shall continue to apply, unless 

provided otherwise by such approval of 

the State’s SIP revision. 

■ 59. Section 52.2241 is added to read 

as follows: 

§ 52.2241 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of Virginia and for which requirements 

are set forth under the TR SO2 Group 1 

Trading Program in subpart CCCCC of 

part 97 of this chapter must comply 

with such requirements. The obligation 

to comply with such requirements will 

be eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Virginia’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.39, except to the extent the 

Administrator’s approval is partial or 

conditional. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of Virginia’s SIP 

revision described in paragraph (a) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 


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Subpart XX—West Virginia 

■ 60. Section 52.2540 is added to read 

as follows: 

§ 52.2540 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

(a)(1) The owner and operator of each 

source and each unit located in the State 

of West Virginia and for which 

requirements are set forth under the TR 

NOX Annual Trading Program in 

subpart AAAAA of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to West Virginia’s State 

Implementation Plan (SIP) as correcting 

the SIP’s deficiency that is the basis for 

the TR Federal Implementation Plan 

under § 52.38(a), except to the extent the 

Administrator’s approval is partial or 

conditional. 

(2) Notwithstanding the provisions of 

paragraph (a)(1) of this section, if, at the 

time of the approval of West Virginia’s 

SIP revision described in paragraph 

(a)(1) of this section, the Administrator 

has already started recording any 

allocations of TR NOX Annual 

allowances under subpart AAAAA of 

part 97 of this chapter to units in the 

State for a control period in any year, 

the provisions of subpart AAAAA of 

part 97 of this chapter authorizing the 

Administrator to complete the 

allocation and recordation of TR NOX

Annual allowances to units in the State 

for each such control period shall 

continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

(b)(1) The owner and operator of each 

source and each unit located in the State 

of West Virginia and for which 

requirements are set forth under the TR 

NOX Ozone Season Trading Program in 

subpart BBBBB of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to West 

Virginia’s State Implementation Plan 

(SIP) as correcting the SIP’s deficiency 

that is the basis for the TR Federal 

Implementation Plan under § 52.38(b), 

except to the extent the Administrator’s 

approval is partial or conditional. 

(2) Notwithstanding the provisions of 

paragraph (b)(1) of this section, if, at the 

time of the approval of West Virginia’s 

SIP revision described in paragraph 

(b)(1) of this section, the Administrator 

has already started recording any 

allocations of TR NOX Ozone Season 

allowances under subpart BBBBB of 

part 97 of this chapter to units in the 

State for a control period in any year, 

the provisions of subpart BBBBB of part 

97 of this chapter authorizing the 

Administrator to complete the 

allocation and recordation of TR NOX

Ozone Season allowances to units in the 

State for each such control period shall 

continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

■ 61. Section 52.2541 is added to read 

as follows: 

§ 52.2541 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

(a) The owner and operator of each 

source and each unit located in the State 

of West Virginia and for which 

requirements are set forth under the TR 

SO2 Group 1 Trading Program in 

subpart CCCCC of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements will be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to West 

Virginia’s State Implementation Plan 

(SIP) as correcting the SIP’s deficiency 

that is the basis for the TR Federal 

Implementation Plan under § 52.39, 

except to the extent the Administrator’s 

approval is partial or conditional. 

(b) Notwithstanding the provisions of 

paragraph (a) of this section, if, at the 

time of the approval of West Virginia’s 

SIP revision described in paragraph (a) 

of this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

Subpart YY—Wisconsin 

■ 62. Section 52.2587 is amended by 

adding new paragraphs (c) and (d) to 

read as follows: 

§ 52.2587 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of nitrogen 

oxides? 

* * * * * 

(c) Notwithstanding any provisions of 

paragraphs (a) and (b) of this section 

and subparts AA through II and AAAA 

through IIII of part 97 of this chapter to 

the contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions in paragraphs (a) 

and (b) of this section relating to NOX

annual or ozone season emissions shall 

not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AA through II 

and AAAA through IIII of part 97 of this 

chapter; and 

(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 November 7, 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 holding or surrender of 

CAIR NOX allowances will be required 

with regard to emissions or excess 

emissions for such control periods; and 

(4) By November 7, 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 

holding or surrender of CAIR NOX

Ozone Season allowances will be 

required with regard to emissions or 

excess emissions for such control 

periods. 

(d)(1) The owner and operator of each 

source and each unit located in the State 

of Wisconsin and Indian country within 

the borders of the State and for which 

requirements are set forth under the TR 

NOX Annual Trading Program in 

subpart AAAAA of part 97 of this 

chapter must comply with such 

requirements. The obligation to comply 

with such requirements with regard to 

sources and units in the State will be 

eliminated by the promulgation of an 

approval by the Administrator of a 

revision to Wisconsin’s State 

Implementation Plan (SIP) as correcting 

in part the SIP’s deficiency that is the 

basis for the TR Federal Implementation 

Plan under § 52.38(a), except to the 

extent the Administrator’s approval is 

partial or conditional. The obligation to 

comply with such requirements with 

regard to sources and units located in 

Indian country within the borders of the 

State will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Wisconsin’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (d)(1) of this section, if, at the 


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time of the approval of Wisconsin’s SIP 

revision described in paragraph (d)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR NOX Annual allowances under 

subpart AAAAA of part 97 of this 

chapter to units in the State for a control 

period in any year, the provisions of 

subpart AAAAA of part 97 of this 

chapter authorizing the Administrator to 

complete the allocation and recordation 

of TR NOX Annual allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

■ 63. Section 52.2588 is amended by 

designating the existing text as 

paragraph (a) and adding new 

paragraphs (b) and (c) to read as follows: 

§ 52.2588 Interstate pollutant transport 

provisions; What are the FIP requirements 

for decreases in emissions of sulfur 

dioxide? 

* * * * * 

(b) Notwithstanding any provisions of 

paragraph (a) of this section and 

subparts AAA through III of part 97 of 

this chapter and any State’s SIP to the 

contrary: 

(1) With regard to any control period 

that begins after December 31, 2011, 

(i) The provisions of paragraph (a) of 

this section relating to SO2 emissions 

shall not be applicable; and 

(ii) The Administrator will not carry 

out any of the functions set forth for the 

Administrator in subparts AAA through 

III of part 97 of this chapter; and 

(2) The Administrator will not deduct 

for excess emissions any CAIR SO2

allowances allocated for 2012 or any 

year thereafter. 

(c)(1) The owner and operator of each 

source and each unit located in the State 

of Wisconsin and Indian country within 

the borders of the State and for which 

requirements are set forth under the TR 

SO2 Group 1 Trading Program in 

subpart CCCCC of part 97 of this chapter 

must comply with such requirements. 

The obligation to comply with such 

requirements with regard to sources and 

units in the State will be eliminated by 

the promulgation of an approval by the 

Administrator of a revision to 

Wisconsin’s State Implementation Plan 

(SIP) as correcting in part the SIP’s 

deficiency that is the basis for the TR 

Federal Implementation Plan under 

§ 52.39, except to the extent the 

Administrator’s approval is partial or 

conditional. The obligation to comply 

with such requirements with regard to 

sources and units located in Indian 

country within the borders of the State 

will not be eliminated by the 

promulgation of an approval by the 

Administrator of a revision to 

Wisconsin’s SIP. 

(2) Notwithstanding the provisions of 

paragraph (c)(1) of this section, if, at the 

time of the approval of Wisconsin’s SIP 

revision described in paragraph (c)(1) of 

this section, the Administrator has 

already started recording any allocations 

of TR SO2 Group 1 allowances under 

subpart CCCCC of part 97 of this chapter 

to units in the State for a control period 

in any year, the provisions of subpart 

CCCCC of part 97 of this chapter 

authorizing the Administrator to 

complete the allocation and recordation 

of TR SO2 Group 1 allowances to units 

in the State for each such control period 

shall continue to apply, unless provided 

otherwise by such approval of the 

State’s SIP revision. 

PART 72—[AMENDED] 

■ 64. The authority citation for part 72 

is revised to read as follows: 

Authority: 42 U.S.C. 7401, 7403, 7410, 

7411, 7426, 7601, et seq. 

§ 72.2 [Amended] 

■ 65. Section 72.2 is amended by 

removing the definition of ‘‘Interested 

person’’. 

PART 78—[AMENDED] 

■ 66. The authority citation for part 78 

continues to read as follows: 

Authority: 42 U.S.C. 7401, 7403, 7410, 

7411, 7426, 7601, et seq. 

■ 67. Section 78.1 is amended by adding 

paragraphs (b)(13) through (b)(16) to 

read as follows: 

§ 78.1 Purpose and scope. 

* * * * * 

(b) * * * 

(13) Under subpart AAAAA of part 97 

of this chapter, 

(i) The decision on allocation of TR 

NOX Annual allowances under 

§ 97.411(a)(2) and (b) of this chapter. 

(ii) The decision on the transfer of TR 

NOX Annual allowances under § 97.423 

of this chapter. 

(iii) The decision on the deduction of 

TR NOX Annual allowances under 

§§ 97.424 and 97.425 of this chapter. 

(iv) The correction of an error in an 

Allowance Management System account 

under § 97.427 of this chapter. 

(v) The adjustment of information in 

a submission and the decision on the 

deduction and transfer of TR NOX

Annual allowances based on the 

information as adjusted under § 97.428 

of this chapter. 

(vi) The finalization of control period 

emissions data, including retroactive 

adjustment based on audit. 

(vii) The approval or disapproval of a 

petition under § 97.435 of this chapter. 

(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. 

(v) The adjustment of information in 

a submission and the decision on the 

deduction and transfer of TR NOX

Ozone Season allowances based on the 

information as adjusted under § 97.528 

of this chapter. 

(vi) The finalization of control period 

emissions data, including retroactive 

adjustment based on audit. 

(vii) The approval or disapproval of a 

petition under § 97.535 of this chapter. 

(15) Under subpart CCCCC of part 97 

of this chapter, 

(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. 

(v) The adjustment of information in 

a submission and the decision on the 

deduction and transfer of TR SO2 Group 

1 allowances based on the information 

as adjusted under § 97.628 of this 

chapter. 

(vi) The finalization of control period 

emissions data, including retroactive 

adjustment based on audit. 

(vii) The approval or disapproval of a 

petition under § 97.635 of this chapter. 

(16) Under subpart DDDDD of part 97 

of this chapter, 

(i) The decision on allocation of TR 

SO2 Group 2 allowances under 

§ 97.711(a)(2) and (b) of this chapter. 

(ii) The decision on the transfer of TR 

SO2 Group 1 allowances under § 97.723 

of this chapter. 

(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. 

(v) The adjustment of information in 

a submission and the decision on the 


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deduction and transfer of TR SO2 Group 

1 allowances based on the information 

as adjusted under § 97.728 of this 

chapter. 

(vi) The finalization of control period 

emissions data, including retroactive 

adjustment based on audit. 

(vii) The approval or disapproval of a 

petition under § 97.735 of this chapter. 

* * * * * 

■ 68. Section 78.2 is revised to read as 

follows: 

§ 78.2 General. 

(a) Definitions. (1) The terms used in 

this subpart with regard to a decision of 

the Administrator that is appealed 

under this section shall have the 

meaning as set forth in the regulations 

under which the Administrator made 

such decision and as set forth in 

paragraph (a)(2) of this section. 

(2) Interested person means, with 

regard to a decision of the 

Administrator: 

(i) Any person who submitted 

comments, or testified at a public 

hearing, pursuant to an opportunity for 

comment provided by the Administrator 

as part of the process of making such 

decision; 

(ii) Who submitted objections 

pursuant to an opportunity for 

objections provided by the 

Administrator as part of the process of 

making such decision; or 

(iii) Who submitted, to the 

Administrator and in a format 

prescribed by the Administrator, his or 

her name, service address, telephone 

number, and facsimile number and 

identified such decision in order to be 

placed on a list of persons interested in 

such decision; 

(iv) Provided that the Administrator 

may update the list of interested persons 

from time to time by requesting 

additional written indication of 

continued interest from the persons 

listed and may delete from the list the 

name of any person failing to respond 

as requested. 

(b) Availability of information. The 

availability to the public of information 

provided to, or otherwise obtained by, 

the Administrator under this subpart 

shall be governed by part 2 of this 

chapter. 

(c) Computation of time. (1) In 

computing any period of time 

prescribed or allowed under this part, 

except as otherwise provided, the day of 

the event from which the period begins 

to run shall not be included, and 

Saturdays, Sundays, and federal 

holidays shall be included. When the 

period ends on a Saturday, Sunday, or 

federal holiday, the stated period shall 

be extended to include the next 

business day. 

(2) Where a document is served by 

first class mail or commercial delivery 

service, but not by overnight or sameday delivery, 5 days shall be added to 

the time prescribed or allowed under 

this part for the filing of a responsive 

document or for otherwise responding. 

■ 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: 

(i) The designated representative for a 

unit or source, or the authorized 

account representative for any 

Allowance Management System 

account, covered by the decision; or 

(ii) Any interested person with regard 

to the decision. 

* * * * * 

(d) * * * 

(11) Any provision or requirement of 

subparts AAAAA, BBBBB, CCCCC, or 

DDDDD of part 97 of this chapter, 

including the standard requirements 

under § 97.406, § 97.506, § 97.606, or 

§ 97.706 of this chapter and any 

emission monitoring or reporting 

requirements. 

* * * * * 

■ 70. Section 78.4 is amended by: 

■ a. Revising paragraph (a) by: 

■ i. Removing the first, second, third, 

fourth, fifth, and last sentences; 

■ ii. In the sixth and seventh sentences, 

removing the words ‘‘interest in’’ and 

adding, in their place, the words 

‘‘ownership interest with respect to’’; 

■ iii. Redesignating the paragraph as 

paragraph (a)(1)(iii); and 

■ b. Adding paragraphs (a)(1) 

introductory text, (a)(1)(i), and (a)(1)(ii); 

and 

■ c. Revising paragraph (a)(2) to read as 

follows: 

§ 78.4 Filings. 

(a)(1) All original filings made under 

this part shall be signed by the person 

making the filing or by an attorney or 

authorized representative, in accordance 

with the following requirements: 

(i) Any filings on behalf of owners 

and operators of a affected unit or 

affected source, TR NOX Annual unit or 

TR NOX Annual source, TR NOX Ozone 

Season unit or TR NOX Ozone Season 

source, TR SO2 Group 1 unit or TR SO2

Group 1 source, TR SO2 Group 2 unit or 

TR SO2 Group 2 source, or a unit for 

which a TR opt-in application is 

submitted and not withdrawn shall be 

signed by the designated representative. 

Any filing on behalf of persons with an 

ownership interest with respect to 

allowances, TR NOX Annual 

allowances, TR NOX Ozone Season 

allowances, TR SO2 Group 1 

allowances, or TR SO2 Group 2 

allowances in a general account shall be 

signed by the authorized account 

representative. 

(ii) Any filings on behalf of owners 

and operators of a NOX Budget unit or 

NOX Budget source shall be signed by 

the NOX authorized account 

representative. Any filing on behalf of 

persons with an ownership interest with 

respect to NOX allowances in a general 

account shall be signed by the NOX

authorized account representative. 

* * * * * 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile number (if any) of the person 

making the filing shall be provided with 

the filing. 

* * * * * 

§ 78.5 [Amended] 

■ 71. Section 78.5 is amended by, in 

paragraph (a): 

■ a. Removing the words ‘‘public 

comment prior to’’ and adding, in their 

place, the words ‘‘submission of public 

comments or objections prior to’’; 

■ b. Removing the words ‘‘public 

comment period’’ whenever they appear 

and adding, in their place, the words 

‘‘period for submission of public 

comments or objections’’. 

§ 78.12 [Amended] 

■ 72. Section 78.12 is amended by, in 

paragraph (a), removing the words 

‘‘public comment’’ and adding, in their 

place, the words ‘‘submission of public 

comments or objections’’. 

PART 97—[AMENDED] 

■ 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: 


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Subpart AAAAA—TR NOX Annual Trading 

Program 

97.401 Purpose. 

97.402 Definitions. 

97.403 Measurements, abbreviations, and 

acronyms. 

97.404 Applicability. 

97.405 Retired unit exemption. 

97.406 Standard requirements. 

97.407 Computation of time. 

97.408 Administrative appeal procedures. 

97.409 [Reserved] 

97.410 State NOX Annual trading budgets, 

new unit set-asides, Indian country new 

unit set-asides and variability limits. 

97.411 Timing requirements for TR NOX

Annual allowance allocations. 

97.412 TR NOX Annual allowance 

allocations to new units. 

97.413 Authorization of designated 

representative and alternate designated 

representative. 

97.414 Responsibilities of designated 

representative and alternate designated 

representative. 

97.415 Changing designated representative 

and alternate designated representative; 

changes in owners and operators. 

97.416 Certificate of representation. 

97.417 Objections concerning designated 

representative and alternate designated 

representative. 

97.418 Delegation by designated 

representative and alternate designated 

representative. 

97.419 [Reserved] 

97.420 Establishment of compliance 

accounts and general accounts. 

97.421 Recordation of TR NOX Annual 

allowance allocations. 

97.422 Submission of TR NOX Annual 

allowance transfers. 

97.423 Recordation of TR NOX Annual 

allowance transfers. 

97.424 Compliance with TR NOX Annual 

emissions limitation. 

97.425 Compliance with TR NOX Annual 

assurance provisions. 

97.426 Banking. 

97.427 Account error. 

97.428 Administrator’s action on 

submissions. 

97.429 [RESERVED] 

97.430 General monitoring, recordkeeping, 

and reporting requirements. 

97.431 Initial monitoring system 

certification and recertification 

procedures. 

97.432 Monitoring system out-of-control 

periods. 

97.433 Notifications concerning 

monitoring. 

97.434 Recordkeeping and reporting. 

97.435 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

Subpart AAAAA—TR NOX Annual 

Trading Program 

§ 97.401 Purpose. 

This subpart sets forth the general, 

designated representative, allowance, 

and monitoring provisions for the 

Transport Rule (TR) NOX Annual 

Trading Program, under section 110 of 

the Clean Air Act and § 52.38 of this 

chapter, as a means of mitigating 

interstate transport of fine particulates 

and nitrogen oxides. 

§ 97.402 Definitions. 

The terms used in this subpart shall 

have the meanings set forth in this 

section as follows: 

Acid Rain Program means a multistate SO2 and NOX air pollution control 

and emission reduction program 

established by the Administrator under 

title IV of the Clean Air Act and parts 

72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Director of the Clean Air Markets 

Division (or its successor determined by 

the Administrator) of the United States 

Environmental Protection Agency, the 

Administrator’s duly authorized 

representative under this subpart. 

Allocate or allocation means, with 

regard to TR NOX Annual allowances, 

the determination by the Administrator, 

State, or permitting authority, in 

accordance with this subpart and any 

SIP revision submitted by the State and 

approved by the Administrator under 

§ 52.38(a)(3), (4), or (5) of this chapter, 

of the amount of such TR NOX Annual 

allowances to be initially credited, at no 

cost to the recipient, to: 

(1) A TR NOX Annual unit; 

(2) A new unit set-aside; 

(3) An Indian country new unit setaside; or 

(4) An entity not listed in paragraphs 

(1) through (3) of this definition; 

(5) Provided that, if the 

Administrator, State, or permitting 

authority initially credits, to a TR NOX

Annual unit qualifying for an initial 

credit, a credit in the amount of zero TR 

NOX Annual allowances, the TR NOX

Annual unit will be treated as being 

allocated an amount (i.e., zero) of TR 

NOX Annual allowances. 

Allowable NOX emission rate means, 

for a unit, the most stringent State or 

federal NOX emission rate limit (in lb/ 

MWhr or, if in lb/mmBtu, converted to 

lb/MWhr by multiplying it by the unit’s 

heat rate in mmBtu/MWhr) that is 

applicable to the unit and covers the 

longest averaging period not exceeding 

one year. 

Allowance Management System 

means the system by which the 

Administrator records allocations, 

deductions, and transfers of TR NOX

Annual allowances under the TR NOX

Annual Trading Program. Such 

allowances are allocated, recorded, 

held, deducted, or transferred only as 

whole allowances. 

Allowance Management System 

account means an account in the 

Allowance Management System 

established by the Administrator for 

purposes of recording the allocation, 

holding, transfer, or deduction of TR 

NOX Annual allowances. 

Allowance transfer deadline means, 

for a control period in a given year, 

midnight of March 1 (if it is a business 

day), or midnight of the first business 

day thereafter (if March 1 is not a 

business day), immediately after such 

control period and is the deadline by 

which a TR NOX Annual allowance 

transfer must be submitted for 

recordation in a TR NOX Annual 

source’s compliance account in order to 

be available for use in complying with 

the source’s TR NOX Annual emissions 

limitation for such control period in 

accordance with §§ 97.406 and 97.424. 

Alternate designated representative 

means, for a TR NOX Annual source and 

each TR NOX Annual unit at the source, 

the natural person who is authorized by 

the owners and operators of the source 

and all such units at the source, in 

accordance with this subpart, to act on 

behalf of the designated representative 

in matters pertaining to the TR NOX

Annual Trading Program. If the TR NOX

Annual source is also subject to the 

Acid Rain Program, TR NOX Ozone 

Season Trading Program, TR SO2 Group 

1 Trading Program, or TR SO2 Group 2 

Trading Program, then this natural 

person shall be the same natural person 

as the alternate designated 

representative, as defined in the 

respective program. 

Assurance account means an 

Allowance Management System 

account, established by the 

Administrator under § 97.425(b)(3) for 

certain owners and operators of a group 

of one or more TR NOX Annual sources 

and units in a given State (and Indian 

country within the borders of such 

State), in which are held TR NOX

Annual allowances available for use for 

a control period in a given year in 

complying with the TR NOX Annual 

assurance provisions in accordance with 

§§ 97.406 and 97.425. 

Authorized account representative 

means, for a general account, the natural 

person who is authorized, in accordance 

with this subpart, to transfer and 

otherwise dispose of TR NOX Annual 

allowances held in the general account 

and, for a TR NOX Annual source’s 

compliance account, the designated 

representative of the source. 

Automated data acquisition and 

handling system or DAHS means the 

component of the continuous emission 

monitoring system, or other emissions 

monitoring system approved for use 


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under this subpart, designed to interpret 

and convert individual output signals 

from pollutant concentration monitors, 

flow monitors, diluent gas monitors, 

and other component parts of the 

monitoring system to produce a 

continuous record of the measured 

parameters in the measurement units 

required by this subpart. 

Biomass means— 

(1) Any organic material grown for the 

purpose of being converted to energy; 

(2) Any organic byproduct of 

agriculture that can be converted into 

energy; or 

(3) Any material that can be converted 

into energy and is nonmerchantable for 

other purposes, that is segregated from 

other material that is nonmerchantable 

for other purposes, and that is; 

(i) A forest-related organic resource, 

including mill residues, precommercial 

thinnings, slash, brush, or byproduct 

from conversion of trees to 

merchantable material; or 

(ii) A wood material, including 

pallets, crates, dunnage, manufacturing 

and construction materials (other than 

pressure-treated, chemically-treated, or 

painted wood products), and landscape 

or right-of-way tree trimmings. 

Boiler means an enclosed fossil- or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Bottoming-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful thermal 

energy, where at least some of the reject 

heat from the useful thermal energy 

application or process is then used for 

electricity production. 

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 of 

the corporation in charge of a principal 

business function or any other person 

who performs similar policy- or 

decision-making functions for the 

corporation; 

(2) For a partnership or sole 

proprietorship, a general partner or the 

proprietor respectively; or 

(3) For a local government entity or 

State, federal, or other public agency, a 

principal executive officer or ranking 

elected official. 

Clean Air Act means the Clean Air 

Act, 42 U.S.C. 7401, et seq. 

Coal means ‘‘coal’’ as defined in 

§ 72.2 of this chapter. 

Coal-derived fuel means any fuel 

(whether in a solid, liquid, or gaseous 

state) produced by the mechanical, 

thermal, or chemical processing of coal. 

Cogeneration system means an 

integrated group, at a source, of 

equipment (including a boiler, or 

combustion turbine, and a steam turbine 

generator) designed to produce useful 

thermal energy for industrial, 

commercial, heating, or cooling 

purposes and electricity through the 

sequential use of energy. 

Cogeneration unit means a stationary, 

fossil-fuel-fired boiler or stationary, 

fossil-fuel-fired combustion turbine that 

is a topping-cycle unit or a bottomingcycle unit: 

(1) Operating as part of a cogeneration 

system; and 

(2) Producing on an annual average 

basis— 

(i) For a topping-cycle unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less than 42.5 percent 

of total energy input, 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 systemwide basis the requirement in paragraph 

(2)(i)(B) or (2)(ii) of this definition, the 

unit shall be deemed to meet such 

requirement during that 12-month 

period or calendar year. 

Combustion turbine means an 

enclosed device comprising: 

(1) If the device is simple cycle, a 

compressor, a combustor, and a turbine 

and in which the flue gas resulting from 

the combustion of fuel in the combustor 

passes through the turbine, rotating the 

turbine; and 

(2) If the device is combined cycle, 

the equipment described in paragraph 

(1) of this definition and any associated 

duct burner, heat recovery steam 

generator, and steam turbine. 

Commence commercial operation 

means, with regard to a unit: 

(1) To have begun to produce steam, 

gas, or other heated medium used to 

generate electricity for sale or use, 

including test generation, except as 

provided in § 97.405. 

(i) For a unit that is a TR NOX Annual 

unit under § 97.404 on the later of 

January 1, 2005 or the date the unit 

commences commercial operation as 

defined in the introductory text of 

paragraph (1) of this definition and that 

subsequently undergoes a physical 

change or is moved to a new location or 

source, such date shall remain the date 

of commencement of commercial 

operation of the unit, which shall 

continue to be treated as the same unit. 

(ii) For a unit that is a TR NOX

Annual unit under § 97.404 on the later 

of January 1, 2005 or the date the unit 

commences commercial operation as 

defined in the introductory text of 

paragraph (1) of this definition and that 

is subsequently replaced by a unit at the 

same or a different source, such date 

shall remain the replaced unit’s date of 

commencement of commercial 

operation, and the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1) or (2) of this definition as 

appropriate. 

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 97.405, for a unit that is not a TR 

NOX Annual unit under § 97.404 on the 

later of January 1, 2005 or the date the 

unit commences commercial operation 

as defined in introductory text of 

paragraph (1) of this definition, the 

unit’s date for commencement of 

commercial operation shall be the date 

on which the unit becomes a TR NOX

Annual unit under § 97.404. 

(i) For a unit with a date for 

commencement of commercial 

operation as defined in the introductory 

text of paragraph (2) of this 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 


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commencement of commercial 

operation as defined in paragraph (1) or 

(2) of this definition as appropriate. 

Common designated representative 

means, with regard to a control period 

in a given year, a designated 

representative where, as of April 1 

immediately after the allowance transfer 

deadline for such control period, the 

same natural person is authorized under 

§§ 97.413(a) and 97.415(a) as the 

designated representative for a group of 

one or more TR NOX Annual sources 

and units located in a State (and Indian 

country within the borders of such 

State). 

Common designated representative’s 

assurance level means, with regard to a 

specific common designated 

representative and a State (and Indian 

country within the borders of such 

State) and control period in a given year 

for which the State assurance level is 

exceeded as described in 

§ 97.406(c)(2)(iii), the common 

designated representative’s share of the 

State NOX Annual trading budget with 

the variability limit for the State for 

such control period. 

Common designated representative’s 

share means, with regard to a specific 

common designated representative for a 

control period in a given year: 

(1) With regard to a total amount of 

NOX emissions from all TR NOX Annual 

units in a State (and Indian country 

within the borders of such State) during 

such control period, the total tonnage of 

NOX emissions during such control 

period from a group of one or more TR 

NOX Annual units located in such State 

(and such Indian country) and having 

the common designated representative 

for such control period; 

(2) With regard to a State NOX Annual 

trading budget with the variability limit 

for such control period, the amount 

(rounded to the nearest allowance) 

equal to the sum of the total amount of 

TR NOX Annual allowances allocated 

for such control period to a group of one 

or more TR NOX Annual units located 

in the State (and Indian country within 

the borders of such State) and having 

the common designated representative 

for such control period and of the total 

amount of TR NOX Annual allowances 

purchased by an owner or operator of 

such TR NOX Annual units in an 

auction for such control period and 

submitted by the State or the permitting 

authority to the Administrator for 

recordation in the compliance accounts 

for such TR NOX Annual units in 

accordance with the TR NOX Annual 

allowance auction provisions in a SIP 

revision approved by the Administrator 

under § 52.38(a)(4) or (5) of this chapter, 

multiplied by the sum of the State NOX

Annual trading budget under § 97.410(a) 

and the State’s variability limit under 

§ 97.410(b) for such control period and 

divided by such State NOX Annual 

trading budget; 

(3) Provided that, in the case of a unit 

that operates during, but has no amount 

of TR NOX Annual allowances allocated 

under §§ 97.411 and 97.412 for, such 

control period, the unit shall be treated, 

solely for purposes of this definition, as 

being allocated an amount (rounded to 

the nearest allowance) of TR NOX

Annual allowances for such control 

period equal to the unit’s allowable NOX

emission rate applicable to such control 

period, multiplied by a capacity factor 

of 0.85 (if the unit is a boiler combusting 

any amount of coal or coal-derived fuel 

during such control period), 0.24 (if the 

unit is a simple combustion turbine 

during such control period), 0.67 (if the 

unit is a combined cycle turbine during 

such control period), 0.74 (if the unit is 

an integrated coal gasification combined 

cycle unit during such control period), 

or 0.36 (for any other unit), multiplied 

by the unit’s maximum hourly load as 

reported in accordance with this subpart 

and by 8,760 hours/control period, and 

divided by 2,000 lb/ton. 

Common stack means a single flue 

through which emissions from 2 or 

more units are exhausted. 

Compliance account means an 

Allowance Management System 

account, established by the 

Administrator for a TR NOX Annual 

source under this subpart, in which any 

TR NOX Annual allowance allocations 

to the TR NOX Annual units at the 

source are recorded and in which are 

held any TR NOX Annual allowances 

available for use for a control period in 

a given year in complying with the 

source’s TR NOX Annual emissions 

limitation in accordance with §§ 97.406 

and 97.424. 

Continuous emission monitoring 

system or CEMS means the equipment 

required under this subpart to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes and using an 

automated data acquisition and 

handling system (DAHS), a permanent 

record of NOX emissions, stack gas 

volumetric flow rate, stack gas moisture 

content, and O2 or CO2 concentration (as 

applicable), in a manner consistent with 

part 75 of this chapter and §§ 97.430 

through 97.435. The following systems 

are the principal types of continuous 

emission monitoring systems: 

(1) A flow monitoring system, 

consisting of a stack flow rate monitor 

and an automated data acquisition and 

handling system and providing a 

permanent, continuous record of stack 

gas volumetric flow rate, in standard 

cubic feet per hour (scfh); 

(2) A NOX concentration monitoring 

system, consisting of a NOX pollutant 

concentration monitor and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of NOX

emissions, in parts per million (ppm); 

(3) A NOX emission rate (or NOXdiluent) monitoring system, consisting 

of a NOX pollutant concentration 

monitor, a diluent gas (CO2 or O2) 

monitor, and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of NOX concentration, in parts 

per million (ppm), diluent gas 

concentration, in percent CO2 or O2, and 

NOX emission rate, in pounds per 

million British thermal units 

(lb/mmBtu); 

(4) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O; 

(5) A CO2 monitoring system, 

consisting of a CO2 pollutant 

concentration monitor (or an O2 monitor 

plus suitable mathematical equations 

from which the CO2 concentration is 

derived) and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of CO2 emissions, in percent CO2; 

and 

(6) An O2 monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2, in percent O2. 

Control period means the period 

starting January 1 of a calendar year, 

except as provided in § 97.406(c)(3), and 

ending on December 31 of the same 

year, inclusive. 

Designated representative means, for 

a TR NOX Annual source and each TR 

NOX Annual unit at the source, the 

natural person who is authorized by the 

owners and operators of the source and 

all such units at the source, in 

accordance with this subpart, to 

represent and legally bind each owner 

and operator in matters pertaining to the 

TR NOX Annual Trading Program. If the 

TR NOX Annual source is also subject 

to the Acid Rain Program, TR NOX

Ozone Season Trading Program, TR SO2

Group 1 Trading Program, or TR SO2

Group 2 Trading Program, then this 

natural person shall be the same natural 

person as the designated representative, 

as defined in the respective program. 

Emissions means air pollutants 

exhausted from a unit or source into the 

atmosphere, as measured, recorded, and 


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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 

(2) For purposes of applying the 

limitation on ‘‘average annual fuel 

consumption of fossil fuel’’ in 

§§ 97.404(b)(2)(i)(B) and (ii), natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material for the purpose of creating 

useful heat. 

Fossil-fuel-fired means, with regard to 

a unit, combusting any amount of fossil 

fuel in 2005 or any calendar year 

thereafter. 

General account means an Allowance 

Management System account, 

established under this subpart, that is 

not a compliance account or an 

assurance account. 

Generator means a device that 

produces electricity. 

Gross electrical output means, for a 

unit, electricity made available for use, 

including any such electricity used in 

the power production process (which 

process includes, but is not limited to, 

any on-site processing or treatment of 

fuel combusted at the unit and any onsite emission controls). 

Heat input means, for a unit for a 

specified period of time, the product (in 

mmBtu/time) of the gross calorific value 

of the fuel (in mmBtu/lb) fed into the 

unit multiplied by the fuel feed rate (in 

lb of fuel/time), as measured, recorded, 

and reported to the Administrator by the 

designated representative and as 

modified by the Administrator in 

accordance with this subpart and 

excluding the heat derived from 

preheated combustion air, recirculated 

flue gases, or exhaust. 

Heat input rate means, for a unit, the 

amount of heat input (in mmBtu) 

divided by unit operating time (in hr) 

or, for a unit and a specific fuel, the 

amount of heat input attributed to the 

fuel (in mmBtu) divided by the unit 

operating time (in hr) during which the 

unit combusts the fuel. 

Heat rate means, for a unit, the unit’s 

maximum design heat input (in Btu/hr), 

divided by the product of 1,000,000 

Btu/mmBtu and the unit’s maximum 

hourly load. 

Indian country means ‘‘Indian 

country’’ as defined in 18 U.S.C. 1151. 

Life-of-the-unit, firm power 

contractual arrangement means a unit 

participation power sales agreement 

under which a utility or industrial 

customer reserves, or is entitled to 

receive, a specified amount or 

percentage of nameplate capacity and 

associated energy generated by any 

specified unit and pays its proportional 

amount of such unit’s total costs, 

pursuant to a contract: 

(1) For the life of the unit; 

(2) For a cumulative term of no less 

than 30 years, including contracts that 

permit an election for early termination; 

or 

(3) For a period no less than 25 years 

or 70 percent of the economic useful life 

of the unit determined as of the time the 

unit is built, with option rights to 

purchase or release some portion of the 

nameplate capacity and associated 

energy generated by the unit at the end 

of the period. 

Maximum design heat input means, 

for a unit, the maximum amount of fuel 

per hour (in Btu/hr) that the unit is 

capable of combusting on a steady state 

basis as of the initial installation of the 

unit as specified by the manufacturer of 

the unit. 

Monitoring system means any 

monitoring system that meets the 

requirements of this subpart, including 

a continuous emission monitoring 

system, an alternative monitoring 

system, or an excepted monitoring 

system under part 75 of this chapter. 

Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe, rounded to 

the nearest tenth) that the generator is 

capable of producing on a steady state 

basis and during continuous operation 

(when not restricted by seasonal or 

other deratings) as of such installation 

as specified by the manufacturer of the 

generator or, starting from the 

completion of any subsequent physical 

change in the generator resulting in an 

increase in the maximum electrical 

generating output that the generator is 

capable of producing on a steady state 

basis and during continuous operation 

(when not restricted by seasonal or 

other deratings), such increased 

maximum amount (in MWe, rounded to 

the nearest tenth) as of such completion 

as specified by the person conducting 

the physical change. 

Natural gas means ‘‘natural gas’’ as 

defined in § 72.2 of this chapter. 

Newly affected TR NOX Annual unit 

means a unit that was not a TR NOX

Annual unit when it began operating 

but that thereafter becomes a TR NOX

Annual unit. 

Operate or operation means, with 

regard to a unit, to combust fuel. 

Operator means, for a TR NOX Annual 

source or a TR NOX Annual unit at a 

source respectively, any person who 

operates, controls, or supervises a TR 

NOX Annual unit at the source or the TR 

NOX Annual unit and shall include, but 

not be limited to, any holding company, 

utility system, or plant manager of such 

source or unit. 

Owner means, for a TR NOX Annual 

source or a TR NOX Annual unit at a 

source respectively, any of the following 

persons: 

(1) Any holder of any portion of the 

legal or equitable title in a TR NOX

Annual unit at the source or the TR NOX

Annual unit; 

(2) Any holder of a leasehold interest 

in a TR NOX Annual unit at the source 

or the TR NOX Annual unit, provided 

that, unless expressly provided for in a 

leasehold agreement, ‘‘owner’’ shall not 

include a passive lessor, or a person 

who has an equitable interest through 

such lessor, whose rental payments are 

not based (either directly or indirectly) 

on the revenues or income from such TR 

NOX Annual unit; and 3) Any purchaser 

of power from a TR NOX Annual unit 

at the source or the TR NOX Annual unit 

under a life-of-the-unit, firm power 

contractual arrangement. 

Permanently retired means, with 

regard to a unit, a unit that is 

unavailable for service and that the 

unit’s owners and operators do not 

expect to return to service in the future. 

Permitting authority means 

‘‘permitting authority’’ as defined in 

§§ 70.2 and 71.2 of this chapter. 

Potential electrical output capacity 

means, for a unit, 33 percent of the 

unit’s maximum design heat input, 

divided by 3,413 Btu/kWh, divided by 

1,000 kWh/MWh, and multiplied by 

8,760 hr/yr. 

Receive or receipt of means, when 

referring to the Administrator, to come 

into possession of a document, 

information, or correspondence 

(whether sent in hard copy or by 

authorized electronic transmission), as 

indicated in an official log, or by a 

notation made on the document, 

information, or correspondence, by the 

Administrator in the regular course of 

business. 

Recordation, record, or recorded 

means, with regard to TR NOX Annual 

allowances, the moving of TR NOX


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Annual allowances by the 

Administrator into, out of, or between 

Allowance Management System 

accounts, for purposes of allocation, 

auction, transfer, or deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter. 

Replacement, replace, or replaced 

means, with regard to a unit, the 

demolishing of a unit, or the permanent 

retirement and permanent disabling of a 

unit, and the construction of another 

unit (the replacement unit) to be used 

instead of the demolished or retired unit 

(the replaced unit). 

Sequential use of energy means: 

(1) The use of reject heat from 

electricity production in a useful 

thermal energy application or process; 

or 

(2) The use of reject heat from useful 

thermal energy application or process in 

electricity production. 

Serial number means, for a TR NOX

Annual allowance, the unique 

identification number assigned to each 

TR NOX Annual allowance by the 

Administrator. 

Solid waste incineration unit means a 

stationary, fossil-fuel-fired boiler or 

stationary, fossil-fuel-fired combustion 

turbine that is a ‘‘solid waste 

incineration unit’’ as defined in section 

129(g)(1) of the Clean Air Act. 

Source means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. This definition 

does not change or otherwise affect the 

definition of ‘‘major source’’, ‘‘stationary 

source’’, or ‘‘source’’ as set forth and 

implemented in a title V operating 

permit program or any other program 

under the Clean Air Act. 

State means one of the States that is 

subject to the TR NOX Annual Trading 

Program pursuant to § 52.38(a) of this 

chapter. 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery; 

(4) Provided that compliance with any 

‘‘submission’’ or ‘‘service’’ deadline 

shall be determined by the date of 

dispatch, transmission, or mailing and 

not the date of receipt. 

Topping-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful power, 

including electricity, where at least 

some of the reject heat from the 

electricity production is then used to 

provide useful thermal energy. 

Total energy input means, for a unit, 

total energy of all forms supplied to the 

unit, excluding energy produced by the 

unit. Each form of energy supplied shall 

be measured by the lower heating value 

of that form of energy calculated as 

follows: 

LHV = HHV ¥ 10.55(W + 9H) 

Where: 

LHV = lower heating value of the form of 

energy in Btu/lb, 

HHV = higher heating value of the form of 

energy in Btu/lb, 

W = weight % of moisture in the form of 

energy, and 

H = weight % of hydrogen in the form of 

energy. 

Total energy output means, for a unit, 

the sum of useful power and useful 

thermal energy produced by the unit. 

TR NOX Annual allowance means a 

limited authorization issued and 

allocated or auctioned by the 

Administrator under this subpart, or by 

a State or permitting authority under a 

SIP revision approved by the 

Administrator under § 52.38(a)(3), (4), or 

(5) of this chapter, to emit one ton of 

NOX during a control period of the 

specified calendar year for which the 

authorization is allocated or auctioned 

or of any calendar year thereafter under 

the TR NOX Annual Trading Program. 

TR NOX Annual allowance deduction 

or deduct TR NOX Annual allowances 

means the permanent withdrawal of TR 

NOX Annual allowances by the 

Administrator from a compliance 

account (e.g., in order to account for 

compliance with the TR NOX Annual 

emissions limitation) or from an 

assurance account (e.g., in order to 

account for compliance with the 

assurance provisions under §§ 97.406 

and 97.425). 

TR NOX Annual allowances held or 

hold TR NO4 Annual allowances means 

the TR NOX Annual allowances treated 

as included in an Allowance 

Management System account as of a 

specified point in time because at that 

time they: 

(1) Have been recorded by the 

Administrator in the account or 

transferred into the account by a 

correctly submitted, but not yet 

recorded, TR NOX Annual allowance 

transfer in accordance with this subpart; 

and 

(2) Have not been transferred out of 

the account by a correctly submitted, 

but not yet recorded, TR NOX Annual 

allowance transfer in accordance with 

this subpart. 

TR NOX Annual emissions limitation 

means, for a TR NOX Annual source, the 

tonnage of NOX emissions authorized in 

a control period in a given year by the 

TR NOX Annual allowances available 

for deduction for the source under 

§ 97.424(a) for such control period. 

TR NOX Annual source means a 

source that includes one or more TR 

NOX Annual units. 

TR NOX Annual Trading Program 

means a multi-state NOX air pollution 

control and emission reduction program 

established in accordance with this 

subpart and § 52.38(a) of this chapter 

(including such a program that is 

revised in a SIP revision approved by 

the Administrator under § 52.38(a)(3) or 

(4) of this chapter or that is established 

in a SIP revision approved by the 

Administrator under § 52.38(a)(5) of this 

chapter), as a means of mitigating 

interstate transport of fine particulates 

and NOX. 

TR NOX Annual unit means a unit 

that is subject to the TR NOX Annual 

Trading Program. 

TR NOX Ozone Season Trading 

Program means a multi-state NOX air 

pollution control and emission 

reduction program established in 

accordance with subpart BBBBB of this 

part and § 52.38(b) of this chapter 

(including such a program that is 

revised in a SIP revision approved by 

the Administrator under § 52.38(b)(3) or 

(4) of this chapter or that is established 

in a SIP revision approved by the 

Administrator under § 52.38(b)(5) of this 

chapter), as a means of mitigating 

interstate transport of ozone and NOX. 

TR SO2 Group 1 Trading Program 

means a multi-state SO2 air pollution 

control and emission reduction program 

established in accordance with subpart 

CCCCC of this part and § 52.39(a), (b), 

(d) through (f), (j), and (k) of this chapter 

(including such a program that is 

revised in a SIP revision approved by 

the Administrator under § 52.39(d) or (e) 

of this chapter or that is established in 

a SIP revision approved by the 

Administrator under § 52.39(f) of this 

chapter), as a means of mitigating 

interstate transport of fine particulates 

and SO2. 

TR SO2 Group 2 Trading Program 

means a multi-state SO2 air pollution 

control and emission reduction program 

established in accordance with subpart 

DDDDD of this part and 52.39(a), (c), 

and (g) through (k) of this chapter 

(including such a program that is 

revised in a SIP revision approved by 

the Administrator under § 52.39(g) or (h) 

of this chapter or that is established in 

a SIP revision approved by the 

Administrator under § 52.39(i) of this 

chapter), as a means of mitigating 

interstate transport of fine particulates 

and SO2. 


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Unit means a stationary, fossil-fuelfired 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 processing or treatment of 

fuel combusted at the unit and any onsite emission controls). 

Useful thermal energy means thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process (not a power 

production process), excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heating application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., in an absorption 

chiller). 

Utility power distribution system 

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers. 

§ 97.403 Measurements, abbreviations, 

and acronyms. 

Measurements, abbreviations, and 

acronyms used in this subpart are 

defined as follows: 

Btu—British thermal unit 

CO2—carbon dioxide 

H2O—water 

hr—hour 

kW—kilowatt electrical 

kWh—kilowatt hour 

lb—pound 

mmBtu—million Btu 

MWe—megawatt electrical 

MWh—megawatt hour 

NOX—nitrogen oxides 

O2—oxygen 

ppm—parts per million 

scfh—standard cubic feet per hour 

SO2—sulfur dioxide 

yr—year 

§ 97.404 Applicability. 

(a) Except as provided in paragraph 

(b) of this section: 

(1) The following units in a State (and 

Indian country within the borders of 

such State) shall be TR NOX Annual 

units, and any source that includes one 

or more such units shall be a TR NOX

Annual source, subject to the 

requirements of this subpart: any 

stationary, 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 (and Indian 

country within the borders of such 

State) that otherwise is a TR NOX

Annual unit under paragraph (a) of this 

section and that meets the requirements 

set forth in paragraph (b)(1)(i) or (2)(i) of 

this section shall not be a TR NOX

Annual unit: 

(1)(i) Any unit: 

(A) Qualifying as a cogeneration unit 

throughout the later of 2005 or the 

12-month period starting on the date the 

unit first produces electricity and 

continuing to qualify as a cogeneration 

unit throughout each calendar year 

ending after the later of 2005 or such 

12-month period; and 

(B) Not supplying in 2005 or any 

calendar year thereafter more than onethird of the unit’s potential electric 

output capacity or 219,000 MWh, 

whichever is greater, to any utility 

power distribution system for sale. 

(ii) If, after qualifying under 

paragraph (b)(1)(i) of this section as not 

being a TR NOX Annual unit, a unit 

subsequently no longer meets all the 

requirements of paragraph (b)(1)(i) of 

this section, the unit shall become a TR 

NOX Annual unit starting on the earlier 

of January 1 after the first calendar year 

during which the unit first no longer 

qualifies as a cogeneration unit or 

January 1 after the first calendar year 

during which the unit no longer meets 

the requirements of paragraph 

(b)(1)(i)(B) of this section. The unit shall 

thereafter continue to be a TR NOX

Annual unit. 

(2)(i) Any unit: 

(A) Qualifying as a solid waste 

incineration unit throughout the later of 

2005 or the 12-month period starting on 

the date the unit first produces 

electricity and continuing to qualify as 

a solid waste incineration unit 

throughout each calendar year ending 

after the later of 2005 or such 12-month 

period; and 

(B) With an average annual fuel 

consumption of fossil fuel for the first 

3 consecutive calendar years of 

operation starting no earlier than 2005 

of less than 20 percent (on a Btu basis) 

and an average annual fuel consumption 

of fossil fuel for any 3 consecutive 

calendar years thereafter of less than 20 

percent (on a Btu basis). 

(ii) If, after qualifying under 

paragraph (b)(2)(i) of this section as not 

being a TR NOX Annual unit, a unit 

subsequently no longer meets all the 

requirements of paragraph (b)(1)(i) of 

this section, the unit shall become a TR 

NOX Annual unit starting on the earlier 

of January 1 after the first calendar year 

during which the unit first no longer 

qualifies as a solid waste incineration 

unit or January 1 after the first 3 

consecutive calendar years after 2005 

for which the unit has an average 

annual fuel consumption of fossil fuel of 

20 percent or more. The unit shall 

thereafter continue to be a TR NOX

Annual unit. 

(c) A certifying official of an owner or 

operator of any unit or other equipment 

may submit a petition (including any 

supporting documents) to the 

Administrator at any time for a 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section or a SIP revision 

approved under § 52.38(a)(4) or (5) of 

this chapter, of the TR NOX Annual 

Trading Program to the unit or other 

equipment. 

(1) Petition content. The petition shall 

be in writing and include the 

identification of the unit or other 

equipment and the relevant facts about 

the unit or other equipment. The 

petition and any other documents 

provided to the Administrator in 

connection with the petition shall 

include the following certification 

statement, signed by the certifying 

official: ‘‘I am authorized to make this 

submission on behalf of the owners and 

operators of the unit or other equipment 

for which the submission is made. I 

certify under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 


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and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(2) Response. The Administrator will 

issue a written response to the petition 

and may request supplemental 

information determined by the 

Administrator to be relevant to such 

petition. The Administrator’s 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section, of the TR NOX

Annual Trading Program to the unit or 

other equipment shall be binding on any 

State or permitting authority unless the 

Administrator determines that the 

petition or other documents or 

information provided in connection 

with the petition contained significant, 

relevant errors or omissions. 

§ 97.405 Retired unit exemption. 

(a)(1) Any TR NOX Annual unit that 

is permanently retired shall be exempt 

from § 97.406(b) and (c)(1), § 97.424, 

and §§ 97.430 through 97.435. 

(2) The exemption under paragraph 

(a)(1) of this section shall become 

effective the day on which the TR NOX

Annual unit is permanently retired. 

Within 30 days of the unit’s permanent 

retirement, the designated 

representative shall submit a statement 

to the Administrator. The statement 

shall state, in a format prescribed by the 

Administrator, that the unit was 

permanently retired on a specified date 

and will comply with the requirements 

of paragraph (b) of this section. 

(b) Special provisions. (1) A unit 

exempt under paragraph (a) of this 

section shall not emit any NOX, starting 

on the date that the exemption takes 

effect. 

(2) For a period of 5 years from the 

date the records are created, the owners 

and operators of a unit exempt under 

paragraph (a) of this section shall retain, 

at the source that includes the unit, 

records demonstrating that the unit is 

permanently retired. The 5-year period 

for keeping records may be extended for 

cause, at any time before the end of the 

period, in writing by the Administrator. 

The owners and operators bear the 

burden of proof that the unit is 

permanently retired. 

(3) The owners and operators and, to 

the extent applicable, the designated 

representative of a unit exempt under 

paragraph (a) of this section shall 

comply with the requirements of the TR 

NOX Annual Trading Program 

concerning all periods for which the 

exemption is not in effect, even if such 

requirements arise, or must be complied 

with, after the exemption takes effect. 

(4) A unit exempt under paragraph (a) 

of this section shall lose its exemption 

on the first date on which the unit 

resumes operation. Such unit shall be 

treated, for purposes of applying 

allocation, monitoring, reporting, and 

recordkeeping requirements under this 

subpart, as a unit that commences 

commercial operation on the first date 

on which the unit resumes operation. 

§ 97.406 Standard requirements. 

(a) Designated representative 

requirements. The owners and operators 

shall comply with the requirement to 

have a designated representative, and 

may have an alternate designated 

representative, in accordance with 

§§ 97.413 through 97.418. 

(b) Emissions monitoring, reporting, 

and recordkeeping requirements. 

(1) The owners and operators, and the 

designated representative, of each TR 

NOX Annual source and each TR NOX

Annual unit at the source shall comply 

with the monitoring, reporting, and 

recordkeeping requirements of §§ 97.430 

through 97.435. 

(2) The emissions data determined in 

accordance with §§ 97.430 through 

97.435 shall be used to calculate 

allocations of TR NOX Annual 

allowances under §§ 97.411(a)(2) and (b) 

and 97.412 and to determine 

compliance with the TR NOX Annual 

emissions limitation and assurance 

provisions under paragraph (c) of this 

section, provided that, for each 

monitoring location from which mass 

emissions are reported, the mass 

emissions amount used in calculating 

such allocations and determining such 

compliance shall be the mass emissions 

amount for the monitoring location 

determined in accordance with 

§§ 97.430 through 97.435 and rounded 

to the nearest ton, with any fraction of 

a ton less than 0.50 being deemed to be 

zero. 

(c) NOX emissions requirements. (1) 

TR NOX Annual emissions limitation. (i) 

As of the allowance transfer deadline for 

a control period 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 

violations, under the Clean Air Act, and 

each ton of such excess emissions and 

each day of such control period shall 

constitute a separate violation of this 

subpart and the Clean Air Act. 

(2) TR NOX Annual assurance 

provisions. (i) If total NOX emissions 

during a control period in a given year 

from all TR NOX Annual units at TR 

NOX Annual sources in a State (and 

Indian country within the borders of 

such State) exceed the State assurance 

level, then the owners and operators of 

such sources and units in each group of 

one or more sources and units having a 

common designated representative for 

such control period, where the common 

designated representative’s share of 

such NOX emissions during such 

control period exceeds the common 

designated representative’s assurance 

level for the State and such control 

period, shall hold (in the assurance 

account established for the owners and 

operators of such group) TR NOX

Annual allowances available for 

deduction for such control period under 

§ 97.425(a) in an amount equal to two 

times the product (rounded to the 

nearest whole number), as determined 

by the Administrator in accordance with 

§ 97.425(b), of multiplying— 

(A) The quotient of the amount by 

which the common designated 

representative’s share of such NOX

emissions exceeds the common 

designated representative’s assurance 

level divided by the sum of the 

amounts, determined for all common 

designated representatives for such 

sources and units in the State (and 

Indian country within the borders of 

such State) for such control period, by 

which each common designated 

representative’s share of such NOX

emissions exceeds the respective 

common designated representative’s 

assurance level; and 

(B) The amount by which total NOX

emissions from all TR NOX Annual 

units at TR NOX Annual sources in the 

State (and Indian country within the 

borders of such State) for such control 

period exceed the State assurance level. 


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(ii) The owners and operators shall 

hold the TR NOX Annual allowances 

required under paragraph (c)(2)(i) of this 

section, as of midnight of November 1 

(if it is a business day), or midnight of 

the first business day thereafter (if 

November 1 is not a business day), 

immediately after such control period. 

(iii) Total NOX emissions from all TR 

NOX Annual units at TR NOX Annual 

sources in a State (and Indian country 

within the borders of such State) during 

a control period in a given year exceed 

the State assurance level if such total 

NOX emissions exceed the sum, for such 

control period, of the State NOX Annual 

trading budget under § 97.410(a) and the 

State’s variability limit under 

§ 97.410(b). 

(iv) It shall not be a violation of this 

subpart or of the Clean Air Act if total 

NOX emissions from all TR NOX Annual 

units at TR NOX Annual sources in a 

State (and Indian country within the 

borders of such State) during a control 

period exceed the State assurance level 

or if a common designated 

representative’s share of total NOX

emissions from the TR NOX Annual 

units at TR NOX Annual sources in a 

State (and Indian country within the 

borders of such State) during a control 

period exceeds the common designated 

representative’s assurance level. 

(v) To the extent the owners and 

operators fail to hold TR NOX Annual 

allowances for a control period in a 

given year in accordance with 

paragraphs (c)(2)(i) through (iii) of this 

section, 

(A) The owners and operators shall 

pay any fine, penalty, or assessment or 

comply with any other remedy imposed 

under the Clean Air Act; and 

(B) Each TR NOX Annual allowance 

that the owners and operators fail to 

hold for such control period in 

accordance with paragraphs (c)(2)(i) 

through (iii) of this section and each day 

of such control period shall constitute a 

separate violation of this subpart and 

the Clean Air Act. 

(3) Compliance periods. A TR NOX

Annual unit shall be subject to the 

requirements under paragraphs (c)(1) 

and (c)(2) of this section for the control 

period starting on the later of January 1, 

2012 or the deadline for meeting the 

unit’s monitor certification 

requirements under § 97.430(b) and for 

each control period thereafter. 

(4) Vintage of allowances held for 

compliance. (i) A TR NOX Annual 

allowance held for compliance with the 

requirements under paragraph (c)(1)(i) 

of this section for a control period in a 

given year must be a TR NOX Annual 

allowance that was allocated for such 

control period or a control period in a 

prior year. 

(ii) A TR NOX Annual allowance held 

for compliance with the requirements 

under paragraphs (c)(1)(ii)(A) and (2)(i) 

through (iii) of this section for a control 

period in a given year must be a TR NOX

Annual allowance that was allocated for 

a control period in a prior year or the 

control period in the given year or in the 

immediately following year. 

(5) Allowance Management System 

requirements. Each TR NOX Annual 

allowance shall be held in, deducted 

from, or transferred into, out of, or 

between Allowance Management 

System accounts in accordance with 

this subpart. 

(6) Limited authorization. A TR NOX

Annual allowance is a limited 

authorization to emit one ton of NOX

during the control period in one year. 

Such authorization is limited in its use 

and duration as follows: 

(i) Such authorization shall only be 

used in accordance with the TR NOX

Annual Trading Program; and 

(ii) Notwithstanding any other 

provision of this subpart, the 

Administrator has the authority to 

terminate or limit the use and duration 

of such authorization to the extent the 

Administrator determines is necessary 

or appropriate to implement any 

provision of the Clean Air Act. 

(7) Property right. A TR NOX Annual 

allowance does not constitute a property 

right. 

(d) Title V permit requirements. (1) No 

title V permit revision shall be required 

for any allocation, holding, deduction, 

or transfer of TR NOX Annual 

allowances in accordance with this 

subpart. 

(2) A description of whether a unit is 

required to monitor and report NOX

emissions using a continuous emission 

monitoring system (under subpart H of 

part 75 of this chapter), an excepted 

monitoring system (under appendices D 

and E to part 75 of this chapter), a low 

mass emissions excepted monitoring 

methodology (under § 75.19 of this 

chapter), or an alternative monitoring 

system (under subpart E of part 75 of 

this chapter) in accordance with 

§§ 97.430 through 97.435 may be added 

to, or changed in, a title V permit using 

minor permit modification procedures 

in accordance with §§ 70.7(e)(2) and 

71.7(e)(1) of this chapter, provided that 

the requirements applicable to the 

described monitoring and reporting (as 

added or changed, respectively) are 

already incorporated in such permit. 

This paragraph explicitly provides that 

the addition of, or change to, a unit’s 

description as described in the prior 

sentence is eligible for minor permit 

modification procedures in accordance 

with §§ 70.7(e)(2)(i)(B) and 

71.7(e)(1)(i)(B) of this chapter. 

(e) Additional recordkeeping and 

reporting requirements. (1) Unless 

otherwise provided, the owners and 

operators of each TR NOX Annual 

source and each TR NOX Annual unit at 

the source shall keep on site at the 

source each of the following documents 

(in hardcopy or electronic format) for a 

period of 5 years from the date the 

document is created. This period may 

be extended for cause, at any time 

before the end of 5 years, in writing by 

the Administrator. 

(i) The certificate of representation 

under § 97.416 for the designated 

representative for the source and each 

TR NOX Annual unit at the source and 

all documents that demonstrate the 

truth of the statements in the certificate 

of representation; provided that the 

certificate and documents shall be 

retained on site at the source beyond 

such 5-year period until such certificate 

of representation and documents are 

superseded because of the submission of 

a new certificate of representation under 

§ 97.416 changing the designated 

representative. 

(ii) All emissions monitoring 

information, in accordance with this 

subpart. 

(iii) Copies of all reports, compliance 

certifications, and other submissions 

and all records made or required under, 

or to demonstrate compliance with the 

requirements of, the TR NOX Annual 

Trading Program. 

(2) The designated representative of a 

TR NOX Annual source and each TR 

NOX Annual unit at the source shall 

make all submissions required under 

the TR NOX Annual Trading Program, 

except as provided in § 97.418. This 

requirement does not change, create an 

exemption from, or or otherwise affect 

the responsible official submission 

requirements under a title V operating 

permit program in parts 70 and 71 of 

this chapter. 

(f) Liability. (1) Any provision of the 

TR NOX Annual Trading Program that 

applies to a TR NOX Annual source or 

the designated representative of a TR 

NOX Annual source shall also apply to 

the owners and operators of such source 

and of the TR NOX Annual units at the 

source. 

(2) Any provision of the TR NOX

Annual Trading Program that applies to 

a TR NOX Annual unit or the designated 

representative of a TR NOX Annual unit 

shall also apply to the owners and 

operators of such unit. 

(g) Effect on other authorities. No 

provision of the TR NOX Annual 

Trading Program or exemption under 


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§ 97.405 shall be construed as 

exempting or excluding the owners and 

operators, and the designated 

representative, of a TR NOX Annual 

source or TR NOX Annual unit from 

compliance with any other provision of 

the applicable, approved State 

implementation plan, a federally 

enforceable permit, or the Clean Air Act. 

§ 97.407 Computation of time. 

(a) Unless otherwise stated, any time 

period scheduled, under the TR NOX

Annual Trading Program, to begin on 

the occurrence of an act or event shall 

begin on the day the act or event occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the TR NOX

Annual Trading Program, to begin 

before the occurrence of an act or event 

shall be computed so that the period 

ends the day before the act or event 

occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the TR 

NOX Annual Trading Program, is not a 

business day, the time period shall be 

extended to the next business day. 

§ 97.408 Administrative appeal 

procedures. 

The administrative appeal procedures 

for decisions of the Administrator under 

the TR NOX Annual Trading Program 

are set forth in part 78 of this chapter. 

§ 97.409 [Reserved] 

§ 97.410 State NOX Annual trading 

budgets, new unit set-asides, Indian 

country new unit set-aside, and variability 

limits. 

(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 setaside (tons) 

for 2012 and 

2013 

Alabama ....................................................................................................................................... 72,691 1,454 ........................

Georgia ........................................................................................................................................ 62,010 1,240 ........................

Illinois ........................................................................................................................................... 47,872 3,830 ........................

Indiana ......................................................................................................................................... 109,726 3,292 ........................

Iowa ............................................................................................................................................. 38,335 729 38 

Kansas ......................................................................................................................................... 30,714 583 31 

Kentucky ...................................................................................................................................... 85,086 3,403 ........................

Maryland ...................................................................................................................................... 16,633 333 ........................

Michigan ....................................................................................................................................... 60,193 1,144 60 

Minnesota .................................................................................................................................... 29,572 561 30 

Missouri ........................................................................................................................................ 52,374 1,571 ........................

Nebraska ...................................................................................................................................... 26,440 1,825 26 

New Jersey .................................................................................................................................. 7,266 145 ........................

New York ..................................................................................................................................... 17,543 508 18 

North Carolina .............................................................................................................................. 50,587 2,984 51 

Ohio ............................................................................................................................................. 92,703 1,854 ........................

Pennsylvania ................................................................................................................................ 119,986 2,400 ........................

South Carolina ............................................................................................................................. 32,498 617 33 

Tennessee ................................................................................................................................... 35,703 714 ........................

Texas ........................................................................................................................................... 133,595 3,874 134 

Virginia ......................................................................................................................................... 33,242 1,662 ........................

West Virginia ................................................................................................................................ 59,472 2,974 ........................

Wisconsin ..................................................................................................................................... 31,628 1,866 32 

State 

NOX Annual 

trading 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 38 

Kansas ......................................................................................................................................... 25,560 485 26 

Kentucky ...................................................................................................................................... 77,238 3,090 ........................

Maryland ...................................................................................................................................... 16,574 331 ........................

Michigan ....................................................................................................................................... 57,812 1,098 58 

Minnesota .................................................................................................................................... 29,572 561 30 

Missouri ........................................................................................................................................ 48,717 1,462 ........................

Nebraska ...................................................................................................................................... 26,440 1,825 26 

New Jersey .................................................................................................................................. 7,266 145 ........................

New York ..................................................................................................................................... 17,543 508 18 

North Carolina .............................................................................................................................. 41,553 2,451 42 

Ohio ............................................................................................................................................. 87,493 1,750 ........................

Pennsylvania ................................................................................................................................ 119,194 2,384 ........................

South Carolina ............................................................................................................................. 32,498 617 33 

Tennessee ................................................................................................................................... 19,337 387 ........................


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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 

Texas ........................................................................................................................................... 133,595 3,874 134 

Virginia ......................................................................................................................................... 33,242 1,662 ........................

West Virginia ................................................................................................................................ 54,582 2,729 ........................

Wisconsin ..................................................................................................................................... 30,398 1,794 30 

* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-aside and does not include the 

variability limit. 

(b) The States’ variability limits for 

the State NOX Annual trading budgets 

for the control periods in 2012 and 

thereafter are as follows: 

State 

Variability 

limits 

for 2012 and 

2013 

Variability 

limits 

for 2014 and 

thereafter 

Alabama ................................................................................................................................................................... 13,084 12,953 

Georgia .................................................................................................................................................................... 11,162 7,297 

Illinois ....................................................................................................................................................................... 8,617 8,617 

Indiana ..................................................................................................................................................................... 19,751 19,516 

Iowa ......................................................................................................................................................................... 6,900 6,750 

Kansas ..................................................................................................................................................................... 5,529 4,601 

Kentucky .................................................................................................................................................................. 15,315 13,903 

Maryland .................................................................................................................................................................. 2,994 2,983 

Michigan ................................................................................................................................................................... 10,835 10,406 

Minnesota ................................................................................................................................................................ 5,323 5,323 

Missouri .................................................................................................................................................................... 9,427 8,769 

Nebraska .................................................................................................................................................................. 4,759 4,759 

New Jersey .............................................................................................................................................................. 1,308 1,308 

New York ................................................................................................................................................................. 3,158 3,158 

North Carolina .......................................................................................................................................................... 9,106 7,480 

Ohio ......................................................................................................................................................................... 16,687 15,749 

Pennsylvania ............................................................................................................................................................ 21,597 21,455 

South Carolina ......................................................................................................................................................... 5,850 5,850 

Tennessee ............................................................................................................................................................... 6,427 3,481 

Texas ....................................................................................................................................................................... 24,047 24,047 

Virginia ..................................................................................................................................................................... 5,984 5,984 

West Virginia ............................................................................................................................................................ 10,705 9,825 

Wisconsin ................................................................................................................................................................. 5,693 5,472 

§ 97.411 Timing requirements for TR NOX

Annual allowance allocations. 

(a) Existing units. (1) TR NOX Annual 

allowances are allocated, for the control 

periods in 2012 and each year 

thereafter, as provided in a notice of 

data availability issued by the 

Administrator. Providing an allocation 

to a unit in such notice does not 

constitute a determination that the unit 

is a TR NOX Annual unit, and not 

providing an allocation to a unit in such 

notice does not constitute a 

determination that the unit is not a TR 

NOX Annual unit. 

(2) Notwithstanding paragraph (a)(1) 

of this section, if a unit provided an 

allocation in the notice of data 

availability issued under paragraph 

(a)(1) of this section does not operate, 

starting after 2011, during the control 

period in two consecutive years, such 

unit will not be allocated the TR NOX

Annual allowances provided in such 

notice for the unit for the control 

periods in the fifth year after the first 

such year and in each year after that 

fifth year. All TR NOX Annual 

allowances that would otherwise have 

been allocated to such unit will be 

allocated to the new unit set-aside for 

the State where such unit is located and 

for the respective years involved. If such 

unit resumes operation, the 

Administrator will allocate TR NOX

Annual allowances to the unit in 

accordance with paragraph (b) of this 

section. 

(b) New units. (1) New unit set-asides. 

(i) By June 1, 2012 and June 1 of each 

year thereafter, the Administrator will 

calculate the TR NOX Annual allowance 

allocation to each TR NOX Annual unit 

in a State, in accordance with 

§ 97.412(a)(2) through (7) and (12), for 

the control period in the year of the 

applicable calculation deadline under 

this paragraph and will promulgate a 

notice of data availability of the results 

of the calculations. 

(ii) For each notice of data availability 

required in paragraph (b)(1)(i) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. 

(A) Objections shall be submitted by 

the deadline specified in each notice of 

data availability required in paragraph 

(b)(1)(i) of this section and shall be 

limited to addressing whether the 

calculations (including the 

identification of the TR NOX Annual 

units) are in accordance with 

§ 97.412(a)(2) through (7) and (12) and 

§§ 97.406(b)(2) and 97.430 through 

97.435. 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(1)(ii)(A) of this section. By August 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(1)(i) of this section, the 


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Administrator will promulgate a notice 

of data availability of any adjustments 

that the Administrator determines to be 

necessary with regard to allocations 

under § 97.412(a)(2) through (7) and (12) 

and the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(1)(ii)(A) 

of this section. 

(iii) If the new unit set-aside for such 

control period contains any TR NOX

Annual allowances that have not been 

allocated in the applicable notice of data 

availability required in paragraph 

(b)(1)(ii) of this section, the 

Administrator will promulgate, by 

December 15 immediately after such 

notice, a notice of data availability that 

identifies any TR NOX Annual units that 

commenced commercial operation 

during the period starting January 1 of 

the year before the year of such control 

period and ending November 30 of year 

of such control period. 

(iv) For each notice of data 

availability required in paragraph 

(b)(1)(iii) of this section, the 

Administrator will provide an 

opportunity for submission of objections 

to the identification of TR NOX annual 

units in such notice. 

(A) Objections shall be submitted by 

the deadline specified in each notice of 

data availability required in paragraph 

(b)(1)(iii) of this section and shall be 

limited to addressing whether the 

identification of TR NOX annual units in 

such notice is in accordance with 

paragraph (b)(1)(iii) of this section. 

(B) The Administrator will adjust the 

identification of TR NOX Annual units 

in the each notice of data availability 

required in paragraph (b)(1)(iii) of this 

section to the extent necessary to ensure 

that it is in accordance with paragraph 

(b)(1)(iii) of this section and will 

calculate the TR NOX Annual allowance 

allocation to each TR NOX Annual unit 

in accordance with § 97.412(a)(9), (10), 

and (12) and §§ 97.406(b)(2) and 97.430 

through 97.435. By February 15 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(1)(iii) of this section, 

the Administrator will promulgate a 

notice of data availability of any 

adjustments of the identification of TR 

NOX Annual units that the 

Administrator determines to be 

necessary, the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(1)(iv)(A) 

of this section, and the results of such 

calculations. 

(v) To the extent any TR NOX Annual 

allowances are added to the new unit 

set-aside after promulgation of each 

notice of data availability required in 

paragraph (b)(1)(iv) of this section, the 

Administrator will promulgate 

additional notices of data availability, as 

deemed appropriate, of the allocation of 

such TR NOX Annual allowances in 

accordance with § 97.412(a)(10). 

(2) Indian country new unit setasides. (i) By June 1, 2012 and June 1 

of each year thereafter, the 

Administrator will calculate the TR 

NOX Annual allowance allocation to 

each TR NOX Annual unit in Indian 

country within the borders of a State, in 

accordance with § 97.412(b)(2) through 

(7) and (12), for the control period in the 

year of the applicable calculation 

deadline under this paragraph and will 

promulgate a notice of data availability 

of the results of the calculations. 

(ii) For each notice of data availability 

required in paragraph (b)(2)(i) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. 

(A) Objections shall be submitted by 

the deadline specified in each notice of 

data availability required in paragraph 

(b)(2)(i) of this section and shall be 

limited to addressing whether the 

calculations (including the 

identification of the TR NOX Annual 

units) are in accordance with 

§ 97.412(b)(2) through (7) and (12) and 

§§ 97.406(b)(2) and 97.430 through 

97.435. 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(ii)(A) of this section. By August 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(2)(i) of this section, the 

Administrator will promulgate a notice 

of data availability of any adjustments 

that the Administrator determines to be 

necessary with regard to allocations 

under § 97.412(b)(2) through (7) and (12) 

and the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(2)(ii)(A) 

of this section. 

(iii) If the Indian country new unit 

set-aside for such control period 

contains any TR NOX Annual 

allowances that have not been allocated 

in the applicable notice of data 

availability required in paragraph 

(b)(2)(ii) of this section, the 

Administrator will promulgate, by 

December 15 immediately after such 

notice, a notice of data availability that 

identifies any TR NOX Annual units that 

commenced commercial operation 

during the period starting January 1 of 

the year before the year of such control 

period and ending November 30 of year 

of such control period. 

(iv) For each notice of data 

availability required in paragraph 

(b)(2)(iii) of this section, the 

Administrator will provide an 

opportunity for submission of objections 

to the identification of TR NOX annual 

units in such notice. 

(A) Objections shall be submitted by 

the deadline specified in each notice of 

data availability required in paragraph 

(b)(2)(iii) of this section and shall be 

limited to addressing whether the 

identification of TR NOX annual units in 

such notice is in accordance with 

paragraph (b)(2)(iii) of this section. 

(B) The Administrator will adjust the 

identification of TR NOX Annual units 

in the each notice of data availability 

required in paragraph (b)(2)(iii) of this 

section to the extent necessary to ensure 

that it is in accordance with paragraph 

(b)(2)(iii) of this section and will 

calculate the TR NOX Annual allowance 

allocation to each TR NOX Annual unit 

in accordance with § 97.412(b)(9), (10), 

and (12) and §§ 97.406(b)(2) and 97.430 

through 97.435. By February 15 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(2)(iii) of this section, 

the Administrator will promulgate a 

notice of data availability of any 

adjustments of the identification of TR 

NOX Annual units that the 

Administrator determines to be 

necessary, the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(2)(iv)(A) 

of this section, and the results of such 

calculations. 

(v) To the extent any TR NOX Annual 

allowances are added to the Indian 

country new unit set-aside after 

promulgation of each notice of data 

availability required in paragraph 

(b)(2)(iv) of this section, the 

Administrator will promulgate 

additional notices of data availability, as 

deemed appropriate, of the allocation of 

such TR NOX Annual allowances in 

accordance with § 97.412(b)(10). 

(c) Units incorrectly allocated TR NOX

Annual allowances. (1) For each control 

period in 2012 and thereafter, if the 

Administrator determines that TR NOX

Annual allowances were allocated 

under paragraph (a) of this section, or 

under a provision of a SIP revision 

approved under § 52.38(a)(3), (4), or (5) 

of this chapter, where such control 

period and the recipient are covered by 

the provisions of paragraph (c)(1)(i) of 

this section or were allocated under 

§ 97.412(a)(2) through (7), (9), and (12) 

and (b)(2) through (7), (9), and (12), or 

under a provision of a SIP revision 

approved under § 52.38(a)(4) or (5) of 

this chapter, where such control period 

and the recipient are covered by the 


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provisions of paragraph (c)(1)(ii) of this 

section, then the Administrator will 

notify the designated representative of 

the recipient and will act in accordance 

with the procedures set forth in 

paragraphs (c)(2) through (5) of this 

section: 

(i)(A) The recipient is not actually a 

TR NOX Annual unit under § 97.404 as 

of January 1, 2012 and is allocated TR 

NOX Annual allowances for such 

control period or, in the case of an 

allocation under a provision of a SIP 

revision approved under § 52.38(a)(3), 

(4), or (5) of this chapter, the recipient 

is not actually a TR NOX Annual unit 

as of January 1, 2012 and is allocated TR 

NOX Annual allowances for such 

control period that the SIP revision 

provides should be allocated only to 

recipients that are TR NOX Annual units 

as of January 1, 2012; or 

(B) The recipient is not located as of 

January 1 of the control period in the 

State from whose NOX Annual trading 

budget the TR NOX Annual allowances 

allocated under paragraph (a) of this 

section, or under a provision of a SIP 

revision approved under § 52.38(a)(3), 

(4), or (5) of this chapter, were allocated 

for such control period. 

(ii) The recipient is not actually a TR 

NOX Annual unit under § 97.404 as of 

January 1 of such control period and is 

allocated TR NOX Annual allowances 

for such control period or, in the case 

of an allocation under a provision of a 

SIP revision approved under 

§ 52.38(a)(3), (4), or (5) of this chapter, 

the recipient is not actually a TR NOX

Annual unit as of January 1 of such 

control period and is allocated TR NOX

Annual allowances for such control 

period that the SIP revision provides 

should be allocated only to recipients 

that are TR NOX Annual units as of 

January 1 of such control period. 

(2) Except as provided in paragraph 

(c)(3) or (4) of this section, the 

Administrator will not record such TR 

NOX Annual allowances under § 97.421. 

(3) If the Administrator already 

recorded such TR NOX Annual 

allowances under § 97.421 and if the 

Administrator makes the determination 

under paragraph (c)(1) of this section 

before making deductions for the source 

that includes such recipient under 

§ 97.424(b) for such control period, then 

the Administrator will deduct from the 

account in which such TR NOX Annual 

allowances were recorded an amount of 

TR NOX Annual allowances allocated 

for the same or a prior control period 

equal to the amount of such already 

recorded TR NOX Annual allowances. 

The authorized account representative 

shall ensure that there are sufficient TR 

NOX Annual allowances in such 

account for completion of the 

deduction. 

(4) If the Administrator already 

recorded such TR NOX Annual 

allowances under § 97.421 and if the 

Administrator makes the determination 

under paragraph (c)(1) of this section 

after making deductions for the source 

that includes such recipient under 

§ 97.424(b) for such control period, then 

the Administrator will not make any 

deduction to take account of such 

already recorded TR NOX Annual 

allowances. 

(5)(i) With regard to the TR NOX

Annual allowances that are not 

recorded, or that are deducted as an 

incorrect allocation, in accordance with 

paragraphs (c)(2) and (3) of this section 

for a recipient under paragraph (c)(1)(i) 

of this section, the Administrator will: 

(A) Transfer such TR NOX Annual 

allowances to the new unit set-aside for 

such control period for the State from 

whose NOX Annual trading budget the 

TR NOX Annual allowances were 

allocated; or 

(B) If the State has a SIP revision 

approved under § 52.38(a)(4) or (5) 

covering such control period, include 

such TR NOX Annual allowances in the 

portion of the State NOX Annual trading 

budget that may be allocated for such 

control period in accordance with such 

SIP revision. 

(ii) With regard to the TR NOX Annual 

allowances that were not allocated from 

the Indian country new unit set-aside 

for such control period and that are not 

recorded, or that are deducted as an 

incorrect allocation, in accordance with 

paragraphs (c)(2) and (3) of this section 

for a recipient under paragraph (c)(1)(ii) 

of this paragraph, the Administrator 

will: 

(A) Transfer such TR NOX Annual 

allowances to the new unit set-aside for 

such control period; or 

(B) If the State has a SIP revision 

approved under § 52.38(a)(4) or (5) 

covering such control period, include 

such TR NOX Annual allowances in the 

portion of the State NOX Annual trading 

budget that may be allocated for such 

control period in accordance with such 

SIP revision. 

(iii) With regard to the TR NOX

Annual allowances that were allocated 

from the Indian country new unit setaside for such control period and that 

are not recorded, or that are deducted as 

an incorrect allocation, in accordance 

with paragraphs (c)(2) and (3) of this 

section for a recipient under paragraph 

(c)(1)(ii) of this paragraph, the 

Administrator will transfer such TR 

NOX Annual allowances to the Indian 

country new unit set-aside for such 

control period. 

§ 97.412 TR NOX Annual allowance 

allocations to new units. 

(a) For each control period in 2012 

and thereafter and for the TR NOX

Annual units in each State, the 

Administrator will allocate TR NOX

Annual allowances to the TR NOX

Annual units as follows: 

(1) The TR NOX Annual allowances 

will be allocated to the following TR 

NOX Annual units, except as provided 

in paragraph (a)(10) of this section: 

(i) TR NOX Annual units that are not 

allocated an amount of TR NOX Annual 

allowances in the notice of data 

availability issued under § 97.411(a)(1); 

(ii) TR NOX Annual units whose 

allocation of an amount of TR NOX

Annual allowances for such control 

period in the notice of data availability 

issued under § 97.411(a)(1) is covered 

by § 97.411(c)(2) or (3); 

(iii) TR NOX Annual units that are 

allocated an amount of TR NOX Annual 

allowances for such control period in 

the notice of data availability issued 

under § 97.411(a)(1), which allocation is 

terminated for such control period 

pursuant to § 97.411(a)(2), and that 

operate during the control period 

immediately preceding such control 

period; or 

(iv) For purposes of paragraph (a)(9) 

of this section, TR NOX Annual units 

under § 97.411(c)(1)(ii) whose allocation 

of an amount of TR NOX Annual 

allowances for such control period in 

the notice of data availability issued 

under § 97.411(b)(1)(ii)(B) is covered by 

§ 97.411(c)(2) or (3). 

(2) The Administrator will establish a 

separate new unit set-aside for the State 

for each such control period. Each such 

new unit 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(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 State after operating 

in another jurisdiction and for which 


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the unit is not already allocated one or 

more TR NOX Annual allowances; and 

(iv) For a unit described in paragraph 

(a)(1)(iii) of this section, the first control 

period after the control period in which 

the unit resumes operation. 

(4)(i) The allocation to each TR NOX

annual unit described in paragraph 

(a)(1)(i) through (iii) of this section and 

for each control period described in 

paragraph (a)(3) of this section will be 

an amount equal to the unit’s total tons 

of NOX emissions during the 

immediately preceding control period. 

(ii) The Administrator will adjust the 

allocation amount in paragraph (a)(4)(i) 

in accordance with paragraphs (a)(5) 

through (7) and (12) of this section. 

(5) The Administrator will calculate 

the sum of the TR NOX Annual 

allowances determined for all such TR 

NOX Annual units under paragraph 

(a)(4)(i) of this section in the State for 

such control period. 

(6) If the amount of TR NOX Annual 

allowances in the new unit 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 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 

§ 97.411(b)(1)(i) and (ii), of the amount 

of TR NOX Annual allowances allocated 

under paragraphs (a)(2) through (7) and 

(12) of this section for such control 

period to each TR NOX Annual unit 

eligible for such allocation. 

(9) If, after completion of the 

procedures under paragraphs (a)(5) 

through (8) of this section for such 

control period, any unallocated TR NOX

Annual allowances remain in the new 

unit set-aside for the State for such 

control period, the Administrator will 

allocate such TR NOX Annual 

allowances as follows— 

(i) The Administrator will determine, 

for each unit described in paragraph 

(a)(1) of this section that commenced 

commercial operation during the period 

starting January 1 of the year before the 

year of such control period and ending 

November 30 of year of such control 

period, the positive difference (if any) 

between the unit’s emissions during 

such control period and the amount of 

TR NOX Annual allowances referenced 

in the notice of data availability 

required under § 97.411(b)(1)(ii) for the 

unit for such control period; 

(ii) The Administrator will determine 

the sum of the positive differences 

determined under paragraph (a)(9)(i) of 

this section; 

(iii) If the amount of unallocated TR 

NOX Annual allowances remaining in 

the new unit set-aside for the State for 

such control period is greater than or 

equal to the sum determined under 

paragraph (a)(9)(ii) of this section, then 

the Administrator will allocate the 

amount of TR NOX Annual allowances 

determined for each such TR NOX

Annual unit under paragraph (a)(9)(i) of 

this section; and 

(iv) If the amount of unallocated TR 

NOX Annual allowances remaining in 

the new unit set-aside for the State for 

such control period is less than the sum 

under paragraph (a)(9)(ii) of this section, 

then the Administrator will allocate to 

each such TR NOX Annual unit the 

amount of the TR NOX Annual 

allowances determined under paragraph 

(a)(9)(i) of this section for the unit, 

multiplied by the amount of unallocated 

TR NOX Annual allowances remaining 

in the new unit set-aside for such 

control period, divided by the sum 

under paragraph (a)(9)(ii) of this section, 

and rounded to the nearest allowance. 

(10) If, after completion of the 

procedures under paragraphs (a)(9) and 

(12) of this section for such control 

period, any unallocated TR NOX Annual 

allowances remain in the new unit setaside 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), (iv), and (v), of the 

amount of TR NOX Annual allowances 

allocated under paragraphs (a)(9), (10), 

and (12) of this section for such control 

period to each TR NOX Annual unit 

eligible for such allocation. 

(12)(i) Notwithstanding the 

requirements of paragraphs (a)(2) 

through (11) of this section, if the 

calculations of allocations of a new unit 

set-aside for a control period in a given 

year under paragraph (a)(7) of this 

section, paragraphs (a)(6) and (9)(iv) of 

this section, or paragraphs (a)(6), (9)(iii), 

and (10) of this section would otherwise 

result in total allocations of such new 

unit set-aside exceeding the total 

amount of such new unit set-aside, then 

the Administrator will adjust the results 

of the calculations under paragraph 

(a)(7), (9)(iv), or (10) of this section, as 

applicable, as follows. The 

Administrator will list the TR NOX

Annual units in descending order based 

on the amount of such units’ allocations 

under paragraph (a)(7), (9)(iv), or (10) of 

this section, as applicable, and, in cases 

of equal allocation amounts, in 

alphabetical order of the relevant 

source’s name and numerical order of 

the relevant unit’s identification 

number, and will reduce each unit’s 

allocation under paragraph (a)(7), 

(9)(iv), or (10) of this section, as 

applicable, by one TR NOX Annual 

allowance (but not below zero) in the 

order in which the units are listed and 

will repeat this reduction process as 

necessary, until the total allocations of 

such new unit set-aside equal the total 

amount of such new unit set-aside. 

(ii) Notwithstanding the requirements 

of paragraphs (a)(10) and (11) of this 

section, if the calculations of allocations 

of a new unit set-aside for a control 

period in a given year under paragraphs 

(a)(6), (9)(iii), and (10) of this section 

would otherwise result in a total 

allocations of such new unit set-aside 

less than the total amount of such new 

unit set-aside, then the Administrator 

will adjust the results of the calculations 

under paragraph (a)(10) of this section, 

as follows. The Administrator will list 

the TR NOX Annual units in descending 

order based on the amount of such 

units’ allocations under paragraph 

(a)(10) of this section and, in cases of 

equal allocation amounts, in 

alphabetical order of the relevant 

source’s name and numerical order of 

the relevant unit’s identification 

number, and will increase each unit’s 


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allocation under paragraph (a)(10) of 

this section by one TR NOX Annual 

allowance in the order in which the 

units are listed and will repeat this 

increase process as necessary, until the 

total allocations of such new unit setaside equal the total amount of such 

new unit set-aside. 

(b) For each control period in 2012 

and thereafter and for the TR NOX

Annual units located in Indian country 

within the borders of each State, the 

Administrator will allocate TR NOX

Annual allowances to the TR NOX

Annual units as follows: 

(1) The TR NOX Annual allowances 

will be allocated to the following TR 

NOX Annual units, except as provided 

in paragraph (b)(10) of this section: 

(i) TR NOX Annual units that are not 

allocated an amount of TR NOX Annual 

allowances in the notice of data 

availability issued under § 97.411(a)(1); 

or 

(ii) For purposes of paragraph (b)(9) of 

this section, TR NOX Annual units 

under § 97.411(c)(1)(ii) whose allocation 

of an amount of TR NOX Annual 

allowances for such control period in 

the notice of data availability issued 

under § 97.411(b)(2)(ii)(B) is covered by 

§ 97.411(c)(2) or (3). 

(2) The Administrator will establish a 

separate Indian country new unit setaside 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). 

(3) The Administrator will determine, 

for each TR NOX Annual unit described 

in paragraph (b)(1) of this section, an 

allocation of TR NOX Annual 

allowances for the later of the following 

control periods and for each subsequent 

control period: 

(i) The control period in 2012; and 

(ii) The first control period after the 

control period in which the TR NOX

Annual unit commences commercial 

operation. 

(4)(i) The allocation to each TR NOX

annual unit described in paragraph 

(b)(1)(i) of this section and for each 

control period described in paragraph 

(b)(3) of this section will be an amount 

equal to the unit’s total tons of NOX

emissions during the immediately 

preceding control period. 

(ii) The Administrator will adjust the 

allocation amount in paragraph (b)(4)(i) 

in accordance with paragraphs (b)(5) 

through (7) and (12) of this section. 

(5) The Administrator will calculate 

the sum of the TR NOX Annual 

allowances determined for all such TR 

NOX Annual units under paragraph 

(b)(4)(i) of this section in Indian country 

within the borders of the State for such 

control period. 

(6) If the amount of TR NOX Annual 

allowances in the Indian country new 

unit set-aside for the State for such 

control period is greater than or equal to 

the sum under paragraph (b)(5) of this 

section, then the Administrator will 

allocate the amount of TR NOX Annual 

allowances determined for each such TR 

NOX Annual unit under paragraph 

(b)(4)(i) of this section. 

(7) If the amount of TR NOX Annual 

allowances in the Indian country new 

unit set-aside for the State for such 

control period is less than the sum 

under paragraph (b)(5) of this section, 

then the Administrator will allocate to 

each such TR NOX Annual unit the 

amount of the TR NOX Annual 

allowances determined under paragraph 

(b)(4)(i) of this section for the unit, 

multiplied by the amount of TR NOX

Annual allowances in the Indian 

country new unit set-aside for such 

control period, divided by the sum 

under paragraph (b)(5) of this section, 

and rounded to the nearest allowance. 

(8) The Administrator will notify the 

public, through the promulgation of the 

notices of data availability described in 

§ 97.411(b)(2)(i) and (ii), of the amount 

of TR NOX Annual allowances allocated 

under paragraphs (b)(2) through (7) and 

(12) of this section for such control 

period to each TR NOX Annual unit 

eligible for such allocation. 

(9) If, after completion of the 

procedures under paragraphs (b)(5) 

through (8) of this section for such 

control period, any unallocated 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 referenced 

in the notice of data availability 

required under § 97.411(b)(2)(ii) for the 

unit for such control period; 

(ii) The Administrator will determine 

the sum of the positive differences 

determined under paragraph (b)(9)(i) of 

this section; 

(iii) If the amount of unallocated TR 

NOX Annual allowances remaining in 

the Indian country new unit set-aside 

for the State for such control period is 

greater than or equal to the sum 

determined under paragraph (b)(9)(ii) of 

this section, then the Administrator will 

allocate the amount of TR NOX Annual 

allowances determined for each such TR 

NOX Annual unit under paragraph 

(b)(9)(i) of this section; and 

(iv) If the amount of unallocated TR 

NOX Annual allowances remaining in 

the Indian country new unit set-aside 

for the State for such control period is 

less than the sum under paragraph 

(b)(9)(ii) of this section, then the 

Administrator will allocate to each such 

TR NOX Annual unit the amount of the 

TR NOX Annual allowances determined 

under paragraph (b)(9)(i) of this section 

for the unit, multiplied by the amount 

of unallocated TR NOX Annual 

allowances remaining in the Indian 

country new unit set-aside for such 

control period, divided by the sum 

under paragraph (b)(9)(ii) of this section, 

and rounded to the nearest allowance. 

(10) If, after completion of the 

procedures under paragraphs (b)(9) and 

(12) of this section for such control 

period, any unallocated TR NOX Annual 

allowances remain in the Indian country 

new unit set-aside for the State for such 

control period, the Administrator will: 

(i) Transfer such unallocated TR NOX

Annual allowances to the new unit setaside for the State for such control 

period; or 

(ii) If the State has a SIP revision 

approved under § 52.38(a)(4) or (5) 

covering such control period, include 

such unallocated TR NOX Annual 

allowances in the portion of the State 

NOX Annual trading budget that may be 

allocated for such control period in 

accordance with such SIP revision. 

(11) The Administrator will notify the 

public, through the promulgation of the 

notices of data availability described in 

§ 97.411(b)(2)(iii), (iv), and (v), of the 

amount of TR NOX Annual allowances 

allocated under paragraphs (b)(9), (10), 

and (12) of this section for such control 

period to each TR NOX Annual unit 

eligible for such allocation. 

(12)(i) Notwithstanding the 

requirements of paragraphs (b)(2) 

through (11) of this section, if the 

calculations of allocations of an Indian 

country new unit set-aside for a control 

period in a given year under paragraph 

(b)(7) of this section, paragraphs (b)(6) 

and (9)(iv) of this section, or paragraphs 

(b)(6), (9)(iii), and (10) of this section 

would otherwise result in total 

allocations of such Indian country new 

unit set-aside exceeding the total 

amount of such Indian country new unit 

set-aside, then the Administrator will 

adjust the results of the calculations 


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under paragraph (b)(7), (9)(iv), or (10) of 

this section, as applicable, as follows. 

The Administrator will list the TR NOX

Annual units in descending order based 

on the amount of such units’ allocations 

under paragraph (b)(7), (9)(iv), or (10) of 

this section, as applicable, and, in cases 

of equal allocation amounts, in 

alphabetical order of the relevant 

source’s name and numerical order of 

the relevant unit’s identification 

number, and will reduce each unit’s 

allocation under paragraph (b)(7), 

(9)(iv), or (10) of this section, as 

applicable, by one TR NOX Annual 

allowance (but not below zero) in the 

order in which the units are listed and 

will repeat this reduction process as 

necessary, until the total allocations of 

such Indian country new unit set-aside 

equal the total amount of such Indian 

country new unit set-aside. 

(ii) Notwithstanding the requirements 

of paragraphs (b)(10) and (11) of this 

section, if the calculations of allocations 

of an Indian country new unit set-aside 

for a control period in a given year 

under paragraphs (b)(6), (9)(iii), and (10) 

of this section would otherwise result in 

a total allocations of such Indian 

country new unit set-aside less than the 

total amount of such Indian country 

new unit set-aside, then the 

Administrator will adjust the results of 

the calculations under paragraph (b)(10) 

of this section, as follows. The 

Administrator will list the TR NOX

Annual units in descending order based 

on the amount of such units’ allocations 

under paragraph (b)(10) of this section 

and, in cases of equal allocation 

amounts, in alphabetical order of the 

relevant source’s name and numerical 

order of the relevant unit’s 

identification number, and will increase 

each unit’s allocation under paragraph 

(b)(10) of this section by one TR NOX

Annual allowance in the order in which 

the units are listed and will repeat this 

increase process as necessary, until the 

total allocations of such Indian country 

new unit set-aside equal the total 

amount of such Indian country new unit 

set-aside. 

§ 97.413 Authorization of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.415, 

each TR NOX Annual source, including 

all TR NOX Annual units at the source, 

shall have one and only one designated 

representative, with regard to all matters 

under the TR NOX Annual Trading 

Program. 

(1) The designated representative 

shall be selected by an agreement 

binding on the owners and operators of 

the source and all TR NOX Annual units 

at the source and shall act in accordance 

with the certification statement in 

§ 97.416(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.416: 

(i) The designated representative shall 

be authorized and shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each owner and operator of the source 

and each TR NOX Annual unit at the 

source in all matters pertaining to the 

TR NOX Annual Trading Program, 

notwithstanding any agreement between 

the designated representative and such 

owners and operators; and 

(ii) The owners and operators of the 

source and each TR NOX Annual unit at 

the source shall be bound by any 

decision or order issued to the 

designated representative by the 

Administrator regarding the source or 

any such unit. 

(b) Except as provided under § 97.415, 

each TR NOX Annual source may have 

one and only one alternate designated 

representative, who may act on behalf of 

the designated representative. The 

agreement by which the alternate 

designated representative is selected 

shall include a procedure for 

authorizing the alternate designated 

representative to act in lieu of the 

designated representative. 

(1) The alternate designated 

representative shall be selected by an 

agreement binding on the owners and 

operators of the source and all TR NOX

Annual units at the source and shall act 

in accordance with the certification 

statement in § 97.416(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.416, 

(i) The alternate designated 

representative shall be authorized; 

(ii) Any representation, action, 

inaction, or submission by the alternate 

designated representative shall be 

deemed to be a representation, action, 

inaction, or submission by the 

designated representative; and 

(iii) The owners and operators of the 

source and each TR NOX Annual unit at 

the source shall be bound by any 

decision or order issued to the alternate 

designated representative by the 

Administrator regarding the source or 

any such unit. 

(c) Except in this section, § 97.402, 

and §§ 97.414 through 97.418, whenever 

the term ‘‘designated representative’’ (as 

distinguished from the term ‘‘common 

designated representative’’) is used in 

this subpart, the term shall be construed 

to include the designated representative 

or any alternate designated 

representative. 

§ 97.414 Responsibilities of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.418 

concerning delegation of authority to 

make submissions, each submission 

under the TR NOX Annual Trading 

Program shall be made, signed, and 

certified by the designated 

representative or alternate designated 

representative for each TR NOX Annual 

source and TR NOX Annual unit for 

which the submission is made. Each 

such submission shall include the 

following certification statement by the 

designated representative or alternate 

designated representative: ‘‘I am 

authorized to make this submission on 

behalf of the owners and operators of 

the source or units for which the 

submission is made. I certify under 

penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(b) The Administrator will accept or 

act on a submission made for a TR NOX

Annual source or a TR NOX Annual unit 

only if the submission has been made, 

signed, and certified in accordance with 

paragraph (a) of this section and 

§ 97.418. 

§ 97.415 Changing designated 

representative and alternate designated 

representative; changes in owners and 

operators; 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 


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time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.416. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous alternate 

designated representative before the 

time and date when the Administrator 

receives the superseding certificate of 

representation shall be binding on the 

new alternate designated representative, 

the designated representative, and the 

owners and operators of the TR NOX

Annual source and the TR NOX Annual 

units at the source. 

(c) Changes in owners and operators. 

(1) In the event an owner or operator of 

a TR NOX Annual source or a TR NOX

Annual unit at the source is not 

included in the list of owners and 

operators in the certificate of 

representation under § 97.416, such 

owner or operator shall be deemed to be 

subject to and bound by the certificate 

of representation, the representations, 

actions, inactions, and submissions of 

the designated representative and any 

alternate designated representative of 

the source or unit, and the decisions 

and orders of the Administrator, as if 

the owner or operator were included in 

such list. 

(2) Within 30 days after any change in 

the owners and operators of a TR NOX

Annual source or a TR NOX Annual unit 

at the source, including the addition or 

removal of an owner or operator, the 

designated representative or any 

alternate designated representative shall 

submit a revision to the certificate of 

representation under § 97.416 amending 

the list of owners and operators to 

reflect the change. 

(d) Changes in units at the source. 

Within 30 days of any change in which 

units are located at a TR NOX Annual 

source (including the addition or 

removal of a unit), the designated 

representative or any alternate 

designated representative shall submit a 

certificate of representation under 

§ 97.416 amending the list of units to 

reflect the change. 

(1) If the change is the addition of a 

unit that operated (other than for 

purposes of testing by the manufacturer 

before initial installation) before being 

located at the source, then the certificate 

of representation shall identify, in a 

format prescribed by the Administrator, 

the entity from whom the unit was 

purchased or otherwise obtained 

(including name, address, telephone 

number, and facsimile number (if any)), 

the date on which the unit was 

purchased or otherwise obtained, and 

the date on which the unit became 

located at the source. 

(2) If the change is the removal of a 

unit, then the certificate of 

representation shall identify, in a format 

prescribed by the Administrator, the 

entity to which the unit was sold or that 

otherwise obtained the unit (including 

name, address, telephone number, and 

facsimile number (if any)), the date on 

which the unit was sold or otherwise 

obtained, and the date on which the 

unit became no longer located at the 

source. 

§ 97.416 Certificate of representation. 

(a) A complete certificate of 

representation for a designated 

representative or an alternate designated 

representative shall include the 

following elements in a format 

prescribed by the Administrator: 

(1) Identification of the TR NOX

Annual source, and each TR NOX

Annual unit at the source, for which the 

certificate of representation is 

submitted, including source name, 

source category and NAICS code (or, in 

the absence of a NAICS code, an 

equivalent code), State, plant code, 

county, latitude and longitude, unit 

identification number and type, 

identification number and nameplate 

capacity (in MWe, rounded to the 

nearest tenth) of each generator served 

by each such unit, actual or projected 

date of commencement of commercial 

operation, and a statement of whether 

such source is located in Indian 

Country. If a projected date of 

commencement of commercial 

operation is provided, the actual date of 

commencement of commercial 

operation shall be provided when such 

information becomes available. 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the designated representative and any 

alternate designated representative. 

(3) A list of the owners and operators 

of the TR NOX Annual source and of 

each TR NOX Annual unit at the source. 

(4) The following certification 

statements by the designated 

representative and any alternate 

designated representative— 

(i) ‘‘I certify that I was selected as the 

designated representative or alternate 

designated representative, as applicable, 

by an agreement binding on the owners 

and operators of the source and each TR 

NOX Annual unit at the source.’’ 

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the TR 

NOX Annual Trading Program on behalf 

of the owners and operators of the 

source and of each TR NOX Annual unit 

at the source and that each such owner 

and operator shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any decision or 

order issued to me by the Administrator 

regarding the source or unit.’’ 

(iii) ‘‘Where there are multiple 

holders of a legal or equitable title to, or 

a leasehold interest in, a TR NOX

Annual unit, or where a utility or 

industrial customer purchases power 

from a TR NOX Annual unit under a 

life-of-the-unit, firm power contractual 

arrangement, I certify that: I have given 

a written notice of my selection as the 

‘designated representative’ or ‘alternate 

designated representative’, as 

applicable, and of the agreement by 

which I was selected to each owner and 

operator of the source and of each TR 

NOX Annual unit at the source; and TR 

NOX Annual allowances and proceeds 

of transactions involving TR NOX

Annual allowances will be deemed to be 

held or distributed in proportion to each 

holder’s legal, equitable, leasehold, or 

contractual reservation or entitlement, 

except that, if such multiple holders 

have expressly provided for a different 

distribution of TR NOX Annual 

allowances by contract, TR NOX Annual 

allowances and proceeds of transactions 

involving TR NOX Annual allowances 

will be deemed to be held or distributed 

in accordance with the contract.’’ 

(5) The signature of the designated 

representative and any alternate 

designated representative and the dates 

signed. 

(b) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the certificate of 

representation shall not be submitted to 

the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

§ 97.417 Objections concerning 

designated representative and alternate 

designated representative. 

(a) Once a complete certificate of 

representation under § 97.416 has been 

submitted and received, the 

Administrator will rely on the certificate 

of representation unless and until a 

superseding complete certificate of 

representation under § 97.416 is 

received by the Administrator. 

(b) Except as provided in paragraph 

(a) of this section, no objection or other 

communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission, of a 

designated representative or alternate 

designated representative shall affect 

any representation, action, inaction, or 

submission of the designated 

representative or alternate designated 

representative or the finality of any 


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decision or order by the Administrator 

under the TR NOX Annual Trading 

Program. 

(c) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of any designated 

representative or alternate designated 

representative, including private legal 

disputes concerning the proceeds of TR 

NOX Annual allowance transfers. 

§ 97.418 Delegation by designated 

representative and alternate designated 

representative. 

(a) A designated representative may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(b) An alternate designated 

representative may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(c) In order to delegate authority to a 

natural person to make an electronic 

submission to the Administrator in 

accordance with paragraph (a) or (b) of 

this section, the designated 

representative or alternate designated 

representative, as appropriate, must 

submit to the Administrator a notice of 

delegation, in a format prescribed by the 

Administrator, that includes the 

following elements: 

(1) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of such 

designated representative or alternate 

designated representative; 

(2) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of each 

such natural person (referred to in this 

section as an ‘‘agent’’); 

(3) For each such natural person, a list 

of the type or types of electronic 

submissions under paragraph (a) or (b) 

of this section for which authority is 

delegated to him or her; and 

(4) The following certification 

statements by such designated 

representative or alternate designated 

representative: 

(i) ‘‘I agree that any electronic 

submission to the Administrator that is 

made by an agent identified in this 

notice of delegation and of a type listed 

for such agent in this notice of 

delegation and that is made when I am 

a designated representative or alternate 

designated representative, as 

appropriate, and before this notice of 

delegation is superseded by another 

notice of delegation under 40 CFR 

97.418(d) shall be deemed to be an 

electronic submission by me.’’ 

(ii) ‘‘Until this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 97.418(d), I 

agree to maintain an e-mail account and 

to notify the Administrator immediately 

of any change in my e-mail address 

unless all delegation of authority by me 

under 40 CFR 97.418 is terminated.’’. 

(d) A notice of delegation submitted 

under paragraph (c) of this section shall 

be effective, with regard to the 

designated representative or alternate 

designated representative identified in 

such notice, upon receipt of such notice 

by the Administrator and until receipt 

by the Administrator of a superseding 

notice of delegation submitted by such 

designated representative or alternate 

designated representative, as 

appropriate. The superseding notice of 

delegation may replace any previously 

identified agent, add a new agent, or 

eliminate entirely any delegation of 

authority. 

(e) Any electronic submission covered 

by the certification in paragraph (c)(4)(i) 

of this section and made in accordance 

with a notice of delegation effective 

under paragraph (d) of this section shall 

be deemed to be an electronic 

submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

§ 97.419 [Reserved] 

§ 97.420 Establishment of compliance 

accounts, assurance accounts, and general 

accounts. 

(a) Compliance accounts. Upon 

receipt of a complete certificate of 

representation under § 97.416, the 

Administrator will establish a 

compliance account for the TR NOX

Annual source for which the certificate 

of representation was submitted, unless 

the source already has a compliance 

account. The designated representative 

and any alternate designated 

representative of the source shall be the 

authorized account representative and 

the alternate authorized account 

representative respectively of the 

compliance account. 

(b) Assurance accounts. The 

Administrator will establish assurance 

accounts for certain owners and 

operators and States in accordance with 

§ 97.425(b)(3). 

(c) General accounts. (1) Application 

for general account. (i) Any person may 

apply to open a general account, for the 

purpose of holding and transferring TR 

NOX Annual allowances, by submitting 

to the Administrator a complete 

application for a general account. Such 

application shall designate one and only 

one authorized account representative 

and may designate one and only one 

alternate authorized account 

representative who may act on behalf of 

the authorized account representative. 

(A) The authorized account 

representative and alternate authorized 

account representative shall be selected 

by an agreement binding on the persons 

who have an ownership interest with 

respect to TR NOX Annual allowances 

held in the general account. 

(B) The agreement by which the 

alternate authorized account 

representative is selected shall include 

a procedure for authorizing the alternate 

authorized account representative to act 

in lieu of the authorized account 

representative. 

(ii) A complete application for a 

general account shall include the 

following elements in a format 

prescribed by the Administrator: 

(A) Name, mailing address, e-mail 

address (if any), telephone number, and 

facsimile transmission number (if any) 

of the authorized account representative 

and any alternate authorized account 

representative; 

(B) An identifying name for the 

general account; 

(C) A list of all persons subject to a 

binding agreement for the authorized 

account representative and any alternate 

authorized account representative to 

represent their ownership interest with 

respect to the TR NOX Annual 

allowances held in the general account; 

(D) The following certification 

statement by the authorized account 

representative and any alternate 

authorized account representative: ‘‘I 

certify that I was selected as the 

authorized account representative or the 

alternate authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to TR NOX Annual allowances 

held in the general account. I certify that 

I have all the necessary authority to 

carry out my duties and responsibilities 

under the TR NOX Annual Trading 

Program on behalf of such persons and 

that each such person shall be fully 

bound by my representations, actions, 

inactions, or submissions and by any 

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 


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general account shall not be submitted 

to the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

(2) Authorization of authorized 

account representative and alternate 

authorized account representative. (i) 

Upon receipt by the Administrator of a 

complete application for a general 

account under paragraph (b)(1) of this 

section, the Administrator will establish 

a general account for the person or 

persons for whom the application is 

submitted, and upon and after such 

receipt by the Administrator: 

(A) The authorized account 

representative of the general account 

shall be authorized and shall represent 

and, by his or her representations, 

actions, inactions, or submissions, 

legally bind each person who has an 

ownership interest with respect to TR 

NOX Annual allowances held in the 

general account in all matters pertaining 

to the TR NOX Annual Trading Program, 

notwithstanding any agreement between 

the authorized account representative 

and such person. 

(B) Any alternate authorized account 

representative shall be authorized, and 

any representation, action, inaction, or 

submission by any alternate authorized 

account representative shall be deemed 

to be a representation, action, inaction, 

or submission by the authorized account 

representative. 

(C) Each person who has an 

ownership interest with respect to TR 

NOX Annual allowances held in the 

general account shall be bound by any 

decision or order issued to the 

authorized account representative or 

alternate authorized account 

representative by the Administrator 

regarding the general account. 

(ii) Except as provided in paragraph 

(c)(5) of this section concerning 

delegation of authority to make 

submissions, each submission 

concerning the general account shall be 

made, signed, and certified by the 

authorized account representative or 

any alternate authorized account 

representative for the persons having an 

ownership interest with respect to TR 

NOX Annual allowances held in the 

general account. Each such submission 

shall include the following certification 

statement by the authorized account 

representative or any alternate 

authorized account representative: ‘‘I 

am authorized to make this submission 

on behalf of the persons having an 

ownership interest with respect to the 

TR NOX Annual allowances held in the 

general account. I certify under penalty 

of law that I have personally examined, 

and am familiar with, the statements 

and information submitted in this 

document and all its attachments. Based 

on my inquiry of those individuals with 

primary responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(iii) Except in this section, whenever 

the term ‘‘authorized account 

representative’’ is used in this subpart, 

the term shall be construed to include 

the authorized account representative or 

any alternate authorized account 

representative. 

(3) Changing authorized account 

representative and alternate authorized 

account representative; changes in 

persons with ownership interest. (i) The 

authorized account representative of a 

general account may be changed at any 

time upon receipt by the Administrator 

of a superseding complete application 

for a general account under paragraph 

(c)(1) of this section. Notwithstanding 

any such change, all representations, 

actions, inactions, and submissions by 

the previous authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

authorized account representative and 

the persons with an ownership interest 

with respect to the TR NOX Annual 

allowances in the general account. 

(ii) The alternate authorized account 

representative of a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (c)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous alternate authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

alternate authorized account 

representative, the authorized account 

representative, and the persons with an 

ownership interest with respect to the 

TR NOX Annual allowances in the 

general account. 

(iii)(A) In the event a person having 

an ownership interest with respect to 

TR NOX Annual allowances in the 

general account is not included in the 

list of such persons in the application 

for a general account, such person shall 

be deemed to be subject to and bound 

by the application for a general account, 

the representation, actions, inactions, 

and submissions of the authorized 

account representative and any alternate 

authorized account representative of the 

account, and the decisions and orders of 

the Administrator, as if the person were 

included in such list. 

(B) Within 30 days after any change 

in the persons having an ownership 

interest with respect to NOX Annual 

allowances in the general account, 

including the addition or removal of a 

person, the authorized account 

representative or any alternate 

authorized account representative shall 

submit a revision to the application for 

a general account amending the list of 

persons having an ownership interest 

with respect to the TR NOX Annual 

allowances in the general account to 

include the change. 

(4) Objections concerning authorized 

account representative and alternate 

authorized account representative. (i) 

Once a complete application for a 

general account under paragraph (c)(1) 

of this section has been submitted and 

received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section is received by the 

Administrator. 

(ii) Except as provided in paragraph 

(c)(4)(i) of this section, no objection or 

other communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission of the 

authorized account representative or 

any alternate authorized account 

representative of a general account shall 

affect any representation, action, 

inaction, or submission of the 

authorized account representative or 

any alternate authorized account 

representative or the finality of any 

decision or order by the Administrator 

under the TR NOX Annual Trading 

Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account, including private legal 

disputes concerning the proceeds of TR 

NOX Annual allowance transfers. 

(5) Delegation by authorized account 

representative and alternate authorized 

account representative. (i) An 

authorized account representative of a 

general account may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 


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provided for or required under this 

subpart. 

(ii) An alternate authorized account 

representative of a general account may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(iii) In order to delegate authority to 

a natural person to make an electronic 

submission to the Administrator in 

accordance with paragraph (c)(5)(i) or 

(ii) of this section, the authorized 

account representative or alternate 

authorized account representative, as 

appropriate, must submit to the 

Administrator a notice of delegation, in 

a format prescribed by the 

Administrator, that includes the 

following elements: 

(A) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of such authorized account 

representative or alternate authorized 

account representative; 

(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 unless all 

delegation of authority by me under 40 

CFR 97.420(c)(5) is terminated.’’. 

(iv) A notice of delegation submitted 

under paragraph (c)(5)(iii) of this section 

shall be effective, with regard to the 

authorized account representative or 

alternate authorized account 

representative identified in such notice, 

upon receipt of such notice by the 

Administrator and until receipt by the 

Administrator of a superseding notice of 

delegation submitted by such 

authorized account representative or 

alternate authorized account 

representative, as appropriate. The 

superseding notice of delegation may 

replace any previously identified agent, 

add a new agent, or eliminate entirely 

any delegation of authority. 

(v) Any electronic submission covered 

by the certification in paragraph 

(c)(5)(iii)(D) of this section and made in 

accordance with a notice of delegation 

effective under paragraph (c)(5)(iv) of 

this section shall be deemed to be an 

electronic submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

(6) Closing a general account. (i) The 

authorized account representative or 

alternate authorized account 

representative of a general account may 

submit to the Administrator a request to 

close the account. Such request shall 

include a correctly submitted TR NOX

Annual allowance transfer under 

§ 97.422 for any TR NOX Annual 

allowances in the account to one or 

more other Allowance Management 

System accounts. 

(ii) If a general account has no TR 

NOX Annual allowance transfers to or 

from the account for a 12-month period 

or longer and does not contain any TR 

NOX Annual allowances, the 

Administrator may notify the authorized 

account representative for the account 

that the account will be closed after 30 

days after the notice is sent. The 

account will be closed after the 30-day 

period unless, before the end of the 30- 

day period, the Administrator receives a 

correctly submitted TR NOX Annual 

allowance transfer under § 97.422 to the 

account or a statement submitted by the 

authorized account representative or 

alternate authorized account 

representative demonstrating to the 

satisfaction of the Administrator good 

cause as to why the account should not 

be closed. 

(d) Account identification. The 

Administrator will assign a unique 

identifying number to each account 

established under paragraph (a), (b), or 

(c) of this section. 

(e) Responsibilities of authorized 

account representative and alternate 

authorized account representative. After 

the establishment of a compliance 

account or general account, the 

Administrator will accept or act on a 

submission pertaining to the account, 

including, 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 November 7, 2011, 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 November 7, 2011, 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 October 17, 

2011 of the State’s intent to submit to 

the Administrator a complete SIP 

revision by April 1, 2012 meeting the 

requirements of § 52.38(a)(3)(i) through 

(iv) of this chapter. 

(1) If, by April 1, 2012, the State does 

not submit to the Administrator such 

complete SIP revision, the 

Administrator will record by April 15, 

2012 in each TR NOX Annual source’s 

compliance account the TR NOX Annual 

allowances allocated to the TR NOX

Annual units at the source in 

accordance with § 97.411(a) for the 

control period in 2013. 

(2) If the State submits to the 

Administrator by April 1, 2012, and the 

Administrator approves by October 1, 

2012, such complete SIP revision, the 

Administrator will record by October 1, 

2012 in each TR NOX Annual source’s 

compliance account the TR NOX Annual 

allowances allocated to the TR NOX

Annual units at the source as provided 

in such approved, complete SIP revision 

for the control period in 2013. 

(3) If the State submits to the 

Administrator by April 1, 2012, and the 

Administrator does not approve by 

October 1, 2012, such complete SIP 

revision, the Administrator will record 

by October 1, 2012 in each TR NOX

Annual source’s compliance account the 

TR NOX Annual allowances allocated to 

the TR NOX Annual units at the source 

in accordance with § 97.411(a) for the 

control period in 2013. 

(c) By July 1, 2013, the Administrator 

will record in each TR NOX Annual 

source’s compliance account the TR 


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NOX Annual allowances allocated to the 

TR NOX Annual units at the source, or 

in each appropriate Allowance 

Management System account the TR 

NOX Annual allowances auctioned to 

TR NOX Annual units, in accordance 

with § 97.411(a), or with a SIP revision 

approved under § 52.38(a)(4) or (5) of 

this chapter, for the control period in 

2014 and 2015. 

(d) By July 1, 2014, the Administrator 

will record in each TR NOX Annual 

source’s compliance account the TR 

NOX Annual allowances allocated to the 

TR NOX Annual units at the source, or 

in each appropriate Allowance 

Management System account the TR 

NOX Annual allowances auctioned to 

TR NOX Annual units, in accordance 

with § 97.411(a), or with a SIP revision 

approved under § 52.38(a)(4) or (5) of 

this chapter, for the control period in 

2016 and 2017. 

(e) By July 1, 2015, the Administrator 

will record in each TR NOX Annual 

source’s compliance account the TR 

NOX Annual allowances allocated to the 

TR NOX Annual units at the source, or 

in each appropriate Allowance 

Management System account the TR 

NOX Annual allowances auctioned to 

TR NOX Annual units, in accordance 

with § 97.411(a), or with a SIP revision 

approved under § 52.38(a)(4) or (5) of 

this chapter, for the control period in 

2018 and 2019. 

(f) By July 1, 2016 and July 1 of each 

year thereafter, the Administrator will 

record in each TR NOX Annual source’s 

compliance account the TR NOX Annual 

allowances allocated to the TR NOX

Annual units at the source, or in each 

appropriate Allowance Management 

System account the TR NOX Annual 

allowances auctioned to TR NOX

Annual units, in accordance with 

§ 97.411(a), or with a SIP revision 

approved under § 52.38(a)(4) or (5) of 

this chapter, for the control period in 

the fourth year after the year of the 

applicable recordation deadline under 

this paragraph. 

(g) By August 1, 2012 and August 1 

of each year thereafter, the 

Administrator will record in each TR 

NOX Annual source’s compliance 

account the TR NOX Annual allowances 

allocated to the TR NOX Annual units 

at the source, or in each appropriate 

Allowance Management System account 

the TR NOX Annual allowances 

auctioned to TR NOX Annual units, in 

accordance with § 97.412(a)(2) through 

(8) and (12), or with a SIP revision 

approved under § 52.38(a)(4) or (5) of 

this chapter, for the control period in 

the year of the applicable recordation 

deadline under this paragraph. 

(h) By August 1, 2012 and August 1 

of each year thereafter, the 

Administrator will record in each TR 

NOX Annual source’s compliance 

account the TR NOX Annual allowances 

allocated to the TR NOX Annual units 

at the source in accordance with 

§ 97.412(b)(2) through (8) and (12) for 

the control period in the year of the 

applicable recordation deadline under 

this paragraph. 

(i) By February 15, 2013 and February 

15 of each year thereafter, the 

Administrator will record in each TR 

NOX Annual source’s compliance 

account the TR NOX Annual allowances 

allocated to the TR NOX Annual units 

at the source in accordance with 

§ 97.412(a)(9) through (12), for the 

control period in the year before the 

year of the applicable recordation 

deadline under this paragraph. 

(j) By the date on which any 

allocation or auction results, other than 

an allocation or auction results 

described in paragraphs (a) through (i) 

of this section, of TR NOX Annual 

allowances to a recipient is made by or 

are submitted to the Administrator in 

accordance with § 97.411 or § 97.412 or 

with a SIP revision approved under 

§ 52.38(a)(4) or (5) of this chapter, the 

Administrator will record such 

allocation or auction results in the 

appropriate Allowance Management 

System account. 

(k) When recording the allocation or 

auction of TR NOX Annual allowances 

to a TR NOX Annual unit or other entity 

in an Allowance Management System 

account, the Administrator will assign 

each TR NOX Annual allowance a 

unique identification number that will 

include digits identifying the year of the 

control period for which the TR NOX

Annual allowance is allocated or 

auctioned. 

§ 97.422 Submission of TR NOX Annual 

allowance transfers. 

(a) An authorized account 

representative seeking recordation of a 

TR NOX Annual allowance transfer shall 

submit the transfer to the Administrator. 

(b) A TR NOX Annual allowance 

transfer shall be correctly submitted if: 

(1) The transfer includes the following 

elements, in a format prescribed by the 

Administrator: 

(i) The account numbers established 

by the Administrator for both the 

transferor and transferee accounts; 

(ii) The serial number of each TR NOX

Annual allowance that is in the 

transferor account and is to be 

transferred; and 

(iii) The name and signature of the 

authorized account representative of the 

transferor account and the date signed; 

and 

(2) When the Administrator attempts 

to record the transfer, the transferor 

account includes each TR NOX Annual 

allowance identified by serial number in 

the transfer. 

§ 97.423 Recordation of TR NOX Annual 

allowance transfers. 

(a) Within 5 business days (except as 

provided in paragraph (b) of this 

section) of receiving a TR NOX Annual 

allowance transfer that is correctly 

submitted under § 97.422, the 

Administrator will record a TR NOX

Annual allowance transfer by moving 

each TR NOX Annual allowance from 

the transferor account to the transferee 

account as specified in the transfer. 

(b) A TR NOX Annual allowance 

transfer to or from a compliance account 

that is submitted for recordation after 

the allowance transfer deadline for a 

control period and that includes any TR 

NOX Annual allowances allocated for 

any control period before such 

allowance transfer deadline will not be 

recorded until after the Administrator 

completes the deductions from such 

compliance account under § 97.424 for 

the control period immediately before 

such allowance transfer deadline. 

(c) Where a TR NOX Annual 

allowance transfer is not correctly 

submitted under § 97.422, the 

Administrator will not record such 

transfer. 

(d) Within 5 business days of 

recordation of a TR NOX Annual 

allowance transfer under paragraphs (a) 

and (b) of the section, the Administrator 

will notify the authorized account 

representatives of both the transferor 

and transferee accounts. 

(e) Within 10 business days of receipt 

of a TR NOX Annual allowance transfer 

that is not correctly submitted under 

§ 97.422, the Administrator will notify 

the authorized account representatives 

of both accounts subject to the transfer 

of: 

(1) A decision not to record the 

transfer, and 

(2) The reasons for such nonrecordation. 

§ 97.424 Compliance with TR NOX Annual 

emissions limitation. 

(a) Availability for deduction for 

compliance. TR NOX Annual 

allowances are available to be deducted 

for compliance with a source’s TR NOX

Annual emissions limitation for a 

control period in a given year only if the 

TR NOX Annual allowances: 

(1) Were allocated for such control 

period or a control period in a prior 

year; and 


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(2) Are held in the source’s 

compliance account as of the allowance 

transfer deadline for such control 

period. 

(b) Deductions for compliance. After 

the recordation, in accordance with 

§ 97.423, of TR NOX Annual allowance 

transfers submitted by the allowance 

transfer deadline for a control period in 

a given year, the Administrator will 

deduct from each source’s compliance 

account TR NOX Annual allowances 

available under paragraph (a) of this 

section in order to determine whether 

the source meets the TR NOX Annual 

emissions limitation for such control 

period, as follows: 

(1) Until the amount of TR NOX

Annual allowances deducted equals the 

number of tons of total NOX emissions 

from all TR NOX Annual units at the 

source for such control period; or 

(2) If there are insufficient TR NOX

Annual allowances to complete the 

deductions in paragraph (b)(1) of this 

section, until no more TR NOX Annual 

allowances available under paragraph 

(a) of this section remain in the 

compliance account. 

(c)(1) Identification of TR NOX

Annual allowances by serial number. 

The authorized account representative 

for a source’s compliance account may 

request that specific TR NOX Annual 

allowances, identified by serial number, 

in the compliance account be deducted 

for emissions or excess emissions for a 

control period in a given year in 

accordance with paragraph (b) or (d) of 

this section. In order to be complete, 

such request shall be submitted to the 

Administrator by the allowance transfer 

deadline for such control period and 

include, in a format prescribed by the 

Administrator, the identification of the 

TR NOX Annual source and the 

appropriate serial numbers. 

(2) First-in, first-out. The 

Administrator will deduct TR NOX

Annual allowances under paragraph (b) 

or (d) of this section from the source’s 

compliance account in accordance with 

a complete request under paragraph 

(c)(1) of this section or, in the absence 

of such request or in the case of 

identification of an insufficient amount 

of TR NOX Annual allowances in such 

request, on a first-in, first-out 

accounting basis in the following order: 

(i) Any TR NOX Annual allowances 

that were allocated to the units at the 

source and not transferred out of the 

compliance account, in the order of 

recordation; and then 

(ii) Any TR NOX Annual allowances 

that were allocated to any unit and 

transferred to and recorded in the 

compliance account pursuant to this 

subpart, in the order of recordation. 

(d) Deductions for excess emissions. 

After making the deductions for 

compliance under paragraph (b) of this 

section for a control period in a year in 

which the TR NOX Annual source has 

excess emissions, the Administrator will 

deduct from the source’s compliance 

account an amount of TR NOX Annual 

allowances, allocated for a control 

period in a prior year or the control 

period in the year of the excess 

emissions or in the immediately 

following year, equal to two times the 

number of tons of the source’s excess 

emissions. 

(e) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraphs (b) and (d) of this section. 

§ 97.425 Compliance with TR NOX Annual 

assurance provisions. 

(a) Availability for deduction. TR NOX

Annual allowances are available to be 

deducted for compliance with the TR 

NOX Annual assurance provisions for a 

control period in a given year by the 

owners and operators of a group of one 

or more TR NOX Annual sources and 

units in a State (and Indian country 

within the borders of such State) only if 

the TR NOX Annual allowances: 

(1) Were allocated for a control period 

in a prior year or the control period in 

the given year or in the immediately 

following year; and 

(2) Are held in the assurance account, 

established by the Administrator for 

such owners and operators of such 

group of TR NOX Annual sources and 

units in such State (and Indian country 

within the borders of such State) under 

paragraph (b)(3) of this section, as of the 

deadline established in paragraph (b)(4) 

of this section. 

(b) Deductions for compliance. The 

Administrator will deduct TR NOX

Annual allowances available under 

paragraph (a) of this section for 

compliance with the TR NOX Annual 

assurance provisions for a State for a 

control period in a given year in 

accordance with the following 

procedures: 

(1) By June 1, 2013 and June 1 of each 

year thereafter, the Administrator will: 

(i) Calculate, for each State (and 

Indian country within the borders of 

such State), the total NOX emissions 

from all TR NOX Annual units at TR 

NOX Annual sources in the State (and 

Indian country within the borders of 

such State) during the control period in 

the year before the year of this 

calculation deadline and the amount, if 

any, by which such total NOX emissions 

exceed the State assurance level as 

described in § 97.406(c)(2)(iii); and 

(ii) Promulgate a notice of data 

availability of the results of the 

calculations required in paragraph 

(b)(1)(i) of this section, including 

separate calculations of the NOX

emissions from each TR NOX Annual 

source. 

(2) For each notice of data availability 

required in paragraph (b)(1)(ii) of this 

section and for any State (and Indian 

country within the borders of such 

State) identified in such notice as 

having TR NOX Annual units with total 

NOX emissions exceeding the State 

assurance level for a control period in 

a given year, as described in 

§ 97.406(c)(2)(iii): 

(i) By July 1 immediately after the 

promulgation of such notice, the 

designated representative of each TR 

NOX Annual source in each such State 

(and Indian country within the borders 

of such State) shall submit a statement, 

in a format prescribed by the 

Administrator, providing for each TR 

NOX Annual unit (if any) at the source 

that operates during, but is not allocated 

an amount of TR NOX Annual 

allowances for, such control period, the 

unit’s allowable NOX emission rate for 

such control period and, if such rate is 

expressed in lb per mmBtu, the unit’s 

heat rate. 

(ii) By August 1 immediately after the 

promulgation of such notice, the 

Administrator will calculate, for each 

such State (and Indian country within 

the borders of such State) and such 

control period and each common 

designated representative for such 

control period for a group of one or 

more TR NOX Annual sources and units 

in the State (and Indian country within 

the borders of such State), the common 

designated representative’s share of the 

total NOX emissions from all TR NOX

Annual units at TR NOX Annual sources 

in the State (and Indian country within 

the borders of such State), the common 

designated representative’s assurance 

level, and the amount (if any) of TR 

NOX Annual allowances that the owners 

and operators of such group of sources 

and units must hold in accordance with 

the calculation formula in 

§ 97.406(c)(2)(i) and will promulgate a 

notice of data availability of the results 

of these calculations. 

(iii) The Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

by the notice of data availability 

required in paragraph (b)(2)(ii) of this 

section and the calculations referenced 

by the relevant notice of data 

availability required in paragraph 

(b)(1)(i) of this section. 

(A) Objections shall be submitted by 

the deadline specified in such notice 


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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. 

(3) For any State (and Indian country 

within the borders of such State) 

referenced in each notice of data 

availability required in paragraph 

(b)(2)(iii)(B) of this section as having TR 

NOX Annual units with total NOX

emissions exceeding the State assurance 

level for a control period in a given year, 

the Administrator will establish one 

assurance account for each set of owners 

and operators referenced, in the notice 

of data availability required under 

paragraph (b)(2)(iii)(B) of this section, as 

all of the owners and operators of a 

group of TR NOX Annual sources and 

units in the State (and Indian country 

within the borders of such State) having 

a common designated representative for 

such control period and as being 

required to hold TR NOX Annual 

allowances. 

(4)(i) As of midnight of November 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(2)(iii)(B) of this section, 

the owners and operators described in 

paragraph (b)(3) of this section shall 

hold in the assurance account 

established for the them and for the 

appropriate TR NOX Annual sources, TR 

NOX Annual units, and State (and 

Indian country within the borders of 

such State) under paragraph (b)(3) of 

this section a total amount of TR NOX

Annual allowances, available for 

deduction under paragraph (a) of this 

section, equal to the amount such 

owners and operators are required to 

hold with regard to such sources, units 

and State (and Indian country within 

the borders of such State) as calculated 

by the Administrator and referenced in 

such notice. 

(ii) Notwithstanding the allowanceholding deadline specified in paragraph 

(b)(4)(i) of this section, if November 1 is 

not a business day, then such 

allowance-holding deadline shall be 

midnight of the first business day 

thereafter. 

(5) After November 1 (or the date 

described in paragraph (b)(4)(ii) of this 

section) immediately after the 

promulgation of each notice of data 

availability required in paragraph 

(b)(2)(iii)(B) of this section and after the 

recordation, in accordance with 

§ 97.423, of TR NOX Annual allowance 

transfers submitted by midnight of such 

date, the Administrator will determine 

whether the owners and operators 

described in paragraph (b)(3) of this 

section hold, in the assurance account 

for the appropriate TR NOX Annual 

sources, TR NOX Annual units, and 

State (and Indian country within the 

borders of such State) established under 

paragraph (b)(3) of this section, the 

amount of TR NOX Annual allowances 

available under paragraph (a) of this 

section that the owners and operators 

are required to hold with regard to such 

sources, units, and State (and Indian 

country within the borders of such 

State) as calculated by the 

Administrator and referenced in the 

notice required in paragraph 

(b)(2)(iii)(B) of this section. 

(6) Notwithstanding any other 

provision of this subpart and any 

revision, made by or submitted to the 

Administrator after the promulgation of 

the notice of data availability required 

in paragraph (b)(2)(iii)(B) of this section 

for a control period in a given year, of 

any data used in making the 

calculations referenced in such notice, 

the amounts of TR NOX Annual 

allowances that the owners and 

operators are required to hold in 

accordance with § 97.406(c)(2)(i) for 

such control period shall continue to be 

such amounts as calculated by the 

Administrator and referenced in such 

notice required in paragraph 

(b)(2)(iii)(B) of this section, except as 

follows: 

(i) If any such data are revised by the 

Administrator as a result of a decision 

in or settlement of litigation concerning 

such data on appeal under part 78 of 

this chapter of such notice, or on appeal 

under section 307 of the Clean Air Act 

of a decision rendered under part 78 of 

this chapter on appeal of such notice, 

then the Administrator will use the data 

as so revised to recalculate the amounts 

of TR NOX Annual allowances that 

owners and operators are required to 

hold in accordance with the calculation 

formula in § 97.406(c)(2)(i) for such 

control period with regard to the TR 

NOX Annual sources, TR NOX Annual 

units, and State (and Indian country 

within the borders of such State) 

involved, provided that such litigation 

under part 78 of this chapter, or the 

proceeding under part 78 of this chapter 

that resulted in the decision appealed in 

such litigation under section 307 of the 

Clean Air Act, was initiated no later 

than 30 days after promulgation of such 

notice required in paragraph 

(b)(2)(iii)(B) of this section. 

(ii) If any such data are revised by the 

owners and operators of a TR NOX

Annual source and TR NOX Annual unit 

whose designated representative 

submitted such data under paragraph 

(b)(2)(i) of this section, as a result of a 

decision in or settlement of litigation 

concerning such submission, then the 

Administrator will use the data as so 

revised to recalculate the amounts of TR 

NOX Annual allowances that owners 

and operators are required to hold in 

accordance with the calculation formula 

in § 97.406(c)(2)(i) for such control 

period with regard to the TR NOX

Annual sources, TR NOX Annual units, 

and State (and Indian country within 

the borders of such State) involved, 

provided that such litigation was 

initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(2)(iii)(B) of this section. 

(iii) If the revised data are used to 

recalculate, in accordance with 

paragraphs (b)(6)(i) and (ii) of this 

section, the amount of TR NOX Annual 

allowances that the owners and 

operators are required to hold for such 

control period with regard to the TR 

NOX Annual sources, TR NOX Annual 

units, and State (and Indian country 

within the borders of such State) 

involved— 

(A) Where the amount of TR NOX

Annual allowances that the owners and 

operators are required to hold increases 

as a result of the use of all such revised 

data, the Administrator will establish a 

new, reasonable deadline on which the 

owners and operators shall hold the 

additional amount of TR NOX Annual 

allowances in the assurance account 

established by the Administrator for the 

appropriate TR NOX Annual sources, TR 

NOX Annual units, and State (and 

Indian country within the borders of 

such State) under paragraph (b)(3) of 

this section. The owners’ and operators’ 

failure to hold such additional amount, 

as required, before the new deadline 

shall not be a violation of the Clean Air 

Act. The owners’ and operators’ failure 

to hold such additional amount, as 

required, as of the new deadline shall be 

a violation of the Clean Air Act. Each 


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TR NOX Annual allowance that the 

owners and operators fail to hold as 

required as of the new deadline, and 

each day in such control period, shall be 

a separate violation of the Clean Air Act. 

(B) For the owners and operators for 

which the amount of TR NOX Annual 

allowances required to be held 

decreases as a result of the use of all 

such revised data, the Administrator 

will record, in all accounts from which 

TR NOX Annual allowances were 

transferred by such owners and 

operators for such control period to the 

assurance account established by the 

Administrator for the appropriate at TR 

NOX Annual sources, TR NOX Annual 

units, and State (and Indian country 

within the borders of such State) under 

paragraph (b)(3) of this section, a total 

amount of the TR NOX Annual 

allowances held in such assurance 

account equal to the amount of the 

decrease. If TR NOX Annual allowances 

were transferred to such assurance 

account from more than one account, 

the amount of TR NOX Annual 

allowances recorded in each such 

transferor account will be in proportion 

to the percentage of the total amount of 

TR NOX Annual allowances transferred 

to such assurance account for such 

control period from such transferor 

account. 

(C) Each TR NOX Annual allowance 

held under paragraph (b)(6)(iii)(A) of 

this section as a result of recalculation 

of requirements under the TR NOX

Annual assurance provisions for such 

control period must be a TR NOX

Annual allowance allocated for a 

control period in a year before or the 

year immediately following, or in the 

same year as, the year of such control 

period. 

§ 97.426 Banking. 

(a) A TR NOX Annual allowance may 

be banked for future use or transfer in 

a compliance account or a general 

account in accordance with paragraph 

(b) of this section. 

(b) Any TR NOX Annual allowance 

that is held in a compliance account or 

a general account will remain in such 

account unless and until the TR NOX

Annual allowance is deducted or 

transferred under § 97.411(c), § 97.423, 

§ 97.424, § 97.425, 97.427, or 97.428. 

§ 97.427 Account error. 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any 

Allowance Management System 

account. Within 10 business days of 

making such correction, the 

Administrator will notify the authorized 

account representative for the account. 

§ 97.428 Administrator’s action on 

submissions. 

(a) The Administrator may review and 

conduct independent audits concerning 

any submission under the TR NOX

Annual Trading Program and make 

appropriate adjustments of the 

information in the submission. 

(b) The Administrator may deduct TR 

NOX Annual allowances from or transfer 

TR NOX Annual allowances to a 

compliance account or an assurance 

account, based on the information in a 

submission, as adjusted under 

paragraph (a)(1) of this section, and 

record such deductions and transfers. 

§ 97.429 [Reserved] 

§ 97.430 General monitoring, 

recordkeeping, and reporting requirements. 

The owners and operators, and to the 

extent applicable, the designated 

representative, of a TR NOX Annual 

unit, shall comply with the monitoring, 

recordkeeping, and reporting 

requirements as provided in this subpart 

and subpart H of part 75 of this chapter. 

For purposes of applying such 

requirements, the definitions in § 97.402 

and in § 72.2 of this chapter shall apply, 

the terms ‘‘affected unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) in part 75 of this chapter shall 

be deemed to refer to the terms ‘‘TR 

NOX Annual unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) respectively as defined in 

§ 97.402, and the term ‘‘newly affected 

unit’’ shall be deemed to mean ‘‘newly 

affected TR NOX Annual unit’’. The 

owner or operator of a unit that is not 

a TR NOX Annual unit but that is 

monitored under § 75.72(b)(2)(ii) of this 

chapter shall comply with the same 

monitoring, recordkeeping, and 

reporting requirements as a TR NOX

Annual unit. 

(a) Requirements for installation, 

certification, and data accounting. The 

owner or operator of each TR NOX

Annual unit shall: 

(1) Install all monitoring systems 

required under this subpart for 

monitoring NOX mass emissions and 

individual unit heat input (including all 

systems required to monitor NOX

emission rate, NOX concentration, stack 

gas moisture content, stack gas flow 

rate, CO2 or O2 concentration, and fuel 

flow rate, as applicable, in accordance 

with §§ 75.71 and 75.72 of this chapter); 

(2) Successfully complete all 

certification tests required under 

§ 97.431 and meet all other 

requirements of this subpart and part 75 

of this chapter applicable to the 

monitoring systems under paragraph 

(a)(1) of this section; and 

(3) Record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section. 

(b) Compliance deadlines. Except as 

provided in paragraph (e) of this 

section, the owner or operator shall 

meet the monitoring system certification 

and other requirements of paragraphs 

(a)(1) and (2) of this section on or before 

the following dates and shall record, 

report, and quality-assure the data from 

the monitoring systems under paragraph 

(a)(1) of this section on and after the 

following dates. 

(1) For the owner or operator of a TR 

NOX Annual unit that commences 

commercial operation before July 1, 

2011, January 1, 2012; 

(2) For the owner or operator of a TR 

NOX Annual unit that commences 

commercial operation on or after July 1, 

2011, the later of the following: 

(i) January 1, 2012; or 

(ii) 180 calendar days 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 

(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 


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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 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 

provides emission data for the same 

pollutant or parameter as the retired or 

discontinued monitoring system; or 

(iii) The designated representative 

submits notification of the date of 

certification testing of a replacement 

monitoring system for the retired or 

discontinued monitoring system in 

accordance with § 97.431(d)(3)(i). 

(e) Long-term cold storage. The owner 

or operator of a TR NOX Annual unit is 

subject to the applicable provisions of 

§ 75.4(d) of this chapter concerning 

units in long-term cold storage. 

§ 97.431 Initial monitoring system 

certification and recertification procedures. 

(a) The owner or operator of a TR NOX

Annual unit shall be exempt from the 

initial certification requirements of this 

section for a monitoring system under 

§ 97.430(a)(1) if the following conditions 

are met: 

(1) The monitoring system has been 

previously certified in accordance with 

part 75 of this chapter; and 

(2) The applicable quality-assurance 

and quality-control requirements of 

§ 75.21 of this chapter and appendices 

B, D, and E to part 75 of this chapter are 

fully met for the certified monitoring 

system described in paragraph (a)(1) of 

this section. 

(b) The recertification provisions of 

this section shall apply to a monitoring 

system under § 97.430(a)(1) that is 

exempt from initial certification 

requirements under paragraph (a) of this 

section. 

(c) If the Administrator has previously 

approved a petition under § 75.17(a) or 

(b) of this chapter for apportioning the 

NOX emission rate measured in a 

common stack or a petition under 

§ 75.66 of this chapter for an alternative 

to a requirement in § 75.12 or § 75.17 of 

this chapter, the designated 

representative shall resubmit the 

petition to the Administrator under 

§ 97.435 to determine whether the 

approval applies under the TR NOX

Annual Trading Program. 

(d) Except as provided in paragraph 

(a) of this section, the owner or operator 

of a TR NOX Annual unit shall comply 

with the following initial certification 

and recertification procedures for a 

continuous monitoring system (i.e., a 

continuous emission monitoring system 

and an excepted monitoring system 

under appendices D and E to part 75 of 

this chapter) under § 97.430(a)(1). The 

owner or operator of a unit that qualifies 

to use the low mass emissions excepted 

monitoring methodology under § 75.19 

of this chapter or that qualifies to use an 

alternative monitoring system under 

subpart E of part 75 of this chapter shall 

comply with the procedures in 

paragraph (e) or (f) of this section 

respectively. 

(1) Requirements for initial 

certification. The owner or operator 

shall ensure that each continuous 

monitoring system under § 97.430(a)(1) 

(including the automated data 

acquisition and handling system) 

successfully completes all of the initial 

certification testing required under 

§ 75.20 of this chapter by the applicable 

deadline in § 97.430(b). In addition, 

whenever the owner or operator installs 

a monitoring system to meet the 

requirements of this subpart in a 

location where no such monitoring 

system was previously installed, initial 

certification in accordance with § 75.20 

of this chapter is required. 

(2) Requirements for recertification. 

Whenever the owner or operator makes 

a replacement, modification, or change 

in any certified continuous emission 

monitoring system under § 97.430(a)(1) 

that may significantly affect the ability 

of the system to accurately measure or 

record NOX mass emissions or heat 

input rate or to meet the qualityassurance and quality-control 

requirements of § 75.21 of this chapter 

or appendix B to part 75 of this chapter, 

the owner or operator shall recertify the 

monitoring system in accordance with 

§ 75.20(b) of this chapter. Furthermore, 

whenever the owner or operator makes 

a replacement, modification, or change 

to the flue gas handling system or the 

unit’s operation that may significantly 

change the stack flow or concentration 

profile, the owner or operator shall 

recertify each continuous emission 

monitoring system whose accuracy is 

potentially affected by the change, in 

accordance with § 75.20(b) of this 

chapter. Examples of changes to a 

continuous emission monitoring system 

that require recertification include 

replacement of the analyzer, complete 

replacement of an existing continuous 

emission monitoring system, or change 

in location or orientation of the 

sampling probe or site. Any fuel 

flowmeter system, and any excepted 

NOX monitoring system under appendix 

E to part 75 of this chapter, under 

§ 97.430(a)(1) are subject to the 

recertification requirements in 

§ 75.20(g)(6) of this chapter. 

(3) Approval process for initial 

certification and recertification. For 

initial certification of a continuous 

monitoring system under § 97.430(a)(1), 

paragraphs (d)(3)(i) through (v) of this 

section apply. For recertifications of 

such monitoring systems, paragraphs 

(d)(3)(i) through (iv) of this section and 

the procedures in §§ 75.20(b)(5) and 

(g)(7) of this chapter (in lieu of the 

procedures in paragraph (d)(3)(v) of this 

section) apply, provided that in 

applying paragraphs (d)(3)(i) through 

(iv) of this section, the words 

‘‘certification’’ and ‘‘initial certification’’ 

are replaced by the word 

‘‘recertification’’ and the word 

‘‘certified’’ is replaced by with the word 

‘‘recertified’’. 

(i) Notification of certification. The 

designated representative shall submit 

to the appropriate EPA Regional Office 

and the Administrator written notice of 

the dates of certification testing, in 

accordance with § 97.433. 


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(ii) Certification application. The 

designated representative shall submit 

to the Administrator a certification 

application for each monitoring system. 

A complete certification application 

shall include the information specified 

in § 75.63 of this chapter. 

(iii) Provisional certification date. The 

provisional certification date for a 

monitoring system shall be determined 

in accordance with § 75.20(a)(3) of this 

chapter. A provisionally certified 

monitoring system may be used under 

the TR NOX Annual Trading Program 

for a period not to exceed 120 days after 

receipt by the Administrator of the 

complete certification application for 

the monitoring system under paragraph 

(d)(3)(ii) of this section. Data measured 

and recorded by the provisionally 

certified monitoring system, in 

accordance with the requirements of 

part 75 of this chapter, will be 

considered valid quality-assured data 

(retroactive to the date and time of 

provisional certification), provided that 

the Administrator does not invalidate 

the provisional certification by issuing a 

notice of disapproval within 120 days of 

the date of receipt of the complete 

certification application by the 

Administrator. 

(iv) Certification application approval 

process. The Administrator will issue a 

written notice of approval or 

disapproval of the certification 

application to the owner or operator 

within 120 days of receipt of the 

complete certification application under 

paragraph (d)(3)(ii) of this section. In the 

event the Administrator does not issue 

such a notice within such 120-day 

period, each monitoring system that 

meets the applicable performance 

requirements of part 75 of this chapter 

and is included in the certification 

application will be deemed certified for 

use under the TR NOX Annual Trading 

Program. 

(A) Approval notice. If the 

certification application is complete and 

shows that each monitoring system 

meets the applicable performance 

requirements of part 75 of this chapter, 

then the Administrator will issue a 

written notice of approval of the 

certification application within 120 

days of receipt. 

(B) Incomplete application notice. If 

the certification application is not 

complete, then the Administrator will 

issue a written notice of incompleteness 

that sets a reasonable date by which the 

designated representative must submit 

the additional information required to 

complete the certification application. If 

the designated representative does not 

comply with the notice of 

incompleteness by the specified date, 

then the Administrator may issue a 

notice of disapproval under paragraph 

(d)(3)(iv)(C) of this section. 

(C) Disapproval notice. If the 

certification application shows that any 

monitoring system does not meet the 

performance requirements of part 75 of 

this chapter or if the certification 

application is incomplete and the 

requirement for disapproval under 

paragraph (d)(3)(iv)(B) of this section is 

met, then the Administrator will issue a 

written notice of disapproval of the 

certification application. Upon issuance 

of such notice of disapproval, the 

provisional certification is invalidated 

by the Administrator and the data 

measured and recorded by each 

uncertified monitoring system shall not 

be considered valid quality-assured data 

beginning with the date and hour of 

provisional certification (as defined 

under § 75.20(a)(3) of this chapter). 

(D) Audit decertification. The 

Administrator may issue a notice of 

disapproval of the certification status of 

a monitor in accordance with 

§ 97.432(b). 

(v) Procedures for loss of certification. 

If the Administrator issues a notice of 

disapproval of a certification 

application under paragraph 

(d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under 

paragraph (d)(3)(iv)(D) of this section, 

then: 

(A) The owner or operator shall 

substitute the following values, for each 

disapproved monitoring system, for 

each hour of unit operation during the 

period of invalid data specified under 

§ 75.20(a)(4)(iii), § 75.20(g)(7), or 

§ 75.21(e) of this chapter and continuing 

until the applicable date and hour 

specified under § 75.20(a)(5)(i) or (g)(7) 

of this chapter: 

(1) For a disapproved NOX emission 

rate (i.e., NOX-diluent) system, the 

maximum potential NOX emission rate, 

as defined in § 72.2 of this chapter. 

(2) For a disapproved NOX pollutant 

concentration monitor and disapproved 

flow monitor, respectively, the 

maximum potential concentration of 

NOX and the maximum potential flow 

rate, as defined in sections 2.1.2.1 and 

2.1.4.1 of appendix A to part 75 of this 

chapter. 

(3) For a disapproved moisture 

monitoring system and disapproved 

diluent gas monitoring system, 

respectively, the minimum potential 

moisture percentage and either the 

maximum potential CO2 concentration 

or the minimum potential O2

concentration (as applicable), as defined 

in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 

appendix A to part 75 of this chapter. 

(4) For a disapproved fuel flowmeter 

system, the maximum potential fuel 

flow rate, as defined in section 2.4.2.1 

of appendix D to part 75 of this chapter. 

(5) For a disapproved excepted NOX

monitoring system under appendix E to 

part 75 of this chapter, the fuel-specific 

maximum potential NOX emission rate, 

as defined in § 72.2 of this chapter. 

(B) The designated representative 

shall submit a notification of 

certification retest dates and a new 

certification application in accordance 

with paragraphs (d)(3)(i) and (ii) of this 

section. 

(C) The owner or operator shall repeat 

all certification tests or other 

requirements that were failed by the 

monitoring system, as indicated in the 

Administrator’s notice of disapproval, 

no later than 30 unit operating days 

after the date of issuance of the notice 

of disapproval. 

(e) The owner or operator of a unit 

qualified to use the low mass emissions 

(LME) excepted methodology under 

§ 75.19 of this chapter shall meet the 

applicable certification and 

recertification requirements in 

§§ 75.19(a)(2) and 75.20(h) of this 

chapter. If the owner or operator of such 

a unit elects to certify a fuel flowmeter 

system for heat input determination, the 

owner or operator shall also meet the 

certification and recertification 

requirements in § 75.20(g) of this 

chapter. 

(f) The designated representative of 

each unit for which the owner or 

operator intends to use an alternative 

monitoring system approved by the 

Administrator under subpart E of part 

75 of this chapter shall comply with the 

applicable notification and application 

procedures of § 75.20(f) of this chapter. 

§ 97.432 Monitoring system out-of-control 

periods. 

(a) General provisions. Whenever any 

monitoring system fails to meet the 

quality-assurance and quality-control 

requirements or data validation 

requirements of part 75 of this chapter, 

data shall be substituted using the 

applicable missing data procedures in 

subpart D or subpart H of, or appendix 

D or appendix E to, part 75 of this 

chapter. 

(b) Audit decertification. Whenever 

both an audit of a monitoring system 

and a review of the initial certification 

or recertification application reveal that 

any monitoring system should not have 

been certified or recertified because it 

did not meet a particular performance 

specification or other requirement under 

§ 97.431 or the applicable provisions of 

part 75 of this chapter, both at the time 

of the initial certification or 


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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. 

§ 97.434 Recordkeeping and reporting. 

(a) General provisions. The designated 

representative shall comply with all 

recordkeeping and reporting 

requirements in paragraphs (b) through 

(e) of this section, the applicable 

recordkeeping and reporting 

requirements under § 75.73 of this 

chapter, and the requirements of 

§ 97.414(a). 

(b) Monitoring plans. The owner or 

operator of a TR NOX Annual unit shall 

comply with requirements of § 75.73(c) 

and (e) of this chapter. 

(c) Certification applications. The 

designated representative shall submit 

an application to the Administrator 

within 45 days after completing all 

initial certification or recertification 

tests required under § 97.431, including 

the information required under § 75.63 

of this chapter. 

(d) Quarterly reports. The designated 

representative shall submit quarterly 

reports, as follows: 

(1) The designated representative 

shall report the NOX mass emissions 

data and heat input data for the TR NOX

Annual unit, in an electronic quarterly 

report in a format prescribed by the 

Administrator, for each calendar quarter 

beginning with: 

(i) For a unit that commences 

commercial operation before July 1, 

2011, the calendar quarter covering 

January 1, 2012 through March 31, 2012; 

or 

(ii) For a unit that commences 

commercial operation on or after July 1, 

2011, the calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 97.430(b), unless 

that quarter is the third or fourth quarter 

of 2011, in which case reporting shall 

commence in the quarter covering 

January 1, 2012 through March 31, 2012. 

(2) The designated representative 

shall submit each quarterly report to the 

Administrator within 30 days after the 

end of the calendar quarter covered by 

the report. Quarterly reports shall be 

submitted in the manner specified in 

§ 75.73(f) of this chapter. 

(3) For TR NOX Annual units that are 

also subject to the Acid Rain Program, 

TR NOX Ozone Season Trading 

Program, TR SO2 Group 1 Trading 

Program, or TR SO2 Group 2 Trading 

Program, quarterly reports shall include 

the applicable data and information 

required by subparts F through H of part 

75 of this chapter as applicable, in 

addition to the NOX mass emission data, 

heat input data, and other information 

required by this subpart. 

(4) The Administrator may review and 

conduct independent audits of any 

quarterly report in order to determine 

whether the quarterly report meets the 

requirements of this subpart and part 75 

of this chapter, including the 

requirement to use substitute data. 

(i) The Administrator will notify the 

designated representative of any 

determination that the quarterly report 

fails to meet any such requirements and 

specify in such notification any 

corrections that the Administrator 

believes are necessary to make through 

resubmission of the quarterly report and 

a reasonable time period within which 

the designated representative must 

respond. Upon request by the 

designated representative, the 

Administrator may specify reasonable 

extensions of such time period. Within 

the time period (including any such 

extensions) specified by the 

Administrator, the designated 

representative shall resubmit the 

quarterly report with the corrections 

specified by the Administrator, except 

to the extent the designated 

representative provides information 

demonstrating that a specified 

correction is not necessary because the 

quarterly report already meets the 

requirements of this subpart and part 75 

of this chapter that are relevant to the 

specified correction. 

(ii) Any resubmission of a quarterly 

report shall meet the requirements 

applicable to the submission of a 

quarterly report under this subpart and 

part 75 of this chapter, except for the 

deadline set forth in paragraph (d)(2) of 

this section. 

(e) Compliance certification. The 

designated representative shall submit 

to the Administrator a compliance 

certification (in a format prescribed by 

the Administrator) in support of each 

quarterly report based on reasonable 

inquiry of those persons with primary 

responsibility for ensuring that all of the 

unit’s emissions are correctly and fully 

monitored. The certification shall state 

that: 

(1) The monitoring data submitted 

were recorded in accordance with the 

applicable requirements of this subpart 

and part 75 of this chapter, including 

the quality assurance procedures and 

specifications; and 

(2) For a unit with add-on NOX

emission controls and for all hours 

where NOX data are substituted in 

accordance with § 75.34(a)(1) of this 

chapter, the add-on emission controls 

were operating within the range of 

parameters listed in the quality 

assurance/quality control program 

under appendix B to part 75 of this 

chapter and the substitute data values 

do not systematically underestimate 

NOX emissions. 

§ 97.435 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

(a) The designated representative of a 

TR NOX Annual unit may submit a 

petition under § 75.66 of this chapter to 

the Administrator, requesting approval 

to apply an alternative to any 

requirement of §§ 97.430 through 

97.434. 

(b) A petition submitted under 

paragraph (a) of this section shall 

include sufficient information for the 

evaluation of the petition, including, at 

a minimum, the following information: 

(i) Identification of each unit and 

source covered by the petition; 

(ii) A detailed explanation of why the 

proposed alternative is being suggested 

in lieu of the requirement; 

(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. 

97.509 [Reserved] 

97.510 State NOX Ozone Season trading 

budgets, new unit set-asides, Indian 

country new unit set-asides and 

variability limits. 

97.511 Timing requirements for TR NOX

Ozone Season allowance allocations. 

97.512 TR NOX Ozone Season allowance 

allocations to new units. 

97.513 Authorization of designated 

representative and alternate designated 

representative. 

97.514 Responsibilities of designated 

representative and alternate designated 

representative. 

97.515 Changing designated representative 

and alternate designated representative; 

changes in owners and operators. 

97.516 Certificate of representation. 

97.517 Objections concerning designated 

representative and alternate designated 

representative. 

97.518 Delegation by designated 

representative and alternate designated 

representative. 

97.519 [Reserved] 

97.520 Establishment of compliance 

accounts and general accounts. 

97.521 Recordation of TR NOX Ozone 

Season allowance allocations. 

97.522 Submission of TR NOX Ozone 

Season allowance transfers. 

97.523 Recordation of TR NOX Ozone 

Season allowance transfers. 

97.524 Compliance with TR NOX Ozone 

Season emissions limitation. 

97.525 Compliance with TR NOX Ozone 

Season assurance provisions. 

97.526 Banking. 

97.527 Account error. 

97.528 Administrator’s action on 

submissions. 

97.529 [RESERVED] 

97.530 General monitoring, recordkeeping, 

and reporting requirements. 

97.531 Initial monitoring system 

certification and recertification 

procedures. 

97.532 Monitoring system out-of-control 

periods. 

97.533 Notifications concerning 

monitoring. 

97.534 Recordkeeping and reporting. 

97.535 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

Subpart BBBBB—TR NOX Ozone 

Season Trading Program 

§ 97.501 Purpose. 

This subpart sets forth the general, 

designated representative, allowance, 

and monitoring provisions for the 

Transport Rule (TR) NOX Ozone Season 

Trading Program, under section 110 of 

the Clean Air Act and § 52.38 of this 

chapter, as a means of mitigating 

interstate transport of ozone and 

nitrogen oxides. 

§ 97.502 Definitions. 

The terms used in this subpart shall 

have the meanings set forth in this 

section as follows: 

Acid Rain Program means a multistate SO2 and NOX air pollution control 

and emission reduction program 

established by the Administrator under 

title IV of the Clean Air Act and parts 

72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Director of the Clean Air Markets 

Division (or its successor determined by 

the Administrator) of the United States 

Environmental Protection Agency, the 

Administrator’s duly authorized 

representative under this subpart. 

Allocate or allocation means, with 

regard to TR NOX Ozone Season 

allowances, the determination by the 

Administrator, State, or permitting 

authority, in accordance with this 

subpart and any SIP revision submitted 

by the State and approved by the 

Administrator under § 52.38(b)(3), (4), 

or (5) of this chapter, of the amount of 

such TR NOX Ozone Season allowances 

to be initially credited, at no cost to the 

recipient, to: 

(1) A TR NOX Ozone Season unit; 

(2) A new unit set-aside; 

(3) An Indian country new unit setaside; 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. 

Allowable NOX emission rate means, 

for a unit, the most stringent State or 

federal NOX emission rate limit (in 

lb/MWhr or, if in lb/mmBtu, converted 

to lb/MWhr by multiplying it by the 

unit’s heat rate in mmBtu/MWhr) that is 

applicable to the unit and covers the 

longest averaging period not exceeding 

one year. 

Allowance Management System 

means the system by which the 

Administrator records allocations, 

deductions, and transfers of TR NOX

Ozone Season allowances under the TR 

NOX Ozone Season Trading Program. 

Such allowances are allocated, 

recorded, held, deducted, or transferred 

only as whole allowances. 

Allowance Management System 

account means an account in the 

Allowance Management System 

established by the Administrator for 

purposes of recording the allocation, 

holding, transfer, or deduction of TR 

NOX Ozone Season allowances. 

Allowance transfer deadline means, 

for a control period in a given year, 

midnight of December 1 (if it is a 

business day), or midnight of the first 

business day thereafter (if December 1 is 

not a business day), immediately after 

such control period and is the deadline 

by which a TR NOX Ozone Season 

allowance transfer must be submitted 

for recordation in a TR NOX Ozone 

Season source’s compliance account in 

order to be available for use in 

complying with the source’s TR NOX

Ozone Season emissions limitation for 

such control period in accordance with 

§§ 97.506 and 97.524. 

Alternate designated representative 

means, for a TR NOX Ozone Season 

source and each TR NOX Ozone Season 

unit at the source, the natural person 

who is authorized by the owners and 

operators of the source and all such 

units at the source, in accordance with 

this subpart, to act on behalf of the 

designated representative in matters 

pertaining to the TR NOX Ozone Season 

Trading Program. If the TR NOX Ozone 

Season source is also subject to the Acid 

Rain Program, TR NOX Annual Trading 

Program, TR SO2 Group 1 Trading 

Program, or TR SO2 Group 2 Trading 

Program, then this natural person shall 

be the same natural person as the 

alternate designated representative, as 

defined in the respective program. 

Assurance account means an 

Allowance Management System 

account, established by the 

Administrator under § 97.525(b)(3) for 

certain owners and operators of a group 

of one or more TR NOX Ozone Season 

sources and units in a given State (and 

Indian country within the borders of 

such State), in which are held TR NOX

Ozone Season allowances available for 

use for a control period in a given year 

in complying with the TR NOX Ozone 


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Season assurance provisions in 

accordance with §§ 97.506 and 97.525. 

Authorized account representative 

means, for a general account, the natural 

person who is authorized, in accordance 

with this subpart, to transfer and 

otherwise dispose of TR NOX Ozone 

Season allowances held in the general 

account and, for a TR NOX Ozone 

Season source’s compliance account, 

the designated representative of the 

source. 

Automated data acquisition and 

handling system or DAHS means the 

component of the continuous emission 

monitoring system, or other emissions 

monitoring system approved for use 

under this subpart, designed to interpret 

and convert individual output signals 

from pollutant concentration monitors, 

flow monitors, diluent gas monitors, 

and other component parts of the 

monitoring system to produce a 

continuous record of the measured 

parameters in the measurement units 

required by this subpart. 

Biomass means— 

(1) Any organic material grown for the 

purpose of being converted to energy; 

(2) Any organic byproduct of 

agriculture that can be converted into 

energy; or 

(3) Any material that can be converted 

into energy and is nonmerchantable for 

other purposes, that is segregated from 

other material that is nonmerchantable 

for other purposes, and that is; 

(i) A forest-related organic resource, 

including mill residues, precommercial 

thinnings, slash, brush, or byproduct 

from conversion of trees to 

merchantable material; or 

(ii) A wood material, including 

pallets, crates, dunnage, manufacturing 

and construction materials (other than 

pressure-treated, chemically-treated, or 

painted wood products), and landscape 

or right-of-way tree trimmings. 

Boiler means an enclosed fossil- or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Bottoming-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful thermal 

energy, where at least some of the reject 

heat from the useful thermal energy 

application or process is then used for 

electricity production. 

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 of 

the corporation in charge of a principal 

business function or any other person 

who performs similar policy- or 

decision-making functions for the 

corporation; 

(2) For a partnership or sole 

proprietorship, a general partner or the 

proprietor respectively; or 

(3) For a local government entity or 

State, federal, or other public agency, a 

principal executive officer or ranking 

elected official. 

Clean Air Act means the Clean Air 

Act, 42 U.S.C. 7401, et seq. 

Coal means ‘‘coal’’ as defined in 

§ 72.2 of this chapter. 

Coal-derived fuel means any fuel 

(whether in a solid, liquid, or gaseous 

state) produced by the mechanical, 

thermal, or chemical processing of coal. 

Cogeneration system means an 

integrated group, at a source, of 

equipment (including a boiler, or 

combustion turbine, and a steam turbine 

generator) designed to produce useful 

thermal energy for industrial, 

commercial, heating, or cooling 

purposes and electricity through the 

sequential use of energy. 

Cogeneration unit means a stationary, 

fossil-fuel-fired boiler or stationary, 

fossil-fuel-fired combustion turbine that 

is a topping-cycle unit or a bottomingcycle unit: 

(1) Operating as part of a cogeneration 

system; and 

(2) Producing on an annual average 

basis— 

(i) For a topping-cycle unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less than 42.5 percent 

of total energy input, 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 systemwide 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 § 97.505. 

(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 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 


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and that subsequently undergoes a 

physical change or is moved to a 

different location or source, such date 

shall remain the date of commencement 

of commercial operation of the unit, 

which shall continue to be treated as the 

same unit. 

(ii) For a unit with a date for 

commencement of commercial 

operation as defined in the introductory 

text of paragraph (2) of this definition 

and that is subsequently replaced by a 

unit at the same or a different source, 

such date shall remain the replaced 

unit’s date of commencement of 

commercial operation, and the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of commercial 

operation as defined in paragraph (1) or 

(2) of this definition as appropriate. 

Common designated representative 

means, with regard to a control period 

in a given year, a designated 

representative where, as of April 1 

immediately after the allowance transfer 

deadline for such control period, the 

same natural person is authorized under 

§§ 97.513(a) and 97.515(a) as the 

designated representative for a group of 

one or more TR NOX Ozone Season 

sources and units located in a State (and 

Indian country within the borders of 

such State). 

Common designated representative’s 

assurance level means, with regard to a 

specific common designated 

representative and a State (and Indian 

country within the borders of such 

State) and control period in a given year 

for which the State assurance level is 

exceeded as described in 

§ 97.506(c)(2)(iii), the common 

designated representative’s share of the 

State NOX Ozone Season trading budget 

with the variability limit for the State 

for such control period. 

Common designated representative’s 

share means, with regard to a specific 

common designated representative for a 

control period in a given year: 

(1) With regard to a total amount of 

NOX emissions from all TR NOX Ozone 

Season units in a State (and Indian 

country within the borders of such 

State) during such control period, the 

total tonnage of NOX emissions during 

such control period from a group of one 

or more TR NOX Ozone Season units 

located in such State (and such Indian 

country) and having the common 

designated representative for such 

control period; 

(2) With regard to a State NOX Ozone 

Season trading budget with the 

variability limit for such control period, 

the amount (rounded to the nearest 

allowance) equal to the sum of the total 

amount of TR NOX Ozone Season 

allowances allocated for such control 

period to a group of one or more TR 

NOX Ozone Season units located in the 

State (and Indian country within the 

borders of such State) and having the 

common designated representative for 

such control period and of the total 

amount of TR NOX Ozone Season 

allowances purchased by an owner or 

operator of such TR NOX Ozone Season 

units in an auction for such control 

period and submitted by the State or the 

permitting authority to the 

Administrator for recordation in the 

compliance accounts for such TR NOX

Ozone Season units in accordance with 

the TR NOX Ozone Season allowance 

auction provisions in a SIP revision 

approved by the Administrator under 

§ 52.38(b)(4) or (5) of this chapter, 

multiplied by the sum of the State NOX

Ozone Season trading budget under 

§ 97.510(a) and the State’s variability 

limit under § 97.510(b) for such control 

period and divided by such State NOX

Ozone Season trading budget; 

(3) Provided that, in the case of a unit 

that operates during, but has no amount 

of TR NOX Ozone Season allowances 

allocated under §§ 97.511 and 97.512 

for, such control period, the unit shall 

be treated, solely for purposes of this 

definition, as being allocated an amount 

(rounded to the nearest allowance) of 

TR NOX Ozone Season allowances for 

such control period equal to the unit’s 

allowable NOX emission rate applicable 

to such control period, multiplied by a 

capacity factor of 0.92 (if the unit is a 

boiler combusting any amount of coal or 

coal-derived fuel during such control 

period), 0.32 (if the unit is a simple 

combustion turbine during such control 

period), 0.71 (if the unit is a combined 

cycle turbine during such control 

period), 0.73 (if the unit is an integrated 

coal gasification combined cycle unit 

during such control period), or 0.44 (for 

any other unit), multiplied by the unit’s 

maximum hourly load as reported in 

accordance with this subpart and by 

3,672 hours/control period, and divided 

by 2,000 lb/ton. 

Common stack means a single flue 

through which emissions from 2 or 

more units are exhausted. 

Compliance account means an 

Allowance Management System 

account, established by the 

Administrator for a TR NOX Ozone 

Season source under this subpart, in 

which any TR NOX Ozone Season 

allowance allocations to the TR NOX

Ozone Season units at the source are 

recorded and in which are held any TR 

NOX Ozone Season allowances available 

for use for a control period in a given 

year in complying 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 NOXdiluent) monitoring system, consisting 

of a NOX pollutant concentration 

monitor, a diluent gas (CO2 or O2) 

monitor, and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of NOX concentration, in parts 

per million (ppm), diluent gas 

concentration, in percent CO2 or O2, and 

NOX emission rate, in pounds per 

million British thermal units (lb/ 

mmBtu); 

(4) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O; 

(5) A CO2 monitoring system, 

consisting of a CO2 pollutant 

concentration monitor (or an O2 monitor 

plus suitable mathematical equations 

from which the CO2 concentration is 

derived) and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of CO2 emissions, in percent CO2; 

and 

(6) An O2 monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2, in percent O2. 

Control period means the period 

starting May 1 of a calendar year, except 

as provided in § 97.506(c)(3), and 


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ending on September 30 of the same 

year, inclusive. 

Designated representative means, for 

a TR NOX Ozone Season source and 

each TR NOX Ozone Season unit at the 

source, the natural person who is 

authorized by the owners and operators 

of the source and all such units at the 

source, in accordance with this subpart, 

to represent and legally bind each 

owner and operator in matters 

pertaining to the TR NOX Ozone Season 

Trading Program. If the TR NOX Ozone 

Season source is also subject to the Acid 

Rain Program, TR NOX Annual Trading 

Program, TR SO2 Group 1 Trading 

Program, or TR SO2 Group 2 Trading 

Program, then this natural person shall 

be the same natural person as the 

designated representative, as defined in 

the respective program. 

Emissions means air pollutants 

exhausted from a unit or source into the 

atmosphere, as measured, recorded, and 

reported to the Administrator by the 

designated representative, and as 

modified by the Administrator: 

(1) In accordance with this subpart; 

and 

(2) With regard to a period before the 

unit or source is required to measure, 

record, and report such air pollutants in 

accordance with this subpart, in 

accordance with part 75 of this chapter. 

Excess emissions means any ton of 

emissions from the TR NOX Ozone 

Season units at a TR NOX Ozone Season 

source during a control period in a 

given year that exceeds the TR NOX

Ozone Season emissions limitation for 

the source for such control period. 

Fossil fuel means— 

(1) Natural gas, petroleum, coal, or 

any form of solid, liquid, or gaseous fuel 

derived from such material; or 

(2) For purposes of applying the 

limitation on ‘‘average annual fuel 

consumption of fossil fuel’’ in 

§§ 97.504(b)(2)(i)(B) and (ii), natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material for the purpose of creating 

useful heat. 

Fossil-fuel-fired means, with regard to 

a unit, combusting any amount of fossil 

fuel in 2005 or any calendar year 

thereafter. 

General account means an Allowance 

Management System account, 

established under this subpart, that is 

not a compliance account or an 

assurance account. 

Generator means a device that 

produces electricity. 

Gross electrical output means, for a 

unit, electricity made available for use, 

including any such electricity used in 

the power production process (which 

process includes, but is not limited to, 

any on-site processing or treatment of 

fuel combusted at the unit and any onsite emission controls). 

Heat input means, for a unit for a 

specified period of time, the product (in 

mmBtu/time) of the gross calorific value 

of the fuel (in mmBtu/lb) fed into the 

unit multiplied by the fuel feed rate (in 

lb of fuel/time), as measured, recorded, 

and reported to the Administrator by the 

designated representative and as 

modified by the Administrator in 

accordance with this subpart and 

excluding the heat derived from 

preheated combustion air, recirculated 

flue gases, or exhaust. 

Heat input rate means, for a unit, the 

amount of heat input (in mmBtu) 

divided by unit operating time (in hr) 

or, for a unit and a specific fuel, the 

amount of heat input attributed to the 

fuel (in mmBtu) divided by the unit 

operating time (in hr) during which the 

unit combusts the fuel. 

Heat rate means, for a unit, the unit’s 

maximum design heat input (in Btu/hr), 

divided by the product of 1,000,000 

Btu/mmBtu and the unit’s maximum 

hourly load. 

Indian country means ‘‘Indian 

country’’ as defined in 18 U.S.C. 1151. 

Life-of-the-unit, firm power 

contractual arrangement means a unit 

participation power sales agreement 

under which a utility or industrial 

customer reserves, or is entitled to 

receive, a specified amount or 

percentage of nameplate capacity and 

associated energy generated by any 

specified unit and pays its proportional 

amount of such unit’s total costs, 

pursuant to a contract: 

(1) For the life of the unit; 

(2) For a cumulative term of no less 

than 30 years, including contracts that 

permit an election for early termination; 

or 

(3) For a period no less than 25 years 

or 70 percent of the economic useful life 

of the unit determined as of the time the 

unit is built, with option rights to 

purchase or release some portion of the 

nameplate capacity and associated 

energy generated by the unit at the end 

of the period. 

Maximum design heat input means, 

for a unit, the maximum amount of fuel 

per hour (in Btu/hr) that the unit is 

capable of combusting on a steady state 

basis as of the initial installation of the 

unit as specified by the manufacturer of 

the unit. 

Monitoring system means any 

monitoring system that meets the 

requirements of this subpart, including 

a continuous emission monitoring 

system, an alternative monitoring 

system, or an excepted monitoring 

system under part 75 of this chapter. 

Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe, rounded to 

the nearest tenth) that the generator is 

capable of producing on a steady state 

basis and during continuous operation 

(when not restricted by seasonal or 

other deratings) as of such installation 

as specified by the manufacturer of the 

generator or, starting from the 

completion of any subsequent physical 

change in the generator resulting in an 

increase in the maximum electrical 

generating output that the generator is 

capable of producing on a steady state 

basis and during continuous operation 

(when not restricted by seasonal or 

other deratings), such increased 

maximum amount (in MWe, rounded to 

the nearest tenth) as of such completion 

as specified by the person conducting 

the physical change. 

Natural gas means ‘‘natural gas’’ as 

defined in § 72.2 of this chapter. 

Newly affected TR NOX Ozone Season 

unit means a unit that was not a TR NOX

Ozone Season unit when it began 

operating but that thereafter becomes a 

TR NOX Ozone Season unit. 

Operate or operation means, with 

regard to a unit, to combust fuel. 

Operator means, for a TR NOX Ozone 

Season source or a TR NOX Ozone 

Season unit at a source respectively, any 

person who operates, controls, or 

supervises a TR NOX Ozone Season unit 

at the source or the TR NOX Ozone 

Season unit and shall include, but not 

be limited to, any holding company, 

utility system, or plant manager of such 

source or unit. 

Owner means, for a TR NOX Ozone 

Season source or a TR NOX Ozone 

Season unit at a source respectively, any 

of the following persons: 

(1) Any holder of any portion of the 

legal or equitable title in a TR NOX

Ozone Season unit at the source or the 

TR NOX Ozone Season unit; 

(2) Any holder of a leasehold interest 

in a TR NOX Ozone Season unit at the 

source or the TR NOX Ozone Season 

unit, provided that, unless expressly 

provided for in a leasehold agreement, 

‘‘owner’’ shall not 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 


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unavailable for service and that the 

unit’s owners and operators do not 

expect to return to service in the future. 

Permitting authority means 

‘‘permitting authority’’ as defined in 

§§ 70.2 and 71.2 of this chapter. 

Potential electrical output capacity 

means, for a unit, 33 percent of the 

unit’s maximum design heat input, 

divided by 3,413 Btu/kWh, divided by 

1,000 kWh/MWh, and multiplied by 

8,760 hr/yr. 

Receive or receipt of means, when 

referring to the Administrator, to come 

into possession of a document, 

information, or correspondence 

(whether sent in hard copy or by 

authorized electronic transmission), as 

indicated in an official log, or by a 

notation made on the document, 

information, or correspondence, by the 

Administrator in the regular course of 

business. 

Recordation, record, or recorded 

means, with regard to TR NOX Ozone 

Season allowances, the moving of TR 

NOX Ozone Season allowances by the 

Administrator into, out of, or between 

Allowance Management System 

accounts, for purposes of allocation, 

auction, transfer, or deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter. 

Replacement, replace, or replaced 

means, with regard to a unit, the 

demolishing of a unit, or the permanent 

retirement and permanent disabling of a 

unit, and the construction of another 

unit (the replacement unit) to be used 

instead of the demolished or retired unit 

(the replaced unit). 

Sequential use of energy means: 

(1) The use of reject heat from 

electricity production in a useful 

thermal energy application or process; 

or 

(2) The use of reject heat from useful 

thermal energy application or process in 

electricity production. 

Serial number means, for a TR NOX

Ozone Season allowance, the unique 

identification number assigned to each 

TR NOX Ozone Season allowance by the 

Administrator. 

Solid waste incineration unit means a 

stationary, fossil-fuel-fired boiler or 

stationary, fossil-fuel-fired combustion 

turbine that is a ‘‘solid waste 

incineration unit’’ as defined in section 

129(g)(1) of the Clean Air Act. 

Source means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. This definition 

does not change or otherwise affect the 

definition of ‘‘major source’’, ‘‘stationary 

source’’, or ‘‘source’’ as set forth and 

implemented in a title V operating 

permit program or any other program 

under the Clean Air Act. 

State means one of the States that is 

subject to the TR NOX Ozone Season 

Trading Program pursuant to § 52.38(b) 

of this chapter. 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery; 

(4) Provided that compliance with any 

‘‘submission’’ or ‘‘service’’ deadline 

shall be determined by the date of 

dispatch, transmission, or mailing and 

not the date of receipt. 

Topping-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful power, 

including electricity, where at least 

some of the reject heat from the 

electricity production is then used to 

provide useful thermal energy. 

Total energy input means, for a unit, 

total energy of all forms supplied to the 

unit, excluding energy produced by the 

unit. Each form of energy supplied shall 

be measured by the lower heating value 

of that form of energy calculated as 

follows: 

LHV = HHV ¥ 10.55 (W + 9H) 

Where: 

LHV = lower heating value of the form of 

energy in Btu/lb, 

HHV = higher heating value of the form of 

energy in Btu/lb, 

W = weight % of moisture in the form of 

energy, and 

H = weight % of hydrogen in the form of 

energy. 

Total energy output means, for a unit, 

the sum of useful power and useful 

thermal energy produced by the unit. 

TR NOX Annual Trading Program 

means a multi-state NOX air pollution 

control and emission reduction program 

established in accordance with subpart 

AAAAA of this part and § 52.38(a) of 

this chapter (including such a program 

that is revised in a SIP revision 

approved by the Administrator under 

§ 52.38(a)(3) or (4) of this chapter or that 

is established in a SIP revision approved 

by the Administrator under § 52.38(a)(5) 

of this chapter), as a means of mitigating 

interstate transport of fine particulates 

and NOX.

TR NOX Ozone Season allowance 

means a limited authorization issued 

and allocated or auctioned by the 

Administrator under this subpart, or by 

a State or permitting authority under a 

SIP revision approved by the 

Administrator under § 52.38(b)(3), (4), 

or (5) of this chapter, to emit one ton of 

NOX during a control period of the 

specified calendar year for which the 

authorization is allocated or auctioned 

or of any calendar year thereafter under 

the TR NOX Ozone Season Trading 

Program. 

TR NOX Ozone Season allowance 

deduction or deduct TR NOX Ozone 

Season allowances means the 

permanent withdrawal of TR NOX

Ozone Season allowances by the 

Administrator from a compliance 

account (e.g., in order to account for 

compliance with the TR NOX Ozone 

Season emissions limitation) or from an 

assurance account (e.g., in order to 

account for compliance with the 

assurance provisions under §§ 97.506 

and 97.525). 

TR NOX Ozone Season allowances 

held or hold TR NOX Ozone Season 

allowances means the TR NOX Ozone 

Season allowances treated as included 

in an Allowance Management System 

account as of a specified point in time 

because at that time they: 

(1) Have been recorded by the 

Administrator in the account or 

transferred into the account by a 

correctly submitted, but not yet 

recorded, TR NOX Ozone Season 

allowance transfer in accordance with 

this subpart; and 

(2) Have not been transferred out of 

the account by a correctly submitted, 

but not yet recorded, TR NOX Ozone 

Season allowance transfer in accordance 

with this subpart. 

TR NOX Ozone Season emissions 

limitation means, for a TR NOX Ozone 

Season source, the tonnage of NOX

emissions authorized in a control period 

in a given year by the TR NOX Ozone 

Season allowances available for 

deduction for the source under 

§ 97.524(a) for such control period. 

TR NOX Ozone Season source means 

a source that includes one or more TR 

NOX Ozone Season units. 

TR NOX Ozone Season Trading 

Program means a multi-state NOX air 

pollution control and emission 

reduction program established in 

accordance with this subpart and 

§ 52.38(b) of this chapter (including 

such a program that is revised in a SIP 

revision approved by the Administrator 

under § 52.38(b)(3) or (4) of this chapter 

or that is established in a SIP revision 

approved by the Administrator under 

§ 52.38(b)(5) of this chapter), as a means 

of mitigating interstate transport of 

ozone and NOX. 

TR NOX Ozone Season unit means a 

unit that is subject to the TR NOX Ozone 

Season Trading Program. 


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TR SO2 Group 1 Trading Program 

means a multi-state SO2 air pollution 

control and emission reduction program 

established in accordance with subpart 

CCCCC of this part and 52.39(a), (b), (d) 

through (f), (j), and (k) of this chapter 

(including such a program that is 

revised in a SIP revision approved by 

the Administrator under § 52.39(d) or (e) 

of this chapter or that is established in 

a SIP revision approved by the 

Administrator under § 52.39(f) of this 

chapter), as a means of mitigating 

interstate transport of fine particulates 

and SO2. 

TR SO2 Group 2 Trading Program 

means a multi-state SO2 air pollution 

control and emission reduction program 

established in accordance with subpart 

DDDDD of this part and 52.39(a), (c), 

and (g) through (k) of this chapter 

(including such a program that is 

revised in a SIP revision approved by 

the Administrator under § 52.39(g) or (h) 

of this chapter or that is established in 

a SIP revision approved by the 

Administrator under § 52.39(i) of this 

chapter), as a means of mitigating 

interstate transport of fine particulates 

and SO2. 

Unit means a stationary, fossil-fuelfired 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 processing or treatment of 

fuel combusted at the unit and any onsite emission controls). 

Useful thermal energy means thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process (not a power 

production process), excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heating application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., in an absorption 

chiller). 

Utility power distribution system 

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers. 

§ 97.503 Measurements, abbreviations, 

and acronyms. 

Measurements, abbreviations, and 

acronyms used in this subpart are 

defined as follows: 

Btu—British thermal unit 

CO2—carbon dioxide 

H2O—water 

hr—hour 

kW—kilowatt electrical 

kWh—kilowatt hour 

lb—pound 

mmBtu—million Btu 

MWe—megawatt electrical 

MWh—megawatt hour 

NOX—nitrogen oxides 

O2—oxygen 

ppm—parts per million 

scfh—standard cubic feet per hour 

SO2—sulfur dioxide 

yr—year 

§ 97.504 Applicability. 

(a) Except as provided in paragraph 

(b) of this section: 

(1) The following units in a State (and 

Indian country within the borders of 

such State) shall be TR NOX Ozone 

Season units, and any source that 

includes one or more such units shall be 

a TR NOX Ozone Season source, subject 

to the requirements of this subpart: any 

stationary, fossil-fuel-fired boiler or 

stationary, fossil-fuel-fired combustion 

turbine serving at any time, on or after 

January 1, 2005, a generator with 

nameplate capacity of more than 25 

MWe producing electricity for sale. 

(2) If a stationary boiler or stationary 

combustion turbine that, under 

paragraph (a)(1) of this section, is not a 

TR NOX Ozone Season unit begins to 

combust fossil fuel or to serve a 

generator with nameplate capacity of 

more than 25 MWe producing electricity 

for sale, the unit shall become a TR NOX

Ozone Season unit as provided in 

paragraph (a)(1) of this section on the 

first date on which it both combusts 

fossil fuel and serves such generator. 

(b) Any unit in a State (and Indian 

country within the borders of such 

State) that otherwise is a TR NOX Ozone 

Season unit under paragraph (a) of this 

section and that meets the requirements 

set forth in paragraph (b)(1)(i) or (2)(i) of 

this section shall not be a TR NOX

Ozone Season unit: 

(1)(i) Any unit: 

(A) Qualifying as a cogeneration unit 

throughout the later of 2005 or the 12- 

month period starting on the date the 

unit first produces electricity and 

continuing to qualify as a cogeneration 

unit throughout each calendar year 

ending after the later of 2005 or such 

12-month period; and 

(B) Not supplying in 2005 or any 

calendar year thereafter more than onethird of the unit’s potential electric 

output capacity or 219,000 MWh, 

whichever is greater, to any utility 

power distribution system for sale. 

(ii) If, after qualifying under 

paragraph (b)(1)(i) of this section as not 

being a TR NOX Ozone Season unit, a 

unit subsequently no longer meets all 

the requirements of paragraph (b)(1)(i) 

of this section, the unit shall become a 

TR NOX Ozone Season unit starting on 

the earlier of January 1 after the first 

calendar year during which the unit first 

no longer qualifies as a cogeneration 

unit or January 1 after the first calendar 

year during which the unit no longer 

meets the requirements of paragraph 

(b)(1)(i)(B) of this section. The unit shall 

thereafter continue to be a TR NOX

Ozone Season unit. 

(2)(i) Any unit: 

(A) Qualifying as a solid waste 

incineration unit throughout the later of 

2005 or the 12-month period starting on 

the date the unit first produces 

electricity and continuing to qualify as 

a solid waste incineration unit 

throughout each calendar year ending 

after the later of 2005 or such 12-month 

period; and 

(B) With an average annual fuel 

consumption of fossil fuel for the first 

3 consecutive calendar years of 

operation starting no earlier than 2005 

of less than 20 percent (on a Btu basis) 

and an average annual fuel consumption 

of fossil fuel for any 3 consecutive 

calendar years thereafter of less than 20 

percent (on a Btu basis). 

(ii) If, after qualifying under 

paragraph (b)(2)(i) of this section as not 

being a TR NOX Ozone Season unit, a 

unit subsequently no longer meets all 

the requirements of paragraph (b)(1)(i) 

of this section, the unit shall become a 

TR NOX Ozone Season unit starting on 

the earlier of January 1 after the first 

calendar year during which the unit first 

no longer qualifies as a solid waste 

incineration unit or January 1 after the 

first 3 consecutive calendar years after 

2005 for which the unit has an average 

annual fuel consumption of fossil fuel of 

20 percent or more. The unit shall 

thereafter continue to be a TR NOX 

Ozone Season unit. 

(c) A certifying official of an owner or 

operator of any unit or other equipment 


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may submit a petition (including any 

supporting documents) to the 

Administrator at any time for a 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section or a SIP revision 

approved under § 52.38(b)(4) or (5) of 

this chapter, of the TR NOX Ozone 

Season Trading Program to the unit or 

other equipment. 

(1) Petition content. The petition shall 

be in writing and include the 

identification of the unit or other 

equipment and the relevant facts about 

the unit or other equipment. The 

petition and any other documents 

provided to the Administrator in 

connection with the petition shall 

include the following certification 

statement, signed by the certifying 

official: ‘‘I am authorized to make this 

submission on behalf of the owners and 

operators of the unit or other equipment 

for which the submission is made. I 

certify under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(2) Response. The Administrator will 

issue a written response to the petition 

and may request supplemental 

information determined by the 

Administrator to be relevant to such 

petition. The Administrator’s 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section, of the TR NOX Ozone 

Season Trading Program to the unit or 

other equipment shall be binding on any 

State or permitting authority unless the 

Administrator determines that the 

petition or other documents or 

information provided in connection 

with the petition contained significant, 

relevant errors or omissions. 

§ 97.505 Retired unit exemption. 

(a)(1) Any TR NOX Ozone Season unit 

that is permanently retired shall be 

exempt from § 97.506(b) and (c)(1), 

§ 97.524, and §§ 97.530 through 97.535. 

(2) The exemption under paragraph 

(a)(1) of this section shall become 

effective the day on which the TR NOX

Ozone Season unit is permanently 

retired. Within 30 days of the unit’s 

permanent retirement, the designated 

representative shall submit a statement 

to the Administrator. The statement 

shall state, in a format prescribed by the 

Administrator, that the unit was 

permanently retired on a specified date 

and will comply with the requirements 

of paragraph (b) of this section. 

(b) Special provisions. (1) A unit 

exempt under paragraph (a) of this 

section shall not emit any NOX, starting 

on the date that the exemption takes 

effect. 

(2) For a period of 5 years from the 

date the records are created, the owners 

and operators of a unit exempt under 

paragraph (a) of this section shall retain, 

at the source that includes the unit, 

records demonstrating that the unit is 

permanently retired. The 5-year period 

for keeping records may be extended for 

cause, at any time before the end of the 

period, in writing by the Administrator. 

The owners and operators bear the 

burden of proof that the unit is 

permanently retired. 

(3) The owners and operators and, to 

the extent applicable, the designated 

representative of a unit exempt under 

paragraph (a) of this section shall 

comply with the requirements of the TR 

NOX Ozone Season Trading Program 

concerning all periods for which the 

exemption is not in effect, even if such 

requirements arise, or must be complied 

with, after the exemption takes effect. 

(4) A unit exempt under paragraph (a) 

of this section shall lose its exemption 

on the first date on which the unit 

resumes operation. Such unit shall be 

treated, for purposes of applying 

allocation, monitoring, reporting, and 

recordkeeping requirements under this 

subpart, as a unit that commences 

commercial operation on the first date 

on which the unit resumes operation. 

§ 97.506 Standard requirements. 

(a) Designated representative 

requirements. The owners and operators 

shall comply with the requirement to 

have a designated representative, and 

may have an alternate designated 

representative, in accordance with 

§§ 97.513 through 97.518. 

(b) Emissions monitoring, reporting, 

and recordkeeping requirements. (1) 

The owners and operators, and the 

designated representative, of each TR 

NOX Ozone Season source and each TR 

NOX Ozone Season unit at the source 

shall comply with the monitoring, 

reporting, and recordkeeping 

requirements of §§ 97.530 through 

97.535. 

(2) The emissions data determined in 

accordance with §§ 97.530 through 

97.535 shall be used to calculate 

allocations of TR NOX Ozone Season 

allowances under §§ 97.511(a)(2) and (b) 

and 97.512 and to determine 

compliance with the TR NOX Ozone 

Season emissions limitation and 

assurance provisions under paragraph 

(c) of this section, provided that, for 

each monitoring location from which 

mass emissions are reported, the mass 

emissions amount used in calculating 

such allocations and determining such 

compliance shall be the mass emissions 

amount for the monitoring location 

determined in accordance with 

§§ 97.530 through 97.535 and rounded 

to the nearest ton, with any fraction of 

a ton less than 0.50 being deemed to be 

zero. 

(c) NOX emissions requirements. (1) 

TR NOX Ozone Season emissions 

limitation. (i) As of the allowance 

transfer deadline for a control period 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. 

(2) TR NOX Ozone Season assurance 

provisions. (i) If total NOX emissions 

during a control period in a given year 

from all TR NOX Ozone Season units at 

TR NOX Ozone Season sources in a 

State (and Indian country within the 

borders of such State) exceed the State 

assurance level, then the owners and 

operators of such sources and units in 

each group of one or more sources and 

units having a common designated 

representative for such control period, 

where the common designated 

representative’s share of such NOX

emissions during such control period 

exceeds the common designated 


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representative’s assurance level for the 

State and such control period, shall 

hold (in the assurance account 

established for the owners and operators 

of such group) TR NOX Ozone Season 

allowances available for deduction for 

such control period under § 97.525(a) in 

an amount equal to two times the 

product (rounded to the nearest whole 

number), as determined by the 

Administrator in accordance with 

§ 97.525(b), of multiplying— 

(A) The quotient of the amount by 

which the common designated 

representative’s share of such NOX

emissions exceeds the common 

designated representative’s assurance 

level divided by the sum of the 

amounts, determined for all common 

designated representatives for such 

sources and units in the State (and 

Indian country within the borders of 

such State) for such control period, by 

which each common designated 

representative’s share of such NOX

emissions exceeds the respective 

common designated representative’s 

assurance level; and 

(B) The amount by which total NOX

emissions from all TR NOX Ozone 

Season units at TR NOX Ozone Season 

sources in the State (and Indian country 

within the borders of such State) for 

such control period exceed the State 

assurance level. 

(ii) The owners and operators shall 

hold the TR NOX Ozone Season 

allowances required under paragraph 

(c)(2)(i) of this section, as of midnight of 

November 1 (if it is a business day), or 

midnight of the first business day 

thereafter (if November 1 is not a 

business day), immediately after such 

control period. 

(iii) Total NOX emissions from all TR 

NOX Ozone Season units at TR NOX

Ozone Season sources in a State (and 

Indian country within the borders of 

such State) during a control period in a 

given year exceed the State assurance 

level if such total NOX emissions exceed 

the sum, for such control period, of the 

State NOX Ozone Season trading budget 

under § 97.510(a) and the State’s 

variability limit under § 97.510(b). 

(iv) It shall not be a violation of this 

subpart or of the Clean Air Act if total 

NOX emissions from all TR NOX Ozone 

Season units at TR NOX Ozone Season 

sources in a State (and Indian country 

within the borders of such State) during 

a control period exceed the State 

assurance level or if a common 

designated representative’s share of total 

NOX emissions from the TR NOX Ozone 

Season units at TR NOX Ozone Season 

sources in a State (and Indian country 

within the borders of such State) during 

a control period exceeds the common 

designated representative’s assurance 

level. 

(v) To the extent the owners and 

operators fail to hold TR NOX Ozone 

Season allowances for a control period 

in a given year in accordance with 

paragraphs (c)(2)(i) through (iii) of this 

section, 

(A) The owners and operators shall 

pay any fine, penalty, or assessment or 

comply with any other remedy imposed 

under the Clean Air Act; and 

(B) Each TR NOX Ozone Season 

allowance that the owners and operators 

fail to hold for such control period in 

accordance with paragraphs (c)(2)(i) 

through (iii) of this section and each day 

of such control period shall constitute a 

separate violation of this subpart and 

the Clean Air Act. 

(3) Compliance periods. A TR NOX

Ozone Season unit shall be subject to 

the requirements under paragraphs 

(c)(1) and (c)(2) of this section for the 

control period starting on the later of 

May 1, 2012 or the deadline for meeting 

the unit’s monitor certification 

requirements under § 97.530(b) and for 

each control period thereafter. 

(4) Vintage of allowances held for 

compliance. (i) A TR NOX Ozone Season 

allowance held for compliance with the 

requirements under paragraph (c)(1)(i) 

of this section for a control period in a 

given year must be a TR NOX Ozone 

Season allowance that was allocated for 

such control period or a control period 

in a prior year. 

(ii) A TR NOX Ozone Season 

allowance held for compliance with the 

requirements under paragraphs 

(c)(1)(ii)(A) and (2)(i) through (iii) of this 

section for a control period in a given 

year must be a TR NOX Ozone Season 

allowance that was allocated for a 

control period in a prior year or the 

control period in the given year or in the 

immediately following year. 

(5) Allowance Management System 

requirements. Each TR NOX Ozone 

Season allowance shall be held in, 

deducted from, or transferred into, out 

of, or between Allowance Management 

System accounts in accordance with 

this subpart. 

(6) Limited authorization. A TR NOX

Ozone Season allowance is a limited 

authorization to emit one ton of NOX

during the control period in one year. 

Such authorization is limited in its use 

and duration as follows: 

(i) Such authorization shall only be 

used in accordance with the TR NOX

Ozone Season Trading Program; and 

(ii) Notwithstanding any other 

provision of this subpart, the 

Administrator has the authority to 

terminate or limit the use and duration 

of such authorization to the extent the 

Administrator determines is necessary 

or appropriate to implement any 

provision of the Clean Air Act. 

(7) Property right. A TR NOX Ozone 

Season allowance does not constitute a 

property right. 

(d) Title V permit requirements. (1) No 

title V permit revision shall be required 

for any allocation, holding, deduction, 

or transfer of TR NOX Ozone Season 

allowances in accordance with this 

subpart. 

(2) A description of whether a unit is 

required to monitor and report NOX

emissions using a continuous emission 

monitoring system (under subpart H of 

part 75 of this chapter), an excepted 

monitoring system (under appendices D 

and E to part 75 of this chapter), a low 

mass emissions excepted monitoring 

methodology (under § 75.19 of this 

chapter), or an alternative monitoring 

system (under subpart E of part 75 of 

this chapter) in accordance with 

§§ 97.530 through 97.535 may be added 

to, or changed in, a title V permit using 

minor permit modification procedures 

in accordance with §§ 70.7(e)(2) and 

71.7(e)(1) of this chapter, provided that 

the requirements applicable to the 

described monitoring and reporting (as 

added or changed, respectively) are 

already incorporated in such permit. 

This paragraph explicitly provides that 

the addition of, or change to, a unit’s 

description as described in the prior 

sentence is eligible for minor permit 

modification procedures in accordance 

with §§ 70.7(e)(2)(i)(B) and 

71.7(e)(1)(i)(B) of this chapter. 

(e) Additional recordkeeping and 

reporting requirements. (1) Unless 

otherwise provided, the owners and 

operators of each TR NOX Ozone Season 

source and each TR NOX Ozone Season 

unit at the source shall keep on site at 

the source each of the following 

documents (in hardcopy or electronic 

format) for a period of 5 years from the 

date the document is created. This 

period may be extended for cause, at 

any time before the end of 5 years, in 

writing by the Administrator. 

(i) The certificate of representation 

under § 97.516 for the designated 

representative for the source and each 

TR NOX Ozone Season unit at the 

source and all documents that 

demonstrate the truth of the statements 

in the certificate of representation; 

provided that the certificate and 

documents shall be retained on site at 

the source beyond such 5-year period 

until such certificate of representation 

and documents are superseded because 

of the submission of a new certificate of 

representation under § 97.516 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 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, except as 

provided in § 97.518. This requirement 

does not change, create an exemption 

from, or otherwise affect the responsible 

official submission requirements under 

a title V operating permit program in 

parts 70 and 71 of this chapter. 

(f) Liability. (1) Any provision of the 

TR NOX Ozone Season Trading Program 

that applies to a TR NOX Ozone Season 

source or the designated representative 

of a TR NOX Ozone Season source shall 

also apply to the owners and operators 

of such source and of the TR NOX

Ozone Season units at the source. 

(2) Any provision of the TR NOX

Ozone Season Trading Program that 

applies to a TR NOX Ozone Season unit 

or the designated representative of a TR 

NOX Ozone Season unit shall also apply 

to the owners and operators of such 

unit. 

(g) Effect on other authorities. No 

provision of the TR NOX Ozone Season 

Trading Program or exemption under 

§ 97.505 shall be construed as 

exempting or excluding the owners and 

operators, and the designated 

representative, of a TR NOX Ozone 

Season source or TR NOX Ozone Season 

unit from compliance with any other 

provision of the applicable, approved 

State implementation plan, a federally 

enforceable permit, or the Clean Air Act. 

§ 97.507 Computation of time. 

(a) Unless otherwise stated, any time 

period scheduled, under the TR NOX

Ozone Season Trading Program, to begin 

on the occurrence of an act or event 

shall begin on the day the act or event 

occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the TR NOX

Ozone Season Trading Program, to begin 

before the occurrence of an act or event 

shall be computed so that the period 

ends the day before the act or event 

occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the TR 

NOX Ozone Season Trading Program, is 

not a business day, the time period shall 

be extended to the next business day. 

§ 97.508 Administrative appeal 

procedures. 

The administrative appeal procedures 

for decisions of the Administrator under 

the TR NOX Ozone Season Trading 

Program are set forth in part 78 of this 

chapter. 

§ 97.509 [Reserved] 

§ 97.510 State NOX Ozone Season trading 

budgets, new unit set-asides, Indian 

country new unit set-aside, and variability 

limits. 

(a) The State NOX Ozone Season 

trading budgets, new unit set-asides, 

and Indian country new unit set-asides 

for allocations of TR NOX Ozone Season 

allowances for the control periods in 

2012 and thereafter are as follows: 

State 

NOX Ozone Season trading budget 

(tons) * for 2012 

and 2013 

New unit set-aside 

(tons) for 2012 and 

2013 

Indian country new 

unit set-aside (tons) 

for 2012 and 2013 

Alabama ............................................................................................................... 31,746 635 ................................

Arkansas .............................................................................................................. 15,037 301 ................................

Florida .................................................................................................................. 27,825 529 28 

Georgia ................................................................................................................ 27,944 559 ................................

Illinois ................................................................................................................... 21,208 1,697 ................................

Indiana ................................................................................................................. 46,876 1,406 ................................

Kentucky .............................................................................................................. 36,167 1,447 ................................

Louisiana .............................................................................................................. 13,432 390 13 

Maryland .............................................................................................................. 7,179 144 ................................

Mississippi ............................................................................................................ 10,160 193 10 

New Jersey .......................................................................................................... 3,382 68 ................................

New York ............................................................................................................. 8,331 242 8 

North Carolina ...................................................................................................... 22,168 1,308 22 

Ohio ..................................................................................................................... 40,063 801 ................................

Pennsylvania ........................................................................................................ 52,201 1,044 ................................

South Carolina ..................................................................................................... 13,909 264 14 

Tennessee ........................................................................................................... 14,908 298 ................................

Texas ................................................................................................................... 63,043 1,828 63 

Virginia ................................................................................................................. 14,452 723 ................................

West Virginia ........................................................................................................ 25,283 1,264 ................................

State 

NOX Ozone Season trading budget 

(tons) * for 2014 

and thereafter 

New unit set-aside 

(tons) for 2014 and 

thereafter 

Indian country new 

unit set-aside (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 ................................


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State 

NOX Ozone Season trading budget 

(tons) * for 2014 

and thereafter 

New unit set-aside 

(tons) for 2014 and 

thereafter 

Indian country new 

unit set-aside (tons) 

for 2014 and thereafter 

New York ............................................................................................................. 8,331 242 8 

North Carolina ...................................................................................................... 18,455 1,089 18 

Ohio ..................................................................................................................... 37,792 756 ................................

Pennsylvania ........................................................................................................ 51,912 1,038 ................................

South Carolina ..................................................................................................... 13,909 264 14 

Tennessee ........................................................................................................... 8,016 160 ................................

Texas ................................................................................................................... 63,043 1,828 63 

Virginia ................................................................................................................. 14,452 723 ................................

West Virginia ........................................................................................................ 23,291 1,165 ................................

* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-aside and does not include the 

variability limit. 

(b) The States’ variability limits for 

the State NOX Ozone Season trading 

budgets for the control periods in 2012 

and thereafter are as follows: 

State Variability limits for 

2012 and 2013 

Variability limits for 

2014 and thereafter 

Alabama ................................................................................................................................................... 6,667 6,615 

Arkansas .................................................................................................................................................. 3,158 3,158 

Florida ...................................................................................................................................................... 5,843 5,843 

Georgia .................................................................................................................................................... 5,868 3,839 

Illinois ....................................................................................................................................................... 4,454 4,454 

Indiana ..................................................................................................................................................... 9,844 9,697 

Kentucky .................................................................................................................................................. 7,595 6,862 

Louisiana .................................................................................................................................................. 2,821 2,821 

Maryland .................................................................................................................................................. 1,508 1,508 

Mississippi ................................................................................................................................................ 2,134 2,134 

New Jersey .............................................................................................................................................. 710 710 

New York ................................................................................................................................................. 1,750 1,750 

North Carolina .......................................................................................................................................... 4,655 3,876 

Ohio ......................................................................................................................................................... 8,413 7,936 

Pennsylvania ............................................................................................................................................ 10,962 10,902 

South Carolina ......................................................................................................................................... 2,921 2,921 

Tennessee ............................................................................................................................................... 3,131 1,683 

Texas ....................................................................................................................................................... 13,239 13,239 

Virginia ..................................................................................................................................................... 3,035 3,035 

West Virginia ............................................................................................................................................ 5,309 4,891 

§ 97.511 Timing requirements for TR NOX

Ozone Season allowance allocations. 

(a) Existing units. (1) TR NOX Ozone 

Season allowances are allocated, for the 

control periods in 2012 and each year 

thereafter, as provided in a notice of 

data availability issued by the 

Administrator. Providing an allocation 

to a unit in such notice does not 

constitute a determination that the unit 

is a TR NOX Ozone Season unit, and not 

providing an allocation to a unit in such 

notice does not constitute a 

determination that the unit is not a TR 

NOX Ozone Season unit. 

(2) Notwithstanding paragraph (a)(1) 

of this section, if a unit provided an 

allocation in the notice of data 

availability issued under paragraph 

(a)(1) of this section does not operate, 

starting after 2011, during the control 

period in two consecutive years, such 

unit will not be allocated the TR NOX

Ozone Season allowances provided 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 setasides. (i) By June 1, 2012 and June 1 

of each year thereafter, the 

Administrator will calculate the TR 

NOX Ozone Season allowance allocation 

to each TR NOX Ozone Season unit in 

a State, in accordance with 

§ 97.512(a)(2) through (7) and (12), for 

the control period in the year of the 

applicable calculation deadline under 

this paragraph and will promulgate a 

notice of data availability of the results 

of the calculations. 

(ii) For each notice of data availability 

required in paragraph (b)(1)(i) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. 

(A) Objections shall be submitted by 

the deadline specified in each notice of 

data availability required in paragraph 

(b)(1)(i) of this section and shall be 

limited to addressing whether the 

calculations (including the 

identification of the TR NOX Ozone 

Season units) are in accordance with 

§ 97.512(a)(2) through (7) and (12) and 

§§ 97.506(b)(2) and 97.530 through 

97.535. 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(1)(ii)(A) of this section. By August 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(1)(i) of this section, the 

Administrator will promulgate a notice 


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of data availability of any adjustments 

that the Administrator determines to be 

necessary with regard to allocations 

under § 97.512(a)(2) through (7) and (12) 

and the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(1)(ii)(A) 

of this section. 

(iii) If the new unit set-aside for such 

control period contains any TR NOX

Ozone Season allowances that have not 

been allocated in the applicable notice 

of data availability required in 

paragraph (b)(1)(ii) of this section, the 

Administrator will promulgate, by 

September 15 immediately after such 

notice, a notice of data availability that 

identifies any TR NOX Ozone Season 

units that commenced commercial 

operation during the period starting 

May 1 of the year before the year of such 

control period and ending August 31 of 

year of such control period. 

(iv) For each notice of data 

availability required in paragraph 

(b)(1)(iii) of this section, the 

Administrator will provide an 

opportunity for submission of objections 

to the identification of TR NOX Ozone 

Season units in such notice. 

(A) Objections shall be submitted by 

the deadline specified in each notice of 

data availability required in paragraph 

(b)(1)(iii) of this section and shall be 

limited to addressing whether the 

identification of TR NOX Ozone Season 

units in such notice is in accordance 

with paragraph (b)(1)(iii) of this section. 

(B) The Administrator will adjust the 

identification of TR NOX Ozone Season 

units in the each notice of data 

availability required in paragraph 

(b)(1)(iii) of this section to the extent 

necessary to ensure that it is in 

accordance with paragraph (b)(1)(iii) of 

this section and will calculate the TR 

NOX Ozone Season allowance allocation 

to each TR NOX Ozone Season unit in 

accordance with § 97.512(a)(9), (10), and 

(12) and §§ 97.506(b)(2) and 97.530 

through 97.535. By November 15 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(1)(iii) of this section, 

the Administrator will promulgate a 

notice of data availability of any 

adjustments of the identification of TR 

NOX Ozone Season units that the 

Administrator determines to be 

necessary, the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(1)(iv)(A) 

of this section, and the results of such 

calculations. 

(v) To the extent any TR NOX Ozone 

Season allowances are added to the new 

unit set-aside after promulgation of each 

notice of data availability required in 

paragraph (b)(1)(iv) of this section, the 

Administrator will promulgate 

additional notices of data availability, as 

deemed appropriate, of the allocation of 

such TR NOX Ozone Season allowances 

in accordance with § 97.512(a)(10). 

(2) Indian country new unit setasides. (i) By June 1, 2012 and June 1 

of each year thereafter, the 

Administrator will calculate the TR 

NOX Ozone Season allowance allocation 

to each TR NOX Ozone Season unit in 

Indian country within the borders of a 

State, in accordance with § 97.512(b)(2) 

through (7) and (12), for the control 

period in the year of the applicable 

calculation deadline under this 

paragraph and will promulgate a notice 

of data availability of the results of the 

calculations. 

(ii) For each notice of data availability 

required in paragraph (b)(2)(i) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. 

(A) Objections shall be submitted by 

the deadline specified in each notice of 

data availability required in paragraph 

(b)(2)(i) of this section and shall be 

limited to addressing whether the 

calculations (including the 

identification of the TR NOX Ozone 

Season units) are in accordance with 

§ 97.512(b)(2) through (7) and (12) and 

§§ 97.506(b)(2) and 97.530 through 

97.535. 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(ii)(A) of this section. By August 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(2)(i) of this section, the 

Administrator will promulgate a notice 

of data availability of any adjustments 

that the Administrator determines to be 

necessary with regard to allocations 

under § 97.512(b)(2) through (7) and (12) 

and the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(2)(ii)(A) 

of this section. 

(iii) If the Indian country new unit 

set-aside for such control period 

contains any TR NOX Ozone Season 

allowances that have not been allocated 

in the applicable notice of data 

availability required in paragraph 

(b)(2)(ii) of this section, the 

Administrator will promulgate, by 

September 15 immediately after such 

notice, a notice of data availability that 

identifies any TR NOX Ozone Season 

units that commenced commercial 

operation during the period starting 

May 1 of the year before the year of such 

control period and ending August 31 of 

year of such control period. 

(iv) For each notice of data 

availability required in paragraph 

(b)(2)(iii) of this section, the 

Administrator will provide an 

opportunity for submission of objections 

to the identification of TR NOX Ozone 

Season units in such notice. 

(A) Objections shall be submitted by 

the deadline specified in each notice of 

data availability required in paragraph 

(b)(2)(iii) of this section and shall be 

limited to addressing whether the 

identification of TR NOX Ozone Season 

units in such notice is in accordance 

with paragraph (b)(2)(iii) of this section. 

(B) The Administrator will adjust the 

identification of TR NOX Ozone Season 

units in the each notice of data 

availability required in paragraph 

(b)(2)(iii) of this section to the extent 

necessary to ensure that it is in 

accordance with paragraph (b)(2)(iii) of 

this section and will calculate the TR 

NOX Ozone Season allowance allocation 

to each TR NOX Ozone Season unit in 

accordance with § 97.512(b)(9), (10), and 

(12) and §§ 97.506(b)(2) and 97.530 

through 97.535. By November 15 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(2)(iii) of this section, 

the Administrator will promulgate a 

notice of data availability of any 

adjustments of the identification of TR 

NOX Ozone Season units that the 

Administrator determines to be 

necessary, the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(2)(iv)(A) 

of this section, and the results of such 

calculations. (v) To the extent any TR 

NOX Ozone Season allowances are 

added to the Indian country new unit 

set-aside after promulgation of each 

notice of data availability required in 

paragraph (b)(2)(iv) of this section, the 

Administrator will promulgate 

additional notices of data availability, as 

deemed appropriate, of the allocation of 

such TR NOX Ozone Season allowances 

in accordance with § 97.512(b)(10). 

(c) Units incorrectly allocated TR NOX

Ozone Season allowances. (1) For each 

control period in 2012 and thereafter, if 

the Administrator determines that TR 

NOX Ozone Season allowances were 

allocated under paragraph (a) of this 

section, or under a provision of a SIP 

revision approved under § 52.38(b)(3), 

(4), or (5) of this chapter, where such 

control period and the recipient are 

covered by the provisions of paragraph 

(c)(1)(i) of this section or were allocated 

under § 97.512(a)(2) through (7), (9), and 

(12) and (b)(2) through (7), (9), and (12), 

or under a provision of a SIP revision 

approved under § 52.38(b)(4) or (5) of 

this chapter, where such control period 

and the recipient are covered by the 


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provisions of paragraph (c)(1)(ii) of this 

section, then the Administrator will 

notify the designated representative of 

the recipient and will act in accordance 

with the procedures set forth in 

paragraphs (c)(2) through (5) of this 

section: 

(i)(A) The recipient is not actually a 

TR NOX Ozone Season unit under 

§ 97.504 as of May 1, 2012 and is 

allocated TR NOX Ozone Season 

allowances for such control period or, in 

the case of an allocation under a 

provision of a SIP revision approved 

under § 52.38(b)(3), (4), or (5) of this 

chapter, the recipient is not actually a 

TR NOX Ozone Season unit as of May 

1, 2012 and is allocated TR NOX Ozone 

Season allowances for such control 

period that the SIP revision provides 

should be allocated only to recipients 

that are TR NOX Ozone Season units as 

of May 1, 2012; or 

(B) The recipient is not located as of 

May 1 of the control period in the State 

from whose NOX Ozone Season trading 

budget the TR NOX Ozone Season 

allowances allocated under paragraph 

(a) of this section, or under a provision 

of a SIP revision approved under 

§ 52.38(b)(3), (4), or (5) of this chapter, 

were allocated for such control period. 

(ii) The recipient is not actually a TR 

NOX Ozone Season unit under § 97.504 

as of May 1 of such control period and 

is allocated TR NOX Ozone Season 

allowances for such control period or, in 

the case of an allocation under a 

provision of a SIP revision approved 

under § 52.38(b)(3), (4), or (5) of this 

chapter, the recipient is not actually a 

TR NOX Ozone Season unit as of 

January 1 of such control period and is 

allocated TR NOX Ozone Season 

allowances for such control period that 

the SIP revision provides should be 

allocated only to recipients that are TR 

NOX Ozone Season units as of May 1 of 

such control period. 

(2) Except as provided in paragraph 

(c)(3) or (4) of this section, the 

Administrator will not record such TR 

NOX Ozone Season allowances under 

§ 97.521. 

(3) If the Administrator already 

recorded such TR NOX Ozone Season 

allowances under § 97.521 and if the 

Administrator makes the determination 

under paragraph (c)(1) of this section 

before making deductions for the source 

that includes such recipient under 

§ 97.524(b) for such control period, then 

the Administrator will deduct from the 

account in which such TR NOX Ozone 

Season allowances were recorded an 

amount of TR NOX Ozone Season 

allowances allocated for the same or a 

prior control period equal to the amount 

of such already recorded TR NOX Ozone 

Season allowances. The authorized 

account representative shall ensure that 

there are sufficient TR NOX Ozone 

Season allowances in such account for 

completion of the deduction. 

(4) If the Administrator already 

recorded such TR NOX Ozone Season 

allowances under § 97.521 and if the 

Administrator makes the determination 

under paragraph (c)(1) of this section 

after making deductions for the source 

that includes such recipient under 

§ 97.524(b) for such control period, then 

the Administrator will not make any 

deduction to take account of such 

already recorded TR NOX Ozone Season 

allowances. 

(5)(i) With regard to the TR NOX

Ozone Season allowances that are not 

recorded, or that are deducted as an 

incorrect allocation, in accordance with 

paragraphs (c)(2) and (3) of this section 

for a recipient under paragraph (c)(1)(i) 

of this section, the Administrator will: 

(A) Transfer such TR NOX Ozone 

Season allowances to the new unit setaside for such control period for the 

State from whose NOX Ozone Season 

trading budget the TR NOX Ozone 

Season allowances were allocated; or 

(B) If the State has a SIP revision 

approved under § 52.38(b)(4) or (5) 

covering such control period, include 

such TR NOX Annual allowances in the 

portion of the State NOX Ozone Season 

trading budget that may be allocated for 

such control period in accordance with 

such SIP revision. 

(ii) With regard to the TR NOX Ozone 

Season allowances that were not 

allocated from the Indian country new 

unit set-aside for such control period 

and that are not recorded, or that are 

deducted as an incorrect allocation, in 

accordance with paragraphs (c)(2) and 

(3) of this section for a recipient under 

paragraph (c)(1)(ii) of this paragraph, the 

Administrator will: 

(A) Transfer such TR NOX Ozone 

Season allowances to the new unit setaside for such control period; or 

(B) If the State has a SIP revision 

approved under § 52.38(b)(4) or (5) 

covering such control period, include 

such TR NOX Ozone Season allowances 

in the portion of the State NOX Ozone 

Season trading budget that may be 

allocated for such control period in 

accordance with such SIP revision. 

(iii) With regard to the TR NOX Ozone 

Season allowances that were allocated 

from the Indian country new unit setaside for such control period and that 

are not recorded, or that are deducted as 

an incorrect allocation, in accordance 

with paragraphs (c)(2) and (3) of this 

section for a recipient under paragraph 

(c)(1)(ii) of this paragraph, the 

Administrator will transfer such TR 

NOX Ozone Season allowances to the 

Indian country new unit set-aside for 

such control period. 

§ 97.512 TR NOX Ozone Season allowance 

allocations to new units. 

(a) For each control period in 2012 

and thereafter and for the TR NOX

Ozone Season units in each State, the 

Administrator will allocate TR NOX

Ozone Season allowances to the TR 

NOX Ozone Season units as follows: 

(1) The TR NOX Ozone Season 

allowances will be allocated to the 

following TR NOX Ozone Season units, 

except as provided in paragraph (a)(10) 

of this section: 

(i) TR NOX Ozone Season units that 

are not allocated an amount of TR NOX

Ozone Season allowances in the notice 

of data availability issued under 

§ 97.511(a)(1); 

(ii) TR NOX Ozone Season units 

whose allocation of an amount of TR 

NOX Ozone Season allowances for such 

control period in the notice of data 

availability issued under § 97.511(a)(1) 

is covered by § 97.511(c)(2) or (3); 

(iii) TR NOX Ozone Season units that 

are allocated an amount of TR NOX

Ozone Season allowances for such 

control period in the notice of data 

availability issued under § 97.511(a)(1), 

which allocation is terminated for such 

control period pursuant to 

§ 97.511(a)(2), and that operate during 

the control period immediately 

preceding such control period; or 

(iv) For purposes of paragraph (a)(9) 

of this section, TR NOX Ozone Season 

units under § 97.511(c)(1)(ii) whose 

allocation of an amount of TR NOX

Ozone Season allowances for such 

control period in the notice of data 

availability issued under 

§ 97.511(b)(1)(ii)(B) is covered by 

§ 97.511(c)(2) or (3). 

(2) The Administrator will establish a 

separate new unit set-aside for the State 

for each such control period. Each such 

new unit 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


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Ozone Season unit commences 

commercial operation; 

(iii) For a unit described in paragraph 

(a)(1)(ii) of this section, the first control 

period in which the TR NOX Ozone 

Season unit operates in the State after 

operating in another jurisdiction and for 

which the unit is not already allocated 

one or more TR NOX Ozone Season 

allowances; and 

(iv) For a unit described in paragraph 

(a)(1)(iii) of this section, the first control 

period after the control period in which 

the unit resumes operation. 

(4)(i) The allocation to each TR NOX

Ozone Season unit described in 

paragraph (a)(1)(i) through (iii) of this 

section and for each control period 

described in paragraph (a)(3) of this 

section will be an amount equal to the 

unit’s total tons of NOX emissions 

during the immediately preceding 

control period. 

(ii) The Administrator will adjust the 

allocation amount in paragraph (a)(4)(i) 

in accordance with paragraphs (a)(5) 

through (7) and (12) of this section. 

(5) The Administrator will calculate 

the sum of the TR NOX Ozone Season 

allowances determined for all such TR 

NOX Ozone Season units under 

paragraph (a)(4)(i) of this section in the 

State for such control period. 

(6) If the amount of TR NOX Ozone 

Season allowances in the new unit setaside for the State for such control 

period is greater than or equal to the 

sum under paragraph (a)(5) of this 

section, then the Administrator will 

allocate the amount of TR NOX 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 setaside for the State for such control 

period is less than the sum under 

paragraph (a)(5) of this section, then the 

Administrator will allocate to each such 

TR NOX Ozone Season unit the amount 

of the TR NOX Ozone Season 

allowances determined under paragraph 

(a)(4)(i) of this section for the unit, 

multiplied by the amount of TR NOX

Ozone Season allowances in the new 

unit set-aside for such control period, 

divided by the sum under paragraph 

(a)(5) of this section, and rounded to the 

nearest allowance. 

(8) The Administrator will notify the 

public, through the promulgation of the 

notices of data availability described in 

§ 97.511(b)(1)(i) and (ii), of the amount 

of TR NOX Ozone Season allowances 

allocated under paragraphs (a)(2) 

through (7) and (12) of this section for 

such control period to each TR NOX

Ozone Season unit eligible for such 

allocation. 

(9) If, after completion of the 

procedures under paragraphs (a)(5) 

through (8) of this section for such 

control period, any unallocated TR NOX

Ozone Season allowances remain in the 

new unit set-aside for the State for such 

control period, the Administrator will 

allocate such TR NOX Ozone Season 

allowances as follows— 

(i) The Administrator will determine, 

for each unit described in paragraph 

(a)(1) of this section that commenced 

commercial operation during the period 

starting May 1 of the year before the 

year of such control period and ending 

August 31 of year of such control 

period, the positive difference (if any) 

between the unit’s emissions during 

such control period and the amount of 

TR NOX Ozone Season allowances 

referenced in the notice of data 

availability required under 

§ 97.511(b)(1)(ii) for the unit for such 

control period; 

(ii) The Administrator will determine 

the sum of the positive differences 

determined under paragraph (a)(9)(i) of 

this section; 

(iii) If the amount of unallocated TR 

NOX Ozone Season allowances 

remaining in the new unit set-aside for 

the State for such control period is 

greater than or equal to the sum 

determined under paragraph (a)(9)(ii) of 

this section, then the Administrator will 

allocate the amount of TR NOX Ozone 

Season allowances determined for each 

such TR NOX Ozone Season unit under 

paragraph (a)(9)(i) of this section; and 

(iv) If the amount of unallocated TR 

NOX Ozone Season allowances 

remaining in the new unit set-aside for 

the State for such control period is less 

than the sum under paragraph (a)(9)(ii) 

of this section, then the Administrator 

will allocate to each such TR NOX

Ozone Season unit the amount of the TR 

NOX Ozone Season allowances 

determined under paragraph (a)(9)(i) of 

this section for the unit, multiplied by 

the amount of unallocated TR NOX

Ozone Season allowances remaining in 

the new unit set-aside for such control 

period, divided by the sum under 

paragraph (a)(9)(ii) of this section, and 

rounded to the nearest allowance. 

(10) If, after completion of the 

procedures under paragraphs (a)(9) and 

(12) of this section for such control 

period, any unallocated TR NOX Ozone 

Season allowances remain in the new 

unit set-aside for the State for such 

control period, the Administrator will 

allocate to each TR NOX Ozone Season 

unit that is in the State, is allocated an 

amount of TR NOX Ozone Season 

allowances in the notice of data 

availability issued under § 97.511(a)(1), 

and continues to be allocated TR NOX

Ozone Season allowances for such 

control period in accordance with 

§ 97.511(a)(2), an amount of TR NOX

Ozone Season allowances equal to the 

following: the total amount of such 

remaining unallocated TR NOX Ozone 

Season allowances in such new unit setaside, multiplied by the unit’s allocation 

under § 97.511(a) for such control 

period, divided by the remainder of the 

amount of tons in the applicable State 

NOX Ozone Season trading budget 

minus the sum of the amounts of tons 

in such new unit set-aside and the 

Indian country new unit set-aside for 

the State for such control period, and 

rounded to the nearest allowance. 

(11) The Administrator will notify the 

public, through the promulgation of the 

notices of data availability described in 

§ 97.511(b)(1)(iii), (iv), and (v), of the 

amount of TR NOX Ozone Season 

allowances allocated under paragraphs 

(a)(9), (10), and (12) of this section for 

such control period to each TR NOX

Ozone Season unit eligible for such 

allocation. 

(12)(i) Notwithstanding the 

requirements of paragraphs (a)(2) 

through (11) of this section, if the 

calculations of allocations of a new unit 

set-aside for a control period in a given 

year under paragraph (a)(7) of this 

section, paragraphs (a)(6) and (9)(iv) of 

this section, or paragraphs (a)(6), (9)(iii), 

and (10) of this section would otherwise 

result in total allocations of such new 

unit set-aside exceeding the total 

amount of such new unit set-aside, then 

the Administrator will adjust the results 

of the calculations under paragraph 

(a)(7), (9)(iv), or (10) of this section, as 

applicable, as follows. The 

Administrator will list the TR NOX

Ozone Season units in descending order 

based on the amount of such units’ 

allocations under paragraph (a)(7), 

(9)(iv), or (10) of this section, as 

applicable, and, in cases of equal 

allocation amounts, in alphabetical 

order of the relevant source’s name and 

numerical order of the relevant unit’s 

identification number, and will reduce 

each unit’s allocation under paragraph 

(a)(7), (9)(iv), or (10) of this section, as 

applicable, by one TR NOX Ozone 

Season allowance (but not below zero) 

in the order in which the units are listed 

and will repeat this reduction process as 

necessary, until the total allocations of 

such new unit set-aside equal the total 

amount of such new unit set-aside. 

(ii) Notwithstanding the requirements 

of paragraphs (a)(10) and (11) of this 

section, if the calculations of allocations 

of a new unit set-aside for a control 

period in a given year under paragraphs 

(a)(6), (9)(iii), and (10) of this section 

would otherwise result in a total 


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allocations of such new unit set-aside 

less than the total amount of such new 

unit set-aside, then the Administrator 

will adjust the results of the calculations 

under paragraph (a)(10) of this section, 

as follows. The Administrator will list 

the TR NOX Ozone Season units in 

descending order based on the amount 

of such units’ allocations under 

paragraph (a)(10) of this section and, in 

cases of equal allocation amounts, in 

alphabetical order of the relevant 

source’s name and numerical order of 

the relevant unit’s identification 

number, and will increase each unit’s 

allocation under paragraph (a)(10) of 

this section by one TR NOX Ozone 

Season allowance in the order in which 

the units are listed and will repeat this 

increase process as necessary, until the 

total allocations of such new unit setaside equal the total amount of such 

new unit set-aside. 

(b) For each control period in 2012 

and thereafter and for the TR NOX

Ozone Season units located in Indian 

country within the borders of each 

State, the Administrator will allocate TR 

NOX Ozone Season allowances to the 

TR NOX Ozone Season units as follows: 

(1) The TR NOX Ozone Season 

allowances will be allocated to the 

following TR NOX Ozone Season units, 

except as provided in paragraph (b)(10) 

of this section: 

(i) TR NOX Ozone Season units that 

are not allocated an amount of TR NOX

Ozone Season allowances in the notice 

of data availability issued under 

§ 97.511(a)(1); or 

(ii) For purposes of paragraph (b)(9) of 

this section, TR NOX Ozone Season 

units under § 97.511(c)(1)(ii) whose 

allocation of an amount of TR NOX

Ozone Season allowances for such 

control period in the notice of data 

availability issued under 

§ 97.511(b)(2)(ii)(B) is covered by 

§ 97.511(c)(2) or (3). 

(2) The Administrator will establish a 

separate Indian country new unit setaside for the State for each such control 

period. Each such Indian country new 

unit set-aside will be allocated TR NOX

Ozone Season allowances in an amount 

equal to the applicable amount of tons 

of NOX emissions as set forth in 

§ 97.510(a) and will be allocated 

additional TR NOX Ozone Season 

allowances (if any) in accordance with 

§ 97.511(c)(5). 

(3) The Administrator will determine, 

for each TR NOX Ozone Season unit 

described in paragraph (b)(1) of this 

section, an allocation of TR NOX Ozone 

Season allowances for the later of the 

following control periods and for each 

subsequent control period: 

(i) The control period in 2012; and 

(ii) The first control period after the 

control period in which the TR NOX

Ozone Season unit commences 

commercial operation. 

(4)(i) The allocation to each TR NOX

Ozone Season unit described in 

paragraph (b)(1)(i) of this section and for 

each control period described in 

paragraph (b)(3) of this section will be 

an amount equal to the unit’s total tons 

of NOX emissions during the 

immediately preceding control period. 

(ii) The Administrator will adjust the 

allocation amount in paragraph (b)(4)(i) 

in accordance with paragraphs (b)(5) 

through (7) and (12) of this section. 

(5) The Administrator will calculate 

the sum of the TR NOX Ozone Season 

allowances determined for all such TR 

NOX Ozone Season units under 

paragraph (b)(4)(i) of this section in 

Indian country within the borders of the 

State for such control period. 

(6) If the amount of TR NOX Ozone 

Season allowances in the Indian country 

new unit set-aside for the State for such 

control period is greater than or equal to 

the sum under paragraph (b)(5) of this 

section, then the Administrator will 

allocate the amount of TR NOX Ozone 

Season allowances determined for each 

such TR NOX Ozone Season unit under 

paragraph (b)(4)(i) of this section. 

(7) If the amount of TR NOX Ozone 

Season allowances in the Indian country 

new unit set-aside for the State for such 

control period is less than the sum 

under paragraph (b)(5) of this section, 

then the Administrator will allocate to 

each such TR NOX Ozone Season unit 

the amount of the TR NOX Ozone 

Season allowances determined under 

paragraph (b)(4)(i) of this section for the 

unit, multiplied by the amount of TR 

NOX Ozone Season allowances in the 

Indian country new unit set-aside for 

such control period, divided by the sum 

under paragraph (b)(5) of this section, 

and rounded to the nearest allowance. 

(8) The Administrator will notify the 

public, through the promulgation of the 

notices of data availability described in 

§ 97.511(b)(2)(i) and (ii), of the amount 

of TR NOX Ozone Season allowances 

allocated under paragraphs (b)(2) 

through (7) and (12) of this section for 

such control period to each TR NOX

Ozone Season unit eligible for such 

allocation. 

(9) If, after completion of the 

procedures under paragraphs (b)(5) 

through (8) of this section for such 

control period, any unallocated TR NOX

Ozone Season allowances remain in the 

Indian country new unit set-aside for 

the State for such control period, the 

Administrator will allocate such TR 

NOX Ozone Season allowances as 

follows— 

(i) The Administrator will determine, 

for each unit described in paragraph 

(b)(1) of this section that commenced 

commercial operation during the period 

starting May 1 of the year before the 

year of such control period and ending 

August 31 of year of such control 

period, the positive difference (if any) 

between the unit’s emissions during 

such control period and the amount of 

TR NOX Ozone Season allowances 

referenced in the notice of data 

availability required under 

§ 97.511(b)(2)(ii) for the unit for such 

control period; 

(ii) The Administrator will determine 

the sum of the positive differences 

determined under paragraph (b)(9)(i) of 

this section; 

(iii) If the amount of unallocated TR 

NOX Ozone Season allowances 

remaining in the Indian country new 

unit set-aside for the State for such 

control period is greater than or equal to 

the sum determined under paragraph 

(b)(9)(ii) of this section, then the 

Administrator will allocate the amount 

of TR NOX Ozone Season allowances 

determined for each such TR NOX

Ozone Season unit under paragraph 

(b)(9)(i) of this section; and 

(iv) If the amount of unallocated TR 

NOX Ozone Season allowances 

remaining in the Indian country new 

unit set-aside for the State for such 

control period is less than the sum 

under paragraph (b)(9)(ii) of this section, 

then the Administrator will allocate to 

each such TR NOX Ozone Season unit 

the amount of the TR NOX Ozone 

Season allowances determined under 

paragraph (b)(9)(i) of this section for the 

unit, multiplied by the amount of 

unallocated TR NOX Ozone Season 

allowances remaining in the Indian 

country new unit set-aside for such 

control period, divided by the sum 

under paragraph (b)(9)(ii) of this section, 

and rounded to the nearest allowance. 

(10) If, after completion of the 

procedures under paragraphs (b)(9) and 

(12) of this section for such control 

period, any unallocated TR NOX Ozone 

Season allowances remain in the Indian 

country new unit set-aside for the State 

for such control period, the 

Administrator will: 

(i) Transfer such unallocated TR NOX

Ozone Season allowances to the new 

unit set-aside for the State for such 

control period; or 

(ii) If the State has a SIP revision 

approved under § 52.38(b)(4) or (5) 

covering such control period, include 

such unallocated TR NOX Ozone Season 

allowances in the portion of the State 

NOX Ozone Season trading budget that 

may be allocated for such control period 

in accordance with such SIP revision. 


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(11) The Administrator will notify the 

public, through the promulgation of the 

notices of data availability described in 

§ 97.511(b)(2)(iii), (iv), and (v), of the 

amount of TR NOX Ozone Season 

allowances allocated under paragraphs 

(b)(9), (10), and (12) of this section for 

such control period to each TR NOX

Ozone Season unit eligible for such 

allocation. 

(12)(i) Notwithstanding the 

requirements of paragraphs (b)(2) 

through (11) of this section, if the 

calculations of allocations of an Indian 

country new unit set-aside for a control 

period in a given year under paragraph 

(b)(7) of this section, paragraphs (b)(6) 

and (9)(iv) of this section, or paragraphs 

(b)(6), (9)(iii), and (10) of this section 

would otherwise result in total 

allocations of such Indian country new 

unit set-aside exceeding the total 

amount of such Indian country new unit 

set-aside, then the Administrator will 

adjust the results of the calculations 

under paragraph (b)(7), (9)(iv), or (10) of 

this section, as applicable, as follows. 

The Administrator will list the TR NOX

Ozone Season units in descending order 

based on the amount of such units’ 

allocations under paragraph (b)(7), 

(9)(iv), or (10) of this section, as 

applicable, and, in cases of equal 

allocation amounts, in alphabetical 

order of the relevant source’s name and 

numerical order of the relevant unit’s 

identification number, and will reduce 

each unit’s allocation under paragraph 

(b)(7), (9)(iv), or (10) of this section, as 

applicable, by one TR NOX Ozone 

Season allowance (but not below zero) 

in the order in which the units are listed 

and will repeat this reduction process as 

necessary, until the total allocations of 

such Indian country new unit set-aside 

equal the total amount of such Indian 

country new unit set-aside. 

(ii) Notwithstanding the requirements 

of paragraphs (b)(10) and (11) of this 

section, if the calculations of allocations 

of an Indian country new unit set-aside 

for a control period in a given year 

under paragraphs (b)(6), (9)(iii), and (10) 

of this section would otherwise result in 

a total allocations of such Indian 

country new unit set-aside less than the 

total amount of such Indian country 

new unit set-aside, then the 

Administrator will adjust the results of 

the calculations under paragraph (b)(10) 

of this section, as follows. The 

Administrator will list the TR NOX

Ozone Season units in descending order 

based on the amount of such units’ 

allocations under paragraph (b)(10) of 

this section and, in cases of equal 

allocation amounts, in alphabetical 

order of the relevant source’s name and 

numerical order of the relevant unit’s 

identification number, and will increase 

each unit’s allocation under paragraph 

(b)(10) of this section by one TR NOX

Ozone Season allowance in the order in 

which the units are listed and will 

repeat this increase process as 

necessary, until the total allocations of 

such Indian country new unit set-aside 

equal the total amount of such Indian 

country new unit set-aside. 

§ 97.513 Authorization of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.515, 

each TR NOX Ozone Season source, 

including all TR NOX Ozone Season 

units at the source, shall have one and 

only one designated representative, with 

regard to all matters under the TR NOX

Ozone Season Trading Program. 

(1) The designated representative 

shall be selected by an agreement 

binding on the owners and operators of 

the source and all TR NOX Ozone 

Season units at the source and shall act 

in accordance with the certification 

statement in § 97.516(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.516: 

(i) The designated representative shall 

be authorized and shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each owner and operator of the source 

and each TR NOX Ozone Season unit at 

the source in all matters pertaining to 

the TR NOX Ozone Season Trading 

Program, notwithstanding any 

agreement between the designated 

representative and such owners and 

operators; and 

(ii) The owners and operators of the 

source and each TR NOX Ozone Season 

unit at the source shall be bound by any 

decision or order issued to the 

designated representative by the 

Administrator regarding the source or 

any such unit. 

(b) Except as provided under § 97.515, 

each TR NOX Ozone Season source may 

have one and only one alternate 

designated representative, who may act 

on behalf of the designated 

representative. The agreement by which 

the alternate designated representative 

is selected shall include a procedure for 

authorizing the alternate designated 

representative to act in lieu of the 

designated representative. 

(1) The alternate designated 

representative shall be selected by an 

agreement binding on the owners and 

operators of the source and all TR NOX

Ozone Season units at the source and 

shall act in accordance with the 

certification statement in 

§ 97.516(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.516, 

(i) The alternate designated 

representative shall be authorized; 

(ii) Any representation, action, 

inaction, or submission by the alternate 

designated representative shall be 

deemed to be a representation, action, 

inaction, or submission by the 

designated representative; and 

(iii) The owners and operators of the 

source and each TR NOX Ozone Season 

unit at the source shall be bound by any 

decision or order issued to the alternate 

designated representative by the 

Administrator regarding the source or 

any such unit. 

(c) Except in this section, § 97.502, 

and §§ 97.514 through 97.518, whenever 

the term ‘‘designated representative’’ (as 

distinguished from the term ‘‘common 

designated representative’’) is used in 

this subpart, the term shall be construed 

to include the designated representative 

or any alternate designated 

representative. 

§ 97.514 Responsibilities of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.518 

concerning delegation of authority to 

make submissions, each submission 

under the TR NOX Ozone Season 

Trading Program shall be made, signed, 

and certified by the designated 

representative or alternate designated 

representative for each TR NOX Ozone 

Season source and TR NOX Ozone 

Season unit for which the submission is 

made. Each such submission shall 

include the following certification 

statement by the designated 

representative or alternate designated 

representative: ‘‘I am authorized to 

make this submission on behalf of the 

owners and operators of the source or 

units for which the submission is made. 

I certify under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(b) The Administrator will accept or 

act on a submission made for a TR NOX

Ozone Season source or a TR NOX

Ozone Season unit only if the 


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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 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. 

(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. 

(a) A complete certificate of 

representation for a designated 

representative or an alternate designated 

representative shall include the 

following elements in a format 

prescribed by the Administrator: 

(1) Identification of the TR NOX

Ozone Season source, and each TR NOX

Ozone Season unit at the source, for 

which the certificate of representation is 

submitted, including source name, 

source category and NAICS code (or, in 

the absence of a NAICS code, an 

equivalent code), State, plant code, 

county, latitude and longitude, unit 

identification number and type, 

identification number and nameplate 

capacity (in MWe, rounded to the 

nearest tenth) of each generator served 

by each such unit, actual or projected 

date of commencement of commercial 

operation, and a statement of whether 

such source is located in Indian 

Country. If a projected date of 

commencement of commercial 

operation is provided, the actual date of 

commencement of commercial 

operation shall be provided when such 

information becomes available. 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the designated representative and any 

alternate designated representative. 

(3) A list of the owners and operators 

of the TR NOX Ozone Season source and 

of each TR NOX Ozone Season unit at 

the source. 

(4) The following certification 

statements by the designated 

representative and any alternate 

designated representative— 

(i) ‘‘I certify that I was selected as the 

designated representative or alternate 

designated representative, as applicable, 

by an agreement binding on the owners 

and operators of the source and each TR 

NOX Ozone Season unit at the source.’’ 

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the TR 

NOX Ozone Season Trading Program on 

behalf of the owners and operators of 

the source and of each TR NOX Ozone 

Season unit at the source and that each 

such owner and operator shall be fully 

bound by my representations, actions, 

inactions, or submissions and by any 

decision or order issued to me by the 

Administrator regarding the source or 

unit.’’ 

(iii) ‘‘Where there are multiple 

holders of a legal or equitable title to, or 

a leasehold interest in, a TR NOX Ozone 

Season unit, or where a utility or 

industrial customer purchases power 

from a TR NOX Ozone Season unit 

under a life-of-the-unit, firm power 

contractual arrangement, I certify that: I 

have given a written notice of my 

selection as the ‘designated 

representative’ or ‘alternate designated 

representative’, as applicable, and of the 

agreement by which I was 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. 


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(b) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the certificate of 

representation shall not be submitted to 

the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

§ 97.517 Objections concerning 

designated representative and alternate 

designated representative. 

(a) Once a complete certificate of 

representation under § 97.516 has been 

submitted and received, the 

Administrator will rely on the certificate 

of representation unless and until a 

superseding complete certificate of 

representation under § 97.516 is 

received by the Administrator. 

(b) Except as provided in paragraph 

(a) of this section, no objection or other 

communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission, of a 

designated representative or alternate 

designated representative shall affect 

any representation, action, inaction, or 

submission of the designated 

representative or alternate designated 

representative or the finality of any 

decision or order by the Administrator 

under the TR NOX Ozone Season 

Trading Program. 

(c) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of any designated 

representative or alternate designated 

representative, including private legal 

disputes concerning the proceeds of TR 

NOX Ozone Season allowance transfers. 

§ 97.518 Delegation by designated 

representative and alternate designated 

representative. 

(a) A designated representative may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(b) An alternate designated 

representative may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(c) In order to delegate authority to a 

natural person to make an electronic 

submission to the Administrator in 

accordance with paragraph (a) or (b) of 

this section, the designated 

representative or alternate designated 

representative, as appropriate, must 

submit to the Administrator a notice of 

delegation, in a format prescribed by the 

Administrator, that includes the 

following elements: 

(1) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of such 

designated representative or alternate 

designated representative; 

(2) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of each 

such natural person (referred to in this 

section as an ‘‘agent’’); 

(3) For each such natural person, a list 

of the type or types of electronic 

submissions under paragraph (a) or (b) 

of this section for which authority is 

delegated to him or her; and 

(4) The following certification 

statements by such designated 

representative or alternate designated 

representative: 

(i) ‘‘I agree that any electronic 

submission to the Administrator that is 

made by an agent identified in this 

notice of delegation and of a type listed 

for such agent in this notice of 

delegation and that is made when I am 

a designated representative or alternate 

designated representative, as 

appropriate, and before this notice of 

delegation is superseded by another 

notice of delegation under 40 CFR 

97.518(d) shall be deemed to be an 

electronic submission by me.’’ 

(ii) ‘‘Until this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 97.518(d), I 

agree to maintain an e-mail account and 

to notify the Administrator immediately 

of any change in my e-mail address 

unless all delegation of authority by me 

under 40 CFR 97.518 is terminated.’’. 

(d) A notice of delegation submitted 

under paragraph (c) of this section shall 

be effective, with regard to the 

designated representative or alternate 

designated representative identified in 

such notice, upon receipt of such notice 

by the Administrator and until receipt 

by the Administrator of a superseding 

notice of delegation submitted by such 

designated representative or alternate 

designated representative, as 

appropriate. The superseding notice of 

delegation may replace any previously 

identified agent, add a new agent, or 

eliminate entirely any delegation of 

authority. 

(e) Any electronic submission covered 

by the certification in paragraph (c)(4)(i) 

of this section and made in accordance 

with a notice of delegation effective 

under paragraph (d) of this section shall 

be deemed to be an electronic 

submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

§ 97.519 [Reserved] 

§ 97.520 Establishment of compliance 

accounts, assurance accounts, and general 

accounts. 

(a) Compliance accounts. Upon 

receipt of a complete certificate of 

representation under § 97.516, the 

Administrator will establish a 

compliance account for the TR NOX

Ozone Season source for which the 

certificate of representation was 

submitted, unless the source already has 

a compliance account. The designated 

representative and any alternate 

designated representative of the source 

shall be the authorized account 

representative and the alternate 

authorized account representative 

respectively of the compliance account. 

(b) Assurance accounts. The 

Administrator will establish assurance 

accounts for certain owners and 

operators and States in accordance with 

§ 97.525(b)(3). 

(c) General accounts. (1) Application 

for general account. (i) Any person may 

apply to open a general account, for the 

purpose of holding and transferring TR 

NOX Ozone Season allowances, by 

submitting to the Administrator a 

complete application for a general 

account. Such application shall 

designate one and only one authorized 

account representative and may 

designate one and only one alternate 

authorized account representative who 

may act on behalf of the authorized 

account representative. 

(A) The authorized account 

representative and alternate authorized 

account representative shall be selected 

by an agreement binding on the persons 

who have an ownership interest with 

respect to TR NOX Ozone Season 

allowances held in the general account. 

(B) The agreement by which the 

alternate authorized account 

representative is selected shall include 

a procedure for authorizing the alternate 

authorized account representative to act 

in lieu of the authorized account 

representative. 

(ii) A complete application for a 

general account shall include the 

following elements in a format 

prescribed by the Administrator: 

(A) Name, mailing address, e-mail 

address (if any), telephone number, and 

facsimile transmission number (if any) 

of the authorized account representative 

and any alternate authorized account 

representative; 

(B) An identifying name for the 

general account; 

(C) A list of all persons subject to a 

binding agreement for the authorized 

account representative and any alternate 

authorized account representative to 


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represent their ownership interest with 

respect to the TR NOX Ozone Season 

allowances held in the general account; 

(D) The following certification 

statement by the authorized account 

representative and any alternate 

authorized account representative: ‘‘I 

certify that I was selected as the 

authorized account representative or the 

alternate authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to TR NOX Ozone Season 

allowances held in the general account. 

I certify that I have all the necessary 

authority to carry out my duties and 

responsibilities under the TR NOX

Ozone Season Trading Program on 

behalf of such persons and that each 

such person shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any decision or 

order issued to me by the Administrator 

regarding the general account.’’ 

(E) The signature of the authorized 

account representative and any alternate 

authorized account representative and 

the dates signed. 

(iii) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the application for a 

general account shall not be submitted 

to the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

(2) Authorization of authorized 

account representative and alternate 

authorized account representative. (i) 

Upon receipt by the Administrator of a 

complete application for a general 

account under paragraph (b)(1) of this 

section, the Administrator will establish 

a general account for the person or 

persons for whom the application is 

submitted, and upon and after such 

receipt by the Administrator: 

(A) The authorized account 

representative of the general account 

shall be authorized and shall represent 

and, by his or her representations, 

actions, inactions, or submissions, 

legally bind each person who has an 

ownership interest with respect to TR 

NOX 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 alternate authorized account 

representative for the persons having an 

ownership interest with respect to TR 

NOX Ozone Season allowances held in 

the general account. Each such 

submission shall include the following 

certification statement by the authorized 

account representative or any alternate 

authorized account representative: ‘‘I 

am authorized to make this submission 

on behalf of the persons having an 

ownership interest with respect to the 

TR NOX Ozone Season allowances held 

in the general account. I certify under 

penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(iii) Except in this section, whenever 

the term ‘‘authorized account 

representative’’ is used in this subpart, 

the term shall be construed to include 

the authorized account representative or 

any alternate authorized account 

representative. 

(3) Changing authorized account 

representative and alternate authorized 

account representative; changes in 

persons with ownership interest. (i) The 

authorized account representative of a 

general account may be changed at any 

time upon receipt by the Administrator 

of a superseding complete application 

for a general account under paragraph 

(c)(1) of this section. Notwithstanding 

any such change, all representations, 

actions, inactions, and submissions by 

the previous authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

authorized account representative and 

the persons with an ownership interest 

with respect to the TR NOX Ozone 

Season allowances in the general 

account. 

(ii) The alternate authorized account 

representative of a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (c)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous alternate authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

alternate authorized account 

representative, the authorized account 

representative, and the persons with an 

ownership interest with respect to the 

TR NOX Ozone Season allowances in 

the general account. 

(iii)(A) In the event a person having 

an ownership interest with respect to 

TR NOX Ozone Season allowances in 

the general account is not included in 

the list of such persons in the 

application for a general account, such 

person shall be deemed to be subject to 

and bound by the application for a 

general account, the representation, 

actions, inactions, and submissions of 

the authorized account representative 

and any alternate authorized account 

representative of the account, and the 

decisions and orders of the 

Administrator, as if the person were 

included in such list. 

(B) Within 30 days after any change 

in the persons having an ownership 

interest with respect to NOX Ozone 

Season allowances in the general 

account, including the addition or 

removal of a person, the authorized 

account representative or any alternate 

authorized account representative shall 

submit a revision to the application for 

a general account amending the list of 

persons having an ownership interest 

with respect to the TR NOX Ozone 

Season allowances in the general 

account to include the change. 

(4) Objections concerning authorized 

account representative and alternate 

authorized account representative. (i) 

Once a complete application for a 

general account under paragraph (c)(1) 

of this section has been submitted and 

received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section is received by the 

Administrator. 


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(ii) Except as provided in paragraph 

(c)(4)(i) of this section, no objection or 

other communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission of the 

authorized account representative or 

any alternate authorized account 

representative of a general account shall 

affect any representation, action, 

inaction, or submission of the 

authorized account representative or 

any alternate authorized account 

representative or the finality of any 

decision or order by the Administrator 

under the TR NOX Ozone Season 

Trading Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account, including private legal 

disputes concerning the proceeds of TR 

NOX Ozone Season allowance transfers. 

(5) Delegation by authorized account 

representative and alternate authorized 

account representative. (i) An 

authorized account representative of a 

general account may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(ii) An alternate authorized account 

representative of a general account may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(iii) In order to delegate authority to 

a natural person to make an electronic 

submission to the Administrator in 

accordance with paragraph (c)(5)(i) or 

(ii) of this section, the authorized 

account representative or alternate 

authorized account representative, as 

appropriate, must submit to the 

Administrator a notice of delegation, in 

a format prescribed by the 

Administrator, that includes the 

following elements: 

(A) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of such authorized account 

representative or alternate authorized 

account representative; 

(B) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of each such natural person (referred to 

in this section as an ‘‘agent’’); 

(C) For each such natural person, a 

list of the type or types of electronic 

submissions under paragraph (c)(5)(i) or 

(ii) of this section for which authority is 

delegated to him or her; 

(D) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘I agree that any 

electronic submission to the 

Administrator that is made by an agent 

identified in this notice of delegation 

and of a type listed for such agent in 

this notice of delegation and that is 

made when I am an authorized account 

representative or alternate authorized 

representative, as appropriate, and 

before this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 97.520(c)(5)(iv) 

shall be deemed to be an electronic 

submission by me.’’; and 

(E) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘Until this 

notice of delegation is superseded by 

another notice of delegation under 40 

CFR 97.520(c)(5)(iv), I agree to maintain 

an 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) Closing a general account. (i) The 

authorized account representative or 

alternate authorized account 

representative of a general account may 

submit to the Administrator a request to 

close the account. Such request shall 

include a correctly submitted TR NOX

Ozone Season allowance transfer under 

§ 97.522 for any TR NOX Ozone Season 

allowances in the account to one or 

more other Allowance Management 

System accounts. 

(ii) If a general account has no TR 

NOX Ozone Season allowance transfers 

to or from the account for a 12-month 

period or longer and does not contain 

any TR NOX Ozone Season allowances, 

the Administrator may notify the 

authorized account representative for 

the account that the account will be 

closed after 30 days after the notice is 

sent. The account will be closed after 

the 30-day period unless, before the end 

of the 30-day period, the Administrator 

receives a correctly submitted TR NOX

Ozone Season allowance transfer under 

§ 97.522 to the account or a statement 

submitted by the authorized account 

representative or alternate authorized 

account representative demonstrating to 

the satisfaction of the Administrator 

good cause as to why the account 

should not be closed. 

(d) Account identification. The 

Administrator will assign a unique 

identifying number to each account 

established under paragraph (a), (b), or 

(c) of this section. 

(e) Responsibilities of authorized 

account representative and alternate 

authorized account representative. After 

the establishment of a compliance 

account or general account, the 

Administrator will accept or act on a 

submission pertaining to the account, 

including, but not limited to, 

submissions concerning the deduction 

or transfer of TR NOX Ozone Season 

allowances in the account, only if the 

submission has been made, signed, and 

certified in accordance with §§ 97.514(a) 

and 97.518 or paragraphs (c)(2)(ii) and 

(c)(5) of this section. 

§ 97.521 Recordation of TR NOX Ozone 

Season allowance allocations and auction 

results. 

(a) By November 7, 2011, 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 November 7, 2011, the 

Administrator will record in each TR 

NOX Ozone Season source’s compliance 

account the TR NOX Ozone Season 

allowances allocated to the TR NOX

Ozone Season units at the source in 

accordance with § 97.511(a) for the 

control period in 2013, unless the State 

in which the source is located notifies 

the Administrator in writing by October 

17, 2011 of the State’s intent to submit 

to the Administrator a complete SIP 

revision by April 1, 2012 meeting the 


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requirements of § 52.38(b)(3)(i) through 

(iv) of this chapter. 

(1) If, by April 1, 2012, the State does 

not submit to the Administrator such 

complete SIP revision, the 

Administrator will record by April 15, 

2012 in each TR NOX Ozone Season 

source’s compliance account the TR 

NOX Ozone Season allowances allocated 

to the TR NOX Ozone Season units at 

the source in accordance with 

§ 97.511(a) for the control period in 

2013. 

(2) If the State submits to the 

Administrator by April 1, 2012, and the 

Administrator approves by October 1, 

2012, such complete SIP revision, the 

Administrator will record by October 1, 

2012 in each TR NOX Ozone Season 

source’s compliance account the TR 

NOX Ozone Season allowances allocated 

to the TR NOX Ozone Season units at 

the source as provided in such 

approved, complete SIP revision for the 

control period in 2013. 

(3) If the State submits to the 

Administrator by April 1, 2012, and the 

Administrator does not approve by 

October 1, 2012, such complete SIP 

revision, the Administrator will record 

by October 1, 2012 in each TR NOX

Ozone Season source’s compliance 

account the TR NOX Ozone Season 

allowances allocated to the TR NOX

Ozone Season units at the source in 

accordance with § 97.511(a) for the 

control period in 2013. 

(c) By July 1, 2013, the Administrator 

will record in each TR NOX Ozone 

Season source’s compliance account the 

TR NOX Ozone Season allowances 

allocated to the TR NOX Ozone Season 

units at the source, or in each 

appropriate Allowance Management 

System account the TR NOX Ozone 

Season allowances auctioned to TR NOX

Ozone Season units, in accordance with 

§ 97.511(a), or with a SIP revision 

approved under § 52.38(b)(4) or (5) of 

this chapter, for the control period in 

2014 and 2015. 

(d) By July 1, 2014, the Administrator 

will record in each TR NOX Ozone 

Season source’s compliance account the 

TR NOX Ozone Season allowances 

allocated to the TR NOX Ozone Season 

units at the source, or in each 

appropriate Allowance Management 

System account the TR NOX Ozone 

Season allowances auctioned to TR NOX

Ozone Season units, in accordance with 

§ 97.511(a), or with a SIP revision 

approved under § 52.38(b)(4) or (5) of 

this chapter, for the control period in 

2016 and 2017. 

(e) By July 1, 2015, the Administrator 

will record in each TR NOX Ozone 

Season source’s compliance account the 

TR NOX Ozone Season allowances 

allocated to the TR NOX Ozone Season 

units at the source, or in each 

appropriate Allowance Management 

System account the TR NOX Ozone 

Season allowances auctioned to TR NOX

Ozone Season units, in accordance with 

§ 97.511(a), or with a SIP revision 

approved under § 52.38(b)(4) or (5) of 

this chapter, for the control period in 

2018 and 2019. 

(f) By July 1, 2016 and July 1 of each 

year thereafter, the Administrator will 

record in each TR NOX Ozone Season 

source’s compliance account the TR 

NOX Ozone Season allowances allocated 

to the TR NOX Ozone Season units at 

the source, or in each appropriate 

Allowance Management System account 

the TR NOX Ozone Season allowances 

auctioned to TR NOX Ozone Season 

units, in accordance with § 97.511(a), or 

with a SIP revision approved under 

§ 52.38(b)(4) or (5) of this chapter, for 

the control period in the fourth year 

after the year of the applicable 

recordation deadline under this 

paragraph. 

(g) By August 1, 2012 and August 1 

of each year thereafter, the 

Administrator will record in each TR 

NOX Ozone Season source’s compliance 

account the TR NOX Ozone Season 

allowances allocated to the TR NOX

Ozone Season units at the source, or in 

each appropriate Allowance 

Management System account the TR 

NOX Ozone Season allowances 

auctioned to TR NOX Ozone Season 

units, in accordance with § 97.512(a)(2) 

through (8) and (12), or with a SIP 

revision approved under § 52.38(b)(4) or 

(5) of this chapter, for the control period 

in the year of the applicable recordation 

deadline under this paragraph. 

(h) By August 1, 2012 and August 1 

of each year thereafter, the 

Administrator will record in each TR 

NOX Ozone Season source’s compliance 

account the TR NOX Ozone Season 

allowances allocated to the TR NOX

Ozone Season units at the source in 

accordance with § 97.512(b)(2) through 

(8) and (12) for the control period in the 

year of the applicable recordation 

deadline under this paragraph. 

(i) By November 15, 2012 and 

November 15 of each year thereafter, the 

Administrator will record in each TR 

NOX Ozone Season source’s compliance 

account the TR NOX Ozone Season 

allowances allocated to the TR NOX

Ozone Season units at the source in 

accordance with § 97.512(a)(9) through 

(12), for the control period in the year 

of the applicable recordation deadline 

under this paragraph. 

(j) By the date on which any 

allocation or auction results, other than 

an allocation or auction results 

described in paragraphs (a) through (i) 

of this section, of TR NOX Ozone Season 

allowances to a recipient is made by or 

are submitted to the Administrator in 

accordance with § 97.511 or § 97.512 or 

with a SIP revision approved under 

§ 52.38(b)(4) or (5) of this chapter, the 

Administrator will record such 

allocation or auction results in the 

appropriate Allowance Management 

System account. 

(k) When recording the allocation or 

auction of TR NOX Ozone Season 

allowances to a TR NOX Ozone Season 

unit or other entity in an Allowance 

Management System account, the 

Administrator will assign each TR NOX

Ozone Season allowance a unique 

identification number that will include 

digits identifying the year of the control 

period for which the TR NOX Ozone 

Season allowance is allocated or 

auctioned. 

§ 97.522 Submission of TR NOX Ozone 

Season allowance transfers. 

(a) An authorized account 

representative seeking recordation of a 

TR NOX Ozone Season allowance 

transfer shall submit the transfer to the 

Administrator. 

(b) A TR NOX Ozone Season 

allowance transfer shall be correctly 

submitted if: 

(1) The transfer includes the following 

elements, in a format prescribed by the 

Administrator: 

(i) The account numbers established 

by the Administrator for both the 

transferor and transferee accounts; 

(ii) The serial number of each TR NOX

Ozone Season allowance that is in the 

transferor account and is to be 

transferred; and 

(iii) The name and signature of the 

authorized account representative of the 

transferor account and the date signed; 

and 

(2) When the Administrator attempts 

to record the transfer, the transferor 

account includes each TR NOX Ozone 

Season allowance identified by serial 

number in the transfer. 

§ 97.523 Recordation of TR NOX Ozone 

Season allowance transfers. 

(a) Within 5 business days (except as 

provided in paragraph (b) of this 

section) of receiving a TR NOX Ozone 

Season allowance transfer that is 

correctly submitted under § 97.522, the 

Administrator will record a TR NOX

Ozone Season allowance transfer by 

moving each TR NOX Ozone Season 

allowance from the transferor account to 

the transferee account as specified in 

the transfer. 

(b) A TR NOX Ozone Season 

allowance transfer to or from a 


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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 section, the Administrator 

will notify the authorized account 

representatives of both the transferor 

and transferee accounts. 

(e) Within 10 business days of receipt 

of a TR NOX Ozone Season allowance 

transfer that is not correctly submitted 

under § 97.522, the Administrator will 

notify the authorized account 

representatives of both accounts subject 

to the transfer of: 

(1) A decision not to record the 

transfer, and 

(2) The reasons for such nonrecordation. 

§ 97.524 Compliance with TR NOX Ozone 

Season emissions limitation. 

(a) Availability for deduction for 

compliance. TR NOX Ozone Season 

allowances are available to be deducted 

for compliance with a source’s TR NOX

Ozone Season emissions limitation for a 

control period in a given year only if the 

TR NOX Ozone Season allowances: 

(1) Were allocated for 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 

§ 97.523, of TR NOX Ozone Season 

allowance transfers submitted by the 

allowance transfer deadline for a control 

period in a given year, the 

Administrator will deduct from each 

source’s compliance account TR NOX

Ozone Season allowances available 

under paragraph (a) of this section in 

order to determine whether the source 

meets the TR NOX Ozone Season 

emissions limitation for such control 

period, as follows: 

(1) Until the amount of TR NOX

Ozone Season allowances deducted 

equals the number of tons of total NOX

emissions from all TR NOX Ozone 

Season units at the source for such 

control period; or 

(2) If there are insufficient TR NOX

Ozone Season allowances to complete 

the deductions in paragraph (b)(1) of 

this section, until no more TR NOX

Ozone Season allowances available 

under paragraph (a) of this section 

remain in the compliance account. 

(c)(1) Identification of TR NOX Ozone 

Season allowances by serial number. 

The authorized account representative 

for a source’s compliance account may 

request that specific TR NOX Ozone 

Season allowances, identified by serial 

number, in the compliance account be 

deducted for emissions or excess 

emissions for a control period in a given 

year in accordance with paragraph (b) or 

(d) of this section. In order to be 

complete, such request shall be 

submitted to the Administrator by the 

allowance transfer deadline for such 

control 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 source 

has excess emissions, the Administrator 

will deduct from the source’s 

compliance account an amount of TR 

NOX Ozone Season allowances, 

allocated for a control period in a prior 

year or the control period in the year of 

the excess emissions or in the 

immediately following year, equal to 

two times the number of tons of the 

source’s excess emissions. 

(e) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraphs (b) and (d) of this section. 

§ 97.525 Compliance with TR NOX Ozone 

Season assurance provisions. 

(a) Availability for deduction. TR NOX

Ozone Season allowances are available 

to be deducted for compliance with the 

TR NOX Ozone Season assurance 

provisions for a control period in a 

given year by the owners and operators 

of a group of one or more TR NOX

Ozone Season sources and units in a 

State (and Indian country within the 

borders of such State) only if the TR 

NOX Ozone Season allowances: 

(1) Were allocated for a control period 

in a prior year or the control period in 

the given year or in the immediately 

following year; and 

(2) Are held in the assurance account, 

established by the Administrator for 

such owners and operators of such 

group of TR NOX Ozone Season sources 

and units in such State (and Indian 

country within the borders of such 

State) under paragraph (b)(3) of this 

section, as of the deadline established in 

paragraph (b)(4) of this section. 

(b) Deductions for compliance. The 

Administrator will deduct TR NOX

Ozone Season allowances available 

under paragraph (a) of this section for 

compliance with the TR NOX Ozone 

Season assurance provisions for a State 

for a control period in a given year in 

accordance with the following 

procedures: 

(1) By June 1, 2013 and June 1 of each 

year thereafter, the Administrator will: 

(i) Calculate, for each State (and 

Indian country within the borders of 

such State), the total NOX emissions 

from all TR NOX Ozone Season units at 

TR NOX Ozone Season sources in the 

State (and Indian country within the 

borders of such State) during the control 

period in the year before the year of this 

calculation deadline and the amount, if 

any, by which such total NOX emissions 

exceed the State assurance level as 

described in § 97.506(c)(2)(iii); and 

(ii) Promulgate a notice of data 

availability of the results of the 

calculations required in paragraph 

(b)(1)(i) of this section, including 

separate calculations of the NOX

emissions from each TR NOX Ozone 

Season source. 

(2) For each notice of data availability 

required in paragraph (b)(1)(ii) of this 

section and for any State (and Indian 

country within the borders of such 

State) identified in such notice as 

having TR NOX Ozone Season units 

with total NOX emissions exceeding the 

State assurance level for a control 


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period in a given year, as described in 

§ 97.506(c)(2)(iii): 

(i) By July 1 immediately after the 

promulgation of such notice, the 

designated representative of each TR 

NOX Ozone Season source in each such 

State (and Indian country within the 

borders of such State) shall submit a 

statement, in a format prescribed by the 

Administrator, providing for each TR 

NOX Ozone Season unit (if any) at the 

source that operates during, but is not 

allocated an amount of TR NOX Ozone 

Season allowances for, such control 

period, the unit’s allowable NOX

emission rate for such control period 

and, if such rate is expressed in lb per 

mmBtu, the unit’s heat rate. 

(ii) By August 1 immediately after the 

promulgation of such notice, the 

Administrator will calculate, for each 

such State (and Indian country within 

the borders of such State) and such 

control period and each common 

designated representative for such 

control period for a group of one or 

more TR NOX Ozone Season sources 

and units in the State (and Indian 

country within the borders of such 

State), the common designated 

representative’s share of the total NOX

emissions from all TR NOX Ozone 

Season units at TR NOX Ozone Season 

sources in the State (and Indian country 

within the borders of such State), the 

common designated representative’s 

assurance level, and the amount (if any) 

of TR NOX Ozone Season allowances 

that the owners and operators of such 

group of sources and units must hold in 

accordance with the calculation formula 

in § 97.506(c)(2)(i) and will promulgate 

a notice of data availability of the results 

of these calculations. 

(iii) The Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

by the notice of data availability 

required in paragraph (b)(2)(ii) of this 

section and the calculations referenced 

by the relevant notice of data 

availability required in paragraph 

(b)(1)(i) of this section. 

(A) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations referenced in 

the relevant notice required under 

paragraph (b)(1)(ii) of this section and 

referenced in the notice required under 

paragraph (b)(2)(ii) of this section are in 

accordance with § 97.506(c)(2)(iii), 

§§ 97.506(b) and 97.530 through 97.535, 

the definitions of ‘‘common designated 

representative’’, ‘‘common designated 

representative’s assurance level’’, and 

‘‘common designated representative’s 

share’’ in § 97.502, and the calculation 

formula in § 97.506(c)(2)(i). 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(iii)(A) of this section. By October 

1 immediately after the promulgation of 

such notice, the Administrator will 

promulgate a notice of data availability 

of any adjustments that the 

Administrator determines to be 

necessary and the reasons for accepting 

or rejecting any objections submitted in 

accordance with paragraph (b)(2)(iii)(A) 

of this section. 

(3) For any State (and Indian country 

within the borders of such State) 

referenced in each notice of data 

availability required in paragraph 

(b)(2)(iii)(B) of this section as having TR 

NOX Ozone Season units with total NOX

emissions exceeding the State assurance 

level for a control period in a given year, 

the Administrator will establish one 

assurance account for each set of owners 

and operators referenced, in the notice 

of data availability required under 

paragraph (b)(2)(iii)(B) of this section, as 

all of the owners and operators of a 

group of TR NOX Ozone Season sources 

and units in the State (and Indian 

country within the borders of such 

State) having a common designated 

representative for such control period 

and as being required to hold TR NOX

Ozone Season allowances. 

(4)(i) As of midnight of November 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(2)(iii)(B) of this section, 

the owners and operators described in 

paragraph (b)(3) of this section shall 

hold in the assurance account 

established for the them and for the 

appropriate TR NOX Ozone Season 

sources, TR NOX Ozone Season units, 

and State (and Indian country within 

the borders of such State) under 

paragraph (b)(3) of this section a total 

amount of TR NOX Ozone Season 

allowances, available for deduction 

under paragraph (a) of this section, 

equal to the amount such owners and 

operators are required to hold with 

regard to such sources, units and State 

(and Indian country within the borders 

of such State) as calculated by the 

Administrator and referenced in such 

notice. 

(ii) Notwithstanding the allowanceholding deadline specified in paragraph 

(b)(4)(i) of this section, if November 1 is 

not a business day, then such 

allowance-holding deadline shall be 

midnight of the first business day 

thereafter. 

(5) After November 1 (or the date 

described in paragraph (b)(4)(ii) of this 

section) immediately after the 

promulgation of each notice of data 

availability required in paragraph 

(b)(2)(iii)(B) of this section and after the 

recordation, in accordance with 

§ 97.523, of TR NOX Ozone Season 

allowance transfers submitted by 

midnight of such date, the 

Administrator will determine whether 

the owners and operators described in 

paragraph (b)(3) of this section hold, in 

the assurance account for the 

appropriate TR NOX Ozone Season 

sources, TR NOX Ozone Season units, 

and State (and Indian country within 

the borders of such State) established 

under paragraph (b)(3) of this section, 

the amount of TR NOX Ozone Season 

allowances available under paragraph 

(a) of this section that the owners and 

operators are required to hold with 

regard to such sources, units, and State 

(and Indian country within the borders 

of such State) as calculated by the 

Administrator and referenced in the 

notice required in paragraph 

(b)(2)(iii)(B) of this section. 

(6) Notwithstanding any other 

provision of this subpart and any 

revision, made by or submitted to the 

Administrator after the promulgation of 

the notice of data availability required 

in paragraph (b)(2)(iii)(B) of this section 

for a control period in a given year, of 

any data used in making the 

calculations referenced in such notice, 

the amounts of TR NOX Ozone Season 

allowances that the owners and 

operators are required to hold in 

accordance with § 97.506(c)(2)(i) for 

such control period shall continue to be 

such amounts as calculated by the 

Administrator and referenced in such 

notice required in paragraph 

(b)(2)(iii)(B) of this section, except as 

follows: 

(i) If any such data are revised by the 

Administrator as a result of a decision 

in or settlement of litigation concerning 

such data on appeal under part 78 of 

this chapter of such notice, or on appeal 

under section 307 of the Clean Air Act 

of a decision rendered under part 78 of 

this chapter on appeal of such notice, 

then the Administrator will use the data 

as so revised to recalculate the amounts 

of TR NOX Ozone Season allowances 

that owners and operators are required 

to hold in accordance with the 

calculation formula in § 97.506(c)(2)(i) 

for such control period with regard to 

the TR NOX Ozone Season sources, TR 

NOX Ozone Season units, and State (and 

Indian country within the borders of 

such State) involved, provided that such 

litigation under part 78 of this chapter, 

or the proceeding under part 78 of this 

chapter that resulted in the decision 

appealed in such litigation under 

section 307 of the Clean Air Act, was 

initiated no later than 30 days after 


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promulgation of such notice required in 

paragraph (b)(2)(iii)(B) of this section. 

(ii) If any such data are revised by the 

owners and operators of a TR NOX

Ozone Season source and TR NOX

Ozone Season unit whose designated 

representative submitted such data 

under paragraph (b)(2)(i) of this section, 

as a result of a decision in or settlement 

of litigation concerning such 

submission, then the Administrator will 

use the data as so revised to recalculate 

the amounts of TR NOX Ozone Season 

allowances that owners and operators 

are required to hold in accordance with 

the calculation formula in 

§ 97.506(c)(2)(i) for such control period 

with regard to the TR NOX Ozone 

Season sources, TR NOX Ozone Season 

units, and State (and Indian country 

within the borders of such State) 

involved, provided that such litigation 

was initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(2)(iii)(B) of this section. 

(iii) If the revised data are used to 

recalculate, in accordance with 

paragraphs (b)(6)(i) and (ii) of this 

section, the amount of TR NOX Ozone 

Season allowances that the owners and 

operators are required to hold for such 

control period with regard to the TR 

NOX Ozone Season sources, TR NOX

Ozone Season units, and State (and 

Indian country within the borders of 

such State) involved— 

(A) Where the amount of TR NOX

Ozone Season allowances that the 

owners and operators are required to 

hold increases as a result of the use of 

all such revised data, the Administrator 

will establish a new, reasonable 

deadline on which the owners and 

operators shall hold the additional 

amount of TR NOX Ozone Season 

allowances in the assurance account 

established by the Administrator for the 

appropriate TR NOX Ozone Season 

sources, TR NOX Ozone Season units, 

and State (and Indian country within 

the borders of such State) under 

paragraph (b)(3) of this section. The 

owners’ and operators’ failure to hold 

such additional amount, as required, 

before the new deadline shall not be a 

violation of the Clean Air Act. The 

owners’ and operators’ failure to hold 

such additional amount, as required, as 

of the new deadline shall be a violation 

of the Clean Air Act. Each TR NOX

Ozone Season allowance that the 

owners and operators fail to hold as 

required as of the new deadline, and 

each day in such control period, shall be 

a separate violation of the Clean Air Act. 

(B) For the owners and operators for 

which the amount of TR NOX Ozone 

Season allowances required to be held 

decreases as a result of the use of all 

such revised data, the Administrator 

will record, in all accounts from which 

TR NOX Ozone Season allowances were 

transferred by such owners and 

operators for such control period to the 

assurance account established by the 

Administrator for the appropriate at TR 

NOX Ozone Season sources, TR NOX

Ozone Season units, and State (and 

Indian country within the borders of 

such State) under paragraph (b)(3) of 

this section, a total amount of the TR 

NOX Ozone Season allowances held in 

such assurance account equal to the 

amount of the decrease. If TR NOX

Ozone Season allowances were 

transferred to such assurance account 

from more than one account, the 

amount of TR NOX Ozone Season 

allowances recorded in each such 

transferor account will be in proportion 

to the percentage of the total amount of 

TR NOX Ozone Season allowances 

transferred to such assurance account 

for such control period from such 

transferor account. 

(C) Each TR NOX Ozone Season 

allowance held under paragraph 

(b)(6)(iii)(A) of this section as a result of 

recalculation of requirements under the 

TR NOX Ozone Season assurance 

provisions for such control period must 

be a TR NOX Ozone Season allowance 

allocated for a control period in a year 

before or the year immediately 

following, or in the same year as, the 

year of such control period. 

§ 97.526 Banking. 

(a) A TR NOX Ozone Season 

allowance may be banked for future use 

or transfer in a compliance account or 

a general account in accordance with 

paragraph (b) of this section. 

(b) Any TR NOX Ozone Season 

allowance that is held in a compliance 

account or a general account will 

remain in such account unless and until 

the TR NOX Ozone Season allowance is 

deducted or transferred under 

§ 97.511(c), § 97.523, § 97.524, § 97.525, 

§ 97.527, or § 97.528. 

§ 97.527 Account error. 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any 

Allowance Management System 

account. Within 10 business days of 

making such correction, the 

Administrator will notify the authorized 

account representative for the account. 

§ 97.528 Administrator’s action on 

submissions. 

(a) The Administrator may review and 

conduct independent audits concerning 

any submission under the TR NOX

Ozone Season Trading Program and 

make appropriate adjustments of the 

information in the submission. 

(b) The Administrator may deduct TR 

NOX Ozone Season allowances from or 

transfer TR NOX Ozone Season 

allowances to a compliance account or 

an assurance account, based on the 

information in a submission, as adjusted 

under paragraph (a)(1) of this section, 

and record such deductions and 

transfers. 

§ 97.529 [Reserved] 

§ 97.530 General monitoring, 

recordkeeping, and reporting requirements. 

The owners and operators, and to the 

extent applicable, the designated 

representative, of a TR NOX Ozone 

Season unit, shall comply with the 

monitoring, recordkeeping, and 

reporting requirements as provided in 

this subpart and subpart H of part 75 of 

this chapter. For purposes of applying 

such requirements, the definitions in 

§ 97.502 and in § 72.2 of this chapter 

shall apply, the terms ‘‘affected unit,’’ 

‘‘designated representative,’’ and 

‘‘continuous emission monitoring 

system’’ (or ‘‘CEMS’’) in part 75 of this 

chapter shall be deemed to refer to the 

terms ‘‘TR NOX Ozone Season unit,’’ 

‘‘designated representative,’’ and 

‘‘continuous emission monitoring 

system’’ (or ‘‘CEMS’’) respectively as 

defined in § 97.502, and the term 

‘‘newly affected unit’’ shall be deemed 

to mean ‘‘newly affected TR NOX Ozone 

Season unit’’. The owner or operator of 

a unit that is not a TR NOX Ozone 

Season unit but that is monitored under 

§ 75.72(b)(2)(ii) of this chapter shall 

comply with the same monitoring, 

recordkeeping, and reporting 

requirements as a TR NOX Ozone 

Season unit. 

(a) Requirements for installation, 

certification, and data accounting. The 

owner or operator of each TR NOX

Ozone Season unit shall: 

(1) Install all monitoring systems 

required under this subpart for 

monitoring NOX mass emissions and 

individual unit heat input (including all 

systems required to monitor NOX

emission rate, NOX concentration, stack 

gas moisture content, stack gas flow 

rate, CO2 or O2 concentration, and fuel 

flow rate, as applicable, in accordance 

with §§ 75.71 and 75.72 of this chapter); 

(2) Successfully complete all 

certification tests required under 

§ 97.531 and meet all other 

requirements of this subpart and part 75 

of this chapter applicable to the 

monitoring systems under paragraph 

(a)(1) of this section; and 

(3) Record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section. 


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(b) Compliance deadlines. Except as 

provided in paragraph (e) of this 

section, the owner or operator shall 

meet the monitoring system certification 

and other requirements of paragraphs 

(a)(1) and (2) of this section on or before 

the following dates and shall record, 

report, and quality-assure the data from 

the monitoring systems under paragraph 

(a)(1) of this section on and after the 

following dates. 

(1) For the owner or operator of a TR 

NOX Ozone Season unit that 

commences commercial operation 

before July 1, 2011, May 1, 2012. 

(2) For the owner or operator of a TR 

NOX Ozone Season unit that 

commences commercial operation on or 

after July 1, 2011 and that reports on an 

annual basis under § 97.534(d), by the 

later of the following: 

(i) 180 calendar days after the date on 

which the unit commences commercial 

operation; or 

(ii) May 1, 2012. 

(3) For the owner or operator of a TR 

NOX Ozone Season unit that 

commences commercial operation on or 

after July 1, 2011 and that reports on a 

control period basis under 

§ 97.534(d)(2)(ii), by the following date: 

(i) 180 calendar days after the date on 

which the unit commences commercial 

operation; or 

(ii) If the compliance date under 

paragraph (b)(3)(i) of this section is not 

during a control period, May 1 

immediately after the compliance date 

under paragraph (b)(3)(i) of this section. 

(4) The owner or operator of a TR 

NOX Ozone Season unit for which 

construction of a new stack or flue or 

installation of add-on NOX emission 

controls is completed after the 

applicable deadline under paragraph 

(b)(1), (2), or (3) of this section shall 

meet the requirements of §§ 75.4(e)(1) 

through (e)(4) of this chapter, except 

that: 

(i) Such requirements shall apply to 

the monitoring systems required under 

§ 97.530 through § 97.535, rather than 

the monitoring systems required under 

part 75 of this chapter; 

(ii) NOX emission rate, NOX

concentration, stack gas moisture 

content, stack gas volumetric flow rate, 

and O2 or CO2 concentration data shall 

be determined and reported, rather than 

the data listed in § 75.4(e)(2) of this 

chapter; and 

(iii) Any petition for another 

procedure under § 75.4(e)(2) of this 

chapter shall be submitted under 

§ 97.535, rather than § 75.66. 

(c) Reporting data. The owner or 

operator of a TR NOX Ozone Season unit 

that does not meet the applicable 

compliance date set forth in paragraph 

(b) of this section for any monitoring 

system under paragraph (a)(1) of this 

section shall, for each such monitoring 

system, determine, record, and report 

maximum potential (or, as appropriate, 

minimum potential) values for NOX

concentration, NOX emission rate, stack 

gas flow rate, stack gas moisture 

content, fuel flow rate, and any other 

parameters required to determine NOX

mass emissions and heat input in 

accordance with § 75.31(b)(2) or (c)(3) of 

this chapter, section 2.4 of appendix D 

to part 75 of this chapter, or section 2.5 

of appendix E to part 75 of this chapter, 

as applicable. 

(d) Prohibitions. (1) No owner or 

operator of a TR NOX Ozone Season unit 

shall use any alternative monitoring 

system, alternative reference method, or 

any other alternative to any requirement 

of this subpart without having obtained 

prior written approval in accordance 

with § 97.535. 

(2) No owner or operator of a TR NOX

Ozone Season unit shall operate the unit 

so as to discharge, or allow to be 

discharged, NOX to the atmosphere 

without accounting for all such NOX in 

accordance with the applicable 

provisions of this subpart and part 75 of 

this chapter. 

(3) No owner or operator of a TR NOX

Ozone Season unit shall disrupt the 

continuous emission monitoring system, 

any portion thereof, or any other 

approved emission monitoring method, 

and thereby avoid monitoring and 

recording NOX mass discharged into the 

atmosphere or heat input, except for 

periods of recertification or periods 

when calibration, quality assurance 

testing, or maintenance is performed in 

accordance with the applicable 

provisions of this subpart and part 75 of 

this chapter. 

(4) No owner or operator of a TR NOX

Ozone Season unit shall retire or 

permanently discontinue use of the 

continuous emission monitoring system, 

any component thereof, or any other 

approved monitoring system under this 

subpart, except under any one of the 

following circumstances: 

(i) During the period that the unit is 

covered by an exemption under § 97.505 

that is in effect; 

(ii) The owner or operator is 

monitoring emissions from the unit with 

another certified monitoring system 

approved, in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter, by the 

Administrator for use at that unit that 

provides emission data for the same 

pollutant or parameter as the retired or 

discontinued monitoring system; or 

(iii) The designated representative 

submits notification of the date of 

certification testing of a replacement 

monitoring system for the retired or 

discontinued monitoring system in 

accordance with § 97.531(d)(3)(i). 

(e) Long-term cold storage. The owner 

or operator of a TR NOX Ozone Season 

unit is subject to the applicable 

provisions of § 75.4(d) of this chapter 

concerning units in long-term cold 

storage. 

§ 97.531 Initial monitoring system 

certification and recertification procedures. 

(a) The owner or operator of a TR NOX

Ozone Season unit shall be exempt from 

the initial certification requirements of 

this section for a monitoring system 

under § 97.530(a)(1) if the following 

conditions are met: 

(1) The monitoring system has been 

previously certified in accordance with 

part 75 of this chapter; and 

(2) The applicable quality-assurance 

and quality-control requirements of 

§ 75.21 of this chapter and appendices 

B, D, and E to part 75 of this chapter are 

fully met for the certified monitoring 

system described in paragraph (a)(1) of 

this section. 

(b) The recertification provisions of 

this section shall apply to a monitoring 

system under § 97.530(a)(1) that is 

exempt from initial certification 

requirements under paragraph (a) of this 

section. 

(c) If the Administrator has previously 

approved a petition under § 75.17(a) or 

(b) of this chapter for apportioning the 

NOX emission rate measured in a 

common stack or a petition under 

§ 75.66 of this chapter for an alternative 

to a requirement in § 75.12 or § 75.17 of 

this chapter, the designated 

representative shall resubmit the 

petition to the Administrator under 

§ 97.535 to determine whether the 

approval applies under the TR NOX

Ozone Season Trading Program. 

(d) Except as provided in paragraph 

(a) of this section, the owner or operator 

of a TR NOX Ozone Season unit shall 

comply with the following initial 

certification and recertification 

procedures for a continuous monitoring 

system (i.e., a continuous emission 

monitoring system and an excepted 

monitoring system under appendices D 

and E to part 75 of this chapter) under 

§ 97.530(a)(1). The owner or operator of 

a unit that qualifies to use the low mass 

emissions excepted monitoring 

methodology under § 75.19 of this 

chapter or that qualifies to use an 

alternative monitoring system under 

subpart E of part 75 of this chapter shall 

comply with the procedures in 

paragraph (e) or (f) of this section 

respectively. 


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(1) Requirements for initial 

certification. The owner or operator 

shall ensure that each continuous 

monitoring system under § 97.530(a)(1) 

(including the automated data 

acquisition and handling system) 

successfully completes all of the initial 

certification testing required under 

§ 75.20 of this chapter by the applicable 

deadline in § 97.530(b). In addition, 

whenever the owner or operator installs 

a monitoring system to meet the 

requirements of this subpart in a 

location where no such monitoring 

system was previously installed, initial 

certification in accordance with § 75.20 

of this chapter is required. 

(2) Requirements for recertification. 

Whenever the owner or operator makes 

a replacement, modification, or change 

in any certified continuous emission 

monitoring system under § 97.530(a)(1) 

that may significantly affect the ability 

of the system to accurately measure or 

record NOX mass emissions or heat 

input rate or to meet the qualityassurance and quality-control 

requirements of § 75.21 of this chapter 

or appendix B to part 75 of this chapter, 

the owner or operator shall recertify the 

monitoring system in accordance with 

§ 75.20(b) of this chapter. Furthermore, 

whenever the owner or operator makes 

a replacement, modification, or change 

to the flue gas handling system or the 

unit’s operation that may significantly 

change the stack flow or concentration 

profile, the owner or operator shall 

recertify each continuous emission 

monitoring system whose accuracy is 

potentially affected by the change, in 

accordance with § 75.20(b) of this 

chapter. Examples of changes to a 

continuous emission monitoring system 

that require recertification include: 

replacement of the analyzer, complete 

replacement of an existing continuous 

emission monitoring system, or change 

in location or orientation of the 

sampling probe or site. Any fuel 

flowmeter system, and any excepted 

NOX monitoring system under appendix 

E to part 75 of this chapter, under 

§ 97.530(a)(1) are subject to the 

recertification requirements in 

§ 75.20(g)(6) of this chapter. 

(3) Approval process for initial 

certification and recertification. For 

initial certification of a continuous 

monitoring system under § 97.530(a)(1), 

paragraphs (d)(3)(i) through (v) of this 

section apply. For recertifications of 

such monitoring systems, paragraphs 

(d)(3)(i) through (iv) of this section and 

the procedures in §§ 75.20(b)(5) and 

(g)(7) of this chapter (in lieu of the 

procedures in paragraph (d)(3)(v) of this 

section) apply, provided that in 

applying paragraphs (d)(3)(i) through 

(iv) of this section, the words 

‘‘certification’’ and ‘‘initial certification’’ 

are replaced by the word 

‘‘recertification’’ and the word 

‘‘certified’’ is replaced by with the word 

‘‘recertified’’. 

(i) Notification of certification. The 

designated representative shall submit 

to the appropriate EPA Regional Office 

and the Administrator written notice of 

the dates of certification testing, in 

accordance with § 97.533. 

(ii) Certification application. The 

designated representative shall submit 

to the Administrator a certification 

application for each monitoring system. 

A complete certification application 

shall include the information specified 

in § 75.63 of this chapter. 

(iii) Provisional certification date. The 

provisional certification date for a 

monitoring system shall be determined 

in accordance with § 75.20(a)(3) of this 

chapter. A provisionally certified 

monitoring system may be used under 

the TR NOX Ozone Season Trading 

Program for a period not to exceed 120 

days after receipt by the Administrator 

of the complete certification application 

for the monitoring system under 

paragraph (d)(3)(ii) of this section. Data 

measured and recorded by the 

provisionally certified monitoring 

system, in accordance with the 

requirements of part 75 of this chapter, 

will be considered valid quality-assured 

data (retroactive to the date and time of 

provisional certification), provided that 

the Administrator does not invalidate 

the provisional certification by issuing a 

notice of disapproval within 120 days of 

the date of receipt of the complete 

certification application by the 

Administrator. 

(iv) Certification application approval 

process. The Administrator will issue a 

written notice of approval or 

disapproval of the certification 

application to the owner or operator 

within 120 days of receipt of the 

complete certification application under 

paragraph (d)(3)(ii) of this section. In the 

event the Administrator does not issue 

such a notice within such 120-day 

period, each monitoring system that 

meets the applicable performance 

requirements of part 75 of this chapter 

and is included in the certification 

application will be deemed certified for 

use under the TR NOX Ozone Season 

Trading Program. 

(A) Approval notice. If the 

certification application is complete and 

shows that each monitoring system 

meets the applicable performance 

requirements of part 75 of this chapter, 

then the Administrator will issue a 

written notice of approval of the 

certification application within 120 

days of receipt. 

(B) Incomplete application notice. If 

the certification application is not 

complete, then the Administrator will 

issue a written notice of incompleteness 

that sets a reasonable date by which the 

designated representative must submit 

the additional information required to 

complete the certification application. If 

the designated representative does not 

comply with the notice of 

incompleteness by the specified date, 

then the Administrator may issue a 

notice of disapproval under paragraph 

(d)(3)(iv)(C) of this section. 

(C) Disapproval notice. If the 

certification application shows that any 

monitoring system does not meet the 

performance requirements of part 75 of 

this chapter or if the certification 

application is incomplete and the 

requirement for disapproval under 

paragraph (d)(3)(iv)(B) of this section is 

met, then the Administrator will issue a 

written notice of disapproval of the 

certification application. Upon issuance 

of such notice of disapproval, the 

provisional certification is invalidated 

by the Administrator and the data 

measured and recorded by each 

uncertified monitoring system shall not 

be considered valid quality-assured data 

beginning with the date and hour of 

provisional certification (as defined 

under § 75.20(a)(3) of this chapter). 

(D) Audit decertification. The 

Administrator may issue a notice of 

disapproval of the certification status of 

a monitor in accordance with 

§ 97.532(b). 

(v) Procedures for loss of certification. 

If the Administrator issues a notice of 

disapproval of a certification 

application under paragraph 

(d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under 

paragraph (d)(3)(iv)(D) of this section, 

then: 

(A) The owner or operator shall 

substitute the following values, for each 

disapproved monitoring system, for 

each hour of unit operation during the 

period of invalid data specified under 

§ 75.20(a)(4)(iii), § 75.20(g)(7), or 

§ 75.21(e) of this chapter and continuing 

until the applicable date and hour 

specified under § 75.20(a)(5)(i) or (g)(7) 

of this chapter: 

(1) For a disapproved NOX emission 

rate (i.e., NOX-diluent) system, the 

maximum potential NOX emission rate, 

as defined in § 72.2 of this chapter. 

(2) For a disapproved NOX pollutant 

concentration monitor and disapproved 

flow monitor, respectively, the 

maximum potential concentration of 

NOX and the maximum potential flow 

rate, as defined in sections 2.1.2.1 and 


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2.1.4.1 of appendix A to part 75 of this 

chapter. 

(3) For a disapproved moisture 

monitoring system and disapproved 

diluent gas monitoring system, 

respectively, the minimum potential 

moisture percentage and either the 

maximum potential CO2 concentration 

or the minimum potential O2

concentration (as applicable), as defined 

in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 

appendix A to part 75 of this chapter. 

(4) For a disapproved fuel flowmeter 

system, the maximum potential fuel 

flow rate, as defined in section 2.4.2.1 

of appendix D to part 75 of this chapter. 

(5) For a disapproved excepted NOX

monitoring system under appendix E to 

part 75 of this chapter, the fuel-specific 

maximum potential NOX emission rate, 

as defined in § 72.2 of this chapter. 

(B) The designated representative 

shall submit a notification of 

certification retest dates and a new 

certification application in accordance 

with paragraphs (d)(3)(i) and (ii) of this 

section. 

(C) The owner or operator shall repeat 

all certification tests or other 

requirements that were failed by the 

monitoring system, as indicated in the 

Administrator’s notice of disapproval, 

no later than 30 unit operating days 

after the date of issuance of the notice 

of disapproval. 

(e) The owner or operator of a unit 

qualified to use the low mass emissions 

(LME) excepted methodology under 

§ 75.19 of this chapter shall meet the 

applicable certification and 

recertification requirements in 

§§ 75.19(a)(2) and 75.20(h) of this 

chapter. If the owner or operator of such 

a unit elects to certify a fuel flowmeter 

system for heat input determination, the 

owner or operator shall also meet the 

certification and recertification 

requirements in § 75.20(g) of this 

chapter. 

(f) The designated representative of 

each unit for which the owner or 

operator intends to use an alternative 

monitoring system approved by the 

Administrator under subpart E of part 

75 of this chapter shall comply with the 

applicable notification and application 

procedures of § 75.20(f) of this chapter. 

§ 97.532 Monitoring system out-of-control 

periods. 

(a) General provisions. Whenever any 

monitoring system fails to meet the 

quality-assurance and quality-control 

requirements or data validation 

requirements of part 75 of this chapter, 

data shall be substituted using the 

applicable missing data procedures in 

subpart D or subpart H of, or appendix 

D or appendix E to, part 75 of this 

chapter. 

(b) Audit decertification. Whenever 

both an audit of a monitoring system 

and a review of the initial certification 

or recertification application reveal that 

any monitoring system should not have 

been certified or recertified because it 

did not meet a particular performance 

specification or other requirement under 

§ 97.531 or the applicable provisions of 

part 75 of this chapter, both at the time 

of the initial certification or 

recertification application submission 

and at the time of the audit, the 

Administrator will issue a notice of 

disapproval of the certification status of 

such monitoring system. For the 

purposes of this paragraph, an audit 

shall be either a field audit or an audit 

of any information submitted to the 

Administrator or any 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 § 97.531 for each 

disapproved monitoring system. 

§ 97.533 Notifications concerning 

monitoring. 

The designated representative of a TR 

NOX Ozone Season unit shall submit 

written notice to the Administrator in 

accordance with § 75.61 of this chapter. 

§ 97.534 Recordkeeping and reporting. 

(a) General provisions. The designated 

representative shall comply with all 

recordkeeping and reporting 

requirements in paragraphs (b) through 

(e) of this section, the applicable 

recordkeeping and reporting 

requirements under § 75.73 of this 

chapter, and the requirements of 

§ 97.514(a). 

(b) Monitoring plans. The owner or 

operator of a TR NOX Ozone Season unit 

shall comply with requirements of 

§ 75.73(c) and (e) of this chapter. 

(c) Certification applications. The 

designated representative shall submit 

an application to the Administrator 

within 45 days after completing all 

initial certification or recertification 

tests required under § 97.531, including 

the information required under § 75.63 

of this chapter. 

(d) Quarterly reports. The designated 

representative shall submit quarterly 

reports, as follows: 

(1) If the TR NOX Ozone Season unit 

is subject to the Acid Rain Program or 

a TR NOX Annual emissions limitation 

or if the owner or operator of such unit 

chooses to report on an annual basis 

under this subpart, the designated 

representative shall meet the 

requirements of subpart H of part 75 of 

this chapter (concerning monitoring of 

NOX mass emissions) for such unit for 

the entire year and shall report the NOX

mass emissions data and heat input data 

for such unit, in an electronic quarterly 

report in a format prescribed by the 

Administrator, for each calendar quarter 

beginning with: 

(i) For a unit that commences 

commercial operation before July 1, 

2011, the calendar quarter covering May 

1, 2012 through June 30, 2012; or 

(ii) For a unit that commences 

commercial operation on or after July 1, 

2011, the calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 97.530(b), unless 

that quarter is the third or fourth quarter 

of 2011 or the first quarter of 2012, in 

which case reporting shall commence in 

the quarter covering May 1, 2012 

through June 30, 2012. 

(2) If the TR NOX Ozone Season unit 

is not subject to the Acid Rain Program 

or a TR NOX Annual emissions 

limitation, then the designated 

representative shall either: 

(i) Meet the requirements of subpart H 

of part 75 (concerning monitoring of 

NOX mass emissions) for such unit for 

the entire year and report the NOX mass 

emissions data and heat input data for 

such unit in accordance with paragraph 

(d)(1) of this section; or 

(ii) Meet the requirements of subpart 

H of part 75 for the control period 

(including the requirements in 

§ 75.74(c) of this chapter) and report 

NOX mass emissions data and heat 

input data (including the data described 

in § 75.74(c)(6) of this chapter) for such 

unit only for the control period of each 

year and report, in an electronic 

quarterly report in a format prescribed 

by the Administrator, for each calendar 

quarter beginning with: 

(A) For a unit that commences 

commercial operation before July 1, 

2011, the calendar quarter covering May 

1, 2012 through June 30, 2012; or 

(B) For a unit that commences 

commercial operation on or after July 1, 

2011, the calendar quarter 

corresponding to the earlier of the date 


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of provisional certification or the 

applicable deadline for initial 

certification under § 97.530(b), unless 

that date is not during a control period, 

in which case reporting shall commence 

in the quarter that includes May 1 

through June 30 of the first control 

period after such date. 

(3) The designated representative 

shall submit each quarterly report to the 

Administrator within 30 days after the 

end of the calendar quarter covered by 

the report. Quarterly reports shall be 

submitted in the manner specified in 

§ 75.73(f) of this chapter. 

(4) For TR NOX Ozone Season units 

that are also subject to the Acid Rain 

Program, TR NOX Annual Trading 

Program, TR SO2 Group 1 Trading 

Program, or TR SO2 Group 2 Trading 

Program, quarterly reports shall include 

the applicable data and information 

required by subparts F through H of part 

75 of this chapter as applicable, in 

addition to the NOX mass emission data, 

heat input data, and other information 

required by this subpart. 

(5) The Administrator may review and 

conduct independent audits of any 

quarterly report in order to determine 

whether the quarterly report meets the 

requirements of this subpart and part 75 

of this chapter, including the 

requirement to use substitute data. 

(i) The Administrator will notify the 

designated representative of any 

determination that the quarterly report 

fails to meet any such requirements and 

specify in such notification any 

corrections that the Administrator 

believes are necessary to make through 

resubmission of the quarterly report and 

a reasonable time period within which 

the designated representative must 

respond. Upon request by the 

designated representative, the 

Administrator may specify reasonable 

extensions of such time period. Within 

the time period (including any such 

extensions) specified by the 

Administrator, the designated 

representative shall resubmit the 

quarterly report with the corrections 

specified by the Administrator, except 

to the extent the designated 

representative provides information 

demonstrating that a specified 

correction is not necessary because the 

quarterly report already meets the 

requirements of this subpart and part 75 

of this chapter that are relevant to the 

specified correction. 

(6) Any resubmission of a quarterly 

report shall meet the requirements 

applicable to the submission of a 

quarterly report under this subpart and 

part 75 of this chapter, except for the 

deadline set forth in paragraph (d)(3) of 

this section. 

(e) Compliance certification. The 

designated representative shall submit 

to the Administrator a compliance 

certification (in a format prescribed by 

the Administrator) in support of each 

quarterly report based on reasonable 

inquiry of those persons with primary 

responsibility for ensuring that all of the 

unit’s emissions are correctly and fully 

monitored. The certification shall state 

that: 

(1) The monitoring data submitted 

were recorded in accordance with the 

applicable requirements of this subpart 

and part 75 of this chapter, including 

the quality assurance procedures and 

specifications; 

(2) For a unit with add-on NOX

emission controls and for all hours 

where NOX data are substituted in 

accordance with § 75.34(a)(1) of this 

chapter, the add-on emission controls 

were operating within the range of 

parameters listed in the quality 

assurance/quality control program 

under appendix B to part 75 of this 

chapter and the substitute data values 

do not systematically underestimate 

NOX emissions; and 

(3) For a unit that is reporting on a 

control period basis under paragraph 

(d)(2)(ii) of this section, the NOX

emission rate and NOX concentration 

values substituted for missing data 

under subpart D of part 75 of this 

chapter are calculated using only values 

from a control period and do not 

systematically underestimate NOX

emissions. 

§ 97.535 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

(a) The designated representative of a 

TR NOX Ozone Season unit may submit 

a petition under § 75.66 of this chapter 

to the Administrator, requesting 

approval to apply an alternative to any 

requirement of §§ 97.530 through 

97.534. 

(b) A petition submitted under 

paragraph (a) of this section shall 

include sufficient information for the 

evaluation of the petition, including, at 

a minimum, the following information: 

(i) Identification of each unit and 

source covered by the petition; 

(ii) A detailed explanation of why the 

proposed alternative is being suggested 

in lieu of the requirement; 

(iii) A description and diagram of any 

equipment and procedures used in the 

proposed alternative; 

(iv) A demonstration that the 

proposed alternative is consistent with 

the purposes of the requirement for 

which the alternative is proposed and 

with the purposes of this subpart and 

part 75 of this chapter and that any 

adverse effect of approving the 

alternative will be de minimis: and 

(v) Any other relevant information 

that the Administrator may require. 

(c) Use of an alternative to any 

requirement referenced in paragraph (a) 

of this section is in accordance with this 

subpart only to the extent that the 

petition is approved in writing by the 

Administrator and that such use is in 

accordance with such approval. 

76. Part 97 is amended by adding 

subpart CCCCC to read as follows: 

Subpart CCCCC—TR SO2 Group 1 

Trading Program 

Sec. 

97.601 Purpose. 

97.602 Definitions. 

97.603 Measurements, abbreviations, and 

acronyms. 

97.604 Applicability. 

97.605 Retired unit exemption. 

97.606 Standard requirements. 

97.607 Computation of time. 

97.608 Administrative appeal procedures. 

97.609 [Reserved] 

97.610 State SO2 Group 1 trading budgets, 

new unit set-asides, Indian country new 

unit set-asides and variability limits. 

97.611 Timing requirements for TR SO2

Group 1 allowance allocations. 

97.612 TR SO2 Group 1 allowance 

allocations to new units. 

97.613 Authorization of designated 

representative and alternate designated 

representative. 

97.614 Responsibilities of designated 

representative and alternate designated 

representative. 

97.615 Changing designated representative 

and alternate designated representative; 

changes in owners and operators. 

97.616 Certificate of representation. 

97.617 Objections concerning designated 

representative and alternate designated 

representative. 

97.618 Delegation by designated 

representative and alternate designated 

representative. 

97.619 [Reserved] 

97.620 Establishment of compliance 

accounts and general accounts. 

97.621 Recordation of TR SO2 Group 1 

allowance allocations. 

97.622 Submission of TR SO2 Group 1 

allowance transfers. 

97.623 Recordation of TR SO2 Group 1 

allowance transfers. 

97.624 Compliance with TR SO2 Group 1 

emissions limitation. 

97.625 Compliance with TR SO2 Group 1 

assurance provisions. 

97.626 Banking. 

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. 


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97.633 Notifications concerning 

monitoring. 

97.634 Recordkeeping and reporting. 

97.635 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

Subpart CCCCC—TR SO2 Group 1 

Trading Program 

§ 97.601 Purpose. 

This subpart sets forth the general, 

designated representative, allowance, 

and monitoring provisions for the 

Transport Rule (TR) SO2 Group 1 

Trading Program, under section 110 of 

the Clean Air Act and § 52.39 of this 

chapter, as a means of mitigating 

interstate transport of fine particulates 

and sulfur dioxide. 

§ 97.602 Definitions. 

The terms used in this subpart shall 

have the meanings set forth in this 

section as follows: 

Acid Rain Program means a multistate SO2 and NOX air pollution control 

and emission reduction program 

established by the Administrator under 

title IV of the Clean Air Act and parts 

72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Director of the Clean Air Markets 

Division (or its successor determined by 

the Administrator) of the United States 

Environmental Protection Agency, the 

Administrator’s duly authorized 

representative under this subpart. 

Allocate or allocation means, with 

regard to TR SO2 Group 1 allowances, 

the determination by the Administrator, 

State, or permitting authority, in 

accordance with this subpart and any 

SIP revision submitted by the State and 

approved by the Administrator under 

§ 52.39(d), (e), or (f) of this chapter, of 

the amount of such TR SO2 Group 1 

allowances to be initially credited, at no 

cost to the recipient, to: 

(1) A TR SO2 Group 1 unit; 

(2) A new unit set-aside; 

(3) An Indian country new unit setaside; or 

(4) An entity not listed in paragraphs 

(1) through (3) of this definition; 

(5) Provided that, if the 

Administrator, State, or permitting 

authority initially credits, to a TR SO2

Group 1 unit qualifying for an initial 

credit, a credit in the amount of zero TR 

SO2 Group 1 allowances, the TR SO2

Group 1 unit will be treated as being 

allocated an amount (i.e., zero) of TR 

SO2 Group 1 allowances. 

Allowable SO2 emission rate means, 

for a unit, the most stringent State or 

federal SO2 emission rate limit (in lb/ 

MWhr or, if in lb/mmBtu, converted to 

lb/MWhr by multiplying it by the unit’s 

heat rate in mmBtu/MWhr) that is 

applicable to the unit and covers the 

longest averaging period not exceeding 

one year. 

Allowance Management System 

means the system by which the 

Administrator records allocations, 

deductions, and transfers of TR SO2

Group 1 allowances under the TR SO2

Group 1 Trading Program. Such 

allowances are allocated, recorded, 

held, deducted, or transferred only as 

whole allowances. 

Allowance Management System 

account means an account in the 

Allowance Management System 

established by the Administrator for 

purposes of recording the allocation, 

holding, transfer, or deduction of TR 

SO2 Group 1 allowances. 

Allowance transfer deadline means, 

for a control period in a given year, 

midnight of March 1 (if it is a business 

day), or midnight of the first business 

day thereafter (if March 1 is not a 

business day), immediately after such 

control period and is the deadline by 

which a TR SO2 Group 1 allowance 

transfer must be submitted for 

recordation in a TR SO2 Group 1 

source’s compliance account in order to 

be available for use in complying with 

the source’s TR SO2 Group 1 emissions 

limitation for such control period in 

accordance with §§ 97.606 and 97.624. 

Alternate designated representative 

means, for a TR SO2 Group 1 source and 

each TR SO2 Group 1 unit at the source, 

the natural person who is authorized by 

the owners and operators of the source 

and all such units at the source, in 

accordance with this subpart, to act on 

behalf of the designated representative 

in matters pertaining to the TR SO2

Group 1 Trading Program. If the TR SO2

Group 1 source is also subject to the 

Acid Rain Program, TR NOX Annual 

Trading Program, or TR NOX Ozone 

Season Trading Program, then this 

natural person shall be the same natural 

person as the alternate designated 

representative, as defined in the 

respective program. 

Assurance account means an 

Allowance Management System 

account, established by the 

Administrator under § 97.625(b)(3) for 

certain owners and operators of a group 

of one or more TR SO2 Group 1 sources 

and units in a given State (and Indian 

country within the borders of such 

State), in which are held TR SO2 Group 

1 allowances available for use for a 

control period in a given year in 

complying with the TR SO2 Group 1 

assurance provisions in accordance with 

§§ 97.606 and 97.625. 

Authorized account representative 

means, for a general account, the natural 

person who is authorized, in accordance 

with this subpart, to transfer and 

otherwise dispose of TR SO2 Group 1 

allowances held in the general account 

and, for a TR SO2 Group 1 source’s 

compliance account, the designated 

representative of the source. 

Automated data acquisition and 

handling system or DAHS means the 

component of the continuous emission 

monitoring system, or other emissions 

monitoring system approved for use 

under this subpart, designed to interpret 

and convert individual output signals 

from pollutant concentration monitors, 

flow monitors, diluent gas monitors, 

and other component parts of the 

monitoring system to produce a 

continuous record of the measured 

parameters in the measurement units 

required by this subpart. 

Biomass means— 

(1) Any organic material grown for the 

purpose of being converted to energy; 

(2) Any organic byproduct of 

agriculture that can be converted into 

energy; or 

(3) Any material that can be converted 

into energy and is nonmerchantable for 

other purposes, that is segregated from 

other material that is nonmerchantable 

for other purposes, and that is; 

(i) A forest-related organic resource, 

including mill residues, precommercial 

thinnings, slash, brush, or byproduct 

from conversion of trees to 

merchantable material; or 

(ii) A wood material, including 

pallets, crates, dunnage, manufacturing 

and construction materials (other than 

pressure-treated, chemically-treated, or 

painted wood products), and landscape 

or right-of-way tree trimmings. 

Boiler means an enclosed fossil- or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Bottoming-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful thermal 

energy, where at least some of the reject 

heat from the useful thermal energy 

application or process is then used for 

electricity production. 

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 of 

the corporation in charge of a principal 

business function or any other person 

who performs similar policy- or 

decision-making functions for the 

corporation; 


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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 that 

is a topping-cycle unit or a bottomingcycle unit: 

(1) Operating as part of a cogeneration 

system; and 

(2) Producing on an annual average 

basis— 

(i) For a topping-cycle unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less than 42.5 percent 

of total energy input, 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 systemwide basis the requirement in paragraph 

(2)(i)(B) or (2)(ii) of this definition, the 

unit shall be deemed to meet such 

requirement during that 12-month 

period or calendar year. 

Combustion turbine means an 

enclosed device comprising: 

(1) If the device is simple cycle, a 

compressor, a combustor, and a turbine 

and in which the flue gas resulting from 

the combustion of fuel in the combustor 

passes through the turbine, rotating the 

turbine; and 

(2) If the device is combined cycle, 

the equipment described in paragraph 

(1) of this definition and any associated 

duct burner, heat recovery steam 

generator, and steam turbine. 

Commence commercial operation 

means, with regard to a unit: 

(1) To have begun to produce steam, 

gas, or other heated medium used to 

generate electricity for sale or use, 

including test generation, except as 

provided in § 97.605. 

(i) For a unit that is a TR SO2 Group 

1 unit under § 97.604 on the later of 

January 1, 2005 or the date the unit 

commences commercial operation as 

defined in the introductory text of 

paragraph (1) of this definition and that 

subsequently undergoes a physical 

change or is moved to a new location or 

source, such date shall remain the date 

of commencement of commercial 

operation of the unit, which shall 

continue to be treated as the same unit. 

(ii) For a unit that is a TR SO2 Group 

1 unit under § 97.604 on the later of 

January 1, 2005 or the date the unit 

commences commercial operation as 

defined in the introductory text of 

paragraph (1) of this definition and that 

is subsequently replaced by a unit at the 

same or a different source, such date 

shall remain the replaced unit’s date of 

commencement of commercial 

operation, and the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1) or (2) of this definition as 

appropriate. 

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 97.605, for a unit that is not a TR 

SO2 Group 1 unit under § 97.604 on the 

later of January 1, 2005 or the date the 

unit commences commercial operation 

as defined in introductory text of 

paragraph (1) of this definition, the 

unit’s date for commencement of 

commercial operation shall be the date 

on which the unit becomes a TR SO2

Group 1 unit under § 97.604. 

(i) For a unit with a date for 

commencement of commercial 

operation as defined in the introductory 

text of paragraph (2) of this definition 

and that subsequently undergoes a 

physical change or is moved to a 

different location or source, such date 

shall remain the date of commencement 

of commercial operation of the unit, 

which shall continue to be treated as the 

same unit. 

(ii) For a unit with a date for 

commencement of commercial 

operation as defined in the introductory 

text of paragraph (2) of this definition 

and that is subsequently replaced by a 

unit at the same or a different source, 

such date shall remain the replaced 

unit’s date of commencement of 

commercial operation, and the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of commercial 

operation as defined in paragraph (1) or 

(2) of this definition as appropriate. 

Common designated representative 

means, with regard to a control period 

in a given year, a designated 

representative where, as of April 1 

immediately after the allowance transfer 

deadline for such control period, the 

same natural person is authorized under 

§§ 97.613(a) and 97.615(a) as the 

designated representative for a group of 

one or more TR SO2 Group 1 sources 

and units located in a State (and Indian 

country within the borders of such 

State). 

Common designated representative’s 

assurance level means, with regard to a 

specific common designated 

representative and a State (and Indian 

country within the borders of such 

State) and control period in a given year 

for which the State assurance level is 

exceeded as described in 

§ 97.606(c)(2)(iii), the common 

designated representative’s share of the 

State SO2 Group 1 trading budget with 

the variability limit for the State for 

such control period. 

Common designated representative’s 

share means, with regard to a specific 

common designated representative for a 

control period in a given year: 

(1) With regard to a total amount of 

SO2 emissions from all TR SO2 Group 1 

units in a State (and Indian country 

within the borders of such State) during 

such control period, the total tonnage of 

SO2 emissions during such control 

period from a group of one or more TR 

SO2 Group 1 units located in such State 

(and such Indian country) and having 

the common designated representative 

for such control period; 

(2) With regard to a State SO2 Group 

1 trading budget with the variability 

limit for such control period, the 

amount (rounded to the nearest 

allowance) equal to the sum of the total 

amount of TR SO2 Group 1 allowances 

allocated for such control period to a 

group of one or more TR SO2 Group 1 

units located in the State (and Indian 

country within the borders of such 


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State) and having the common 

designated representative for such 

control period and of the total amount 

of TR SO2 Group 1 allowances 

purchased by an owner or operator of 

such TR SO2 Group 1 units in an 

auction for such control period and 

submitted by the State or the permitting 

authority to the Administrator for 

recordation in the compliance accounts 

for such TR SO2 Group 1 units in 

accordance with the TR SO2 Group 1 

allowance auction provisions in a SIP 

revision approved by the Administrator 

under § 52.39(e) or (f) of this chapter, 

multiplied by the sum of the State SO2

Group 1 trading budget under 

§ 97.610(a) and the State’s variability 

limit under § 97.610(b) for such control 

period and divided by such State SO2

Group 1 trading budget; 

(3) Provided that, in the case of a unit 

that operates during, but has no amount 

of TR SO2 Group 1 allowances allocated 

under §§ 97.611 and 97.612 for, such 

control period, the unit shall be treated, 

solely for purposes of this definition, as 

being allocated an amount (rounded to 

the nearest allowance) of TR SO2 Group 

1 allowances for such control period 

equal to the unit’s allowable SO2

emission rate applicable to such control 

period, multiplied by a capacity factor 

of 0.85 (if the unit is a boiler combusting 

any amount of coal or coal-derived fuel 

during such control period), 0.24 (if the 

unit is a simple combustion turbine 

during such control period), 0.67 (if the 

unit is a combined cycle turbine during 

such control period), 0.74 (if the unit is 

an integrated coal gasification combined 

cycle unit during such control period), 

or 0.36 (for any other unit), multiplied 

by the unit’s maximum hourly load as 

reported in accordance with this subpart 

and by 8,760 hours/control period, and 

divided by 2,000 lb/ton. 

Common stack means a single flue 

through which emissions from 2 or 

more units are exhausted. 

Compliance account means an 

Allowance Management System 

account, established by the 

Administrator for a TR SO2 Group 1 

source under this subpart, in which any 

TR SO2 Group 1 allowance allocations 

to the TR SO2 Group 1 units at the 

source are recorded and in which are 

held any TR SO2 Group 1 allowances 

available for use for a control period in 

a given year in complying with the 

source’s TR SO2 Group 1 emissions 

limitation in accordance with §§ 97.606 

and 97.624. 

Continuous emission monitoring 

system or CEMS means the equipment 

required under this subpart to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes and using an 

automated data acquisition and 

handling system (DAHS), a permanent 

record of SO2 emissions, stack gas 

volumetric flow rate, stack gas moisture 

content, and O2 or CO2 concentration (as 

applicable), in a manner consistent with 

part 75 of this chapter and §§ 97.630 

through 97.635. The following systems 

are the principal types of continuous 

emission monitoring systems: 

(1) A flow monitoring system, 

consisting of a stack flow rate monitor 

and an automated data acquisition and 

handling system and providing a 

permanent, continuous record of stack 

gas volumetric flow rate, in standard 

cubic feet per hour (scfh); 

(2) A SO2 monitoring system, 

consisting of a SO2 pollutant 

concentration monitor and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of SO2

emissions, in parts per million (ppm); 

(3) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O; 

(4) A CO2 monitoring system, 

consisting of a CO2 pollutant 

concentration monitor (or an O2 monitor 

plus suitable mathematical equations 

from which the CO2 concentration is 

derived) and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of CO2 emissions, in percent CO2; 

and 

(5) An O2 monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2, in percent O2. 

Control period means the period 

starting January 1 of a calendar year, 

except as provided in § 97.606(c)(3), and 

ending on December 31 of the same 

year, inclusive. 

Designated representative means, for 

a TR SO2 Group 1 source and each TR 

SO2 Group 1 unit at the source, the 

natural person who is authorized by the 

owners and operators of the source and 

all such units at the source, in 

accordance with this subpart, to 

represent and legally bind each owner 

and operator in matters pertaining to the 

TR SO2 Group 1 Trading Program. If the 

TR SO2 Group 1 source is also subject 

to the Acid Rain Program, TR NOX

Annual Trading Program, or TR NOX

Ozone Season Trading Program, then 

this natural person shall be the same 

natural person as the designated 

representative, as defined in the 

respective program. 

Emissions means air pollutants 

exhausted from a unit or source into the 

atmosphere, as measured, recorded, and 

reported to the Administrator by the 

designated representative, and as 

modified by the Administrator: 

(1) In accordance with this subpart; 

and 

(2) With regard to a period before the 

unit or source is required to measure, 

record, and report such air pollutants in 

accordance with this subpart, in 

accordance with part 75 of this chapter. 

Excess emissions means any ton of 

emissions from the TR SO2 Group 1 

units at a TR SO2 Group 1 source during 

a control period in a given year that 

exceeds the TR SO2 Group 1 emissions 

limitation for the source for such control 

period. 

Fossil fuel means— 

(1) Natural gas, petroleum, coal, or 

any form of solid, liquid, or gaseous fuel 

derived from such material; or 

(2) For purposes of applying the 

limitation on ‘‘average annual fuel 

consumption of fossil fuel’’ in 

§§ 97.604(b)(2)(i)(B) and (ii), natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material for the purpose of creating 

useful heat. 

Fossil-fuel-fired means, with regard to 

a unit, combusting any amount of fossil 

fuel in 2005 or any calendar year 

thereafter. 

General account means an Allowance 

Management System account, 

established under this subpart, that is 

not a compliance account or an 

assurance account. 

Generator means a device that 

produces electricity. 

Gross electrical output means, for a 

unit, electricity made available for use, 

including any such electricity used in 

the power production process (which 

process includes, but is not limited to, 

any on-site processing or treatment of 

fuel combusted at the unit and any onsite emission controls). 

Heat input means, for a unit for a 

specified period of time, the product (in 

mmBtu/time) of the gross calorific value 

of the fuel (in mmBtu/lb) fed into the 

unit multiplied by the fuel feed rate (in 

lb of fuel/time), as measured, recorded, 

and reported to the Administrator by the 

designated representative and as 

modified by the Administrator in 

accordance with this subpart and 

excluding the heat derived from 

preheated combustion air, recirculated 

flue gases, or exhaust. 

Heat input rate means, for a unit, the 

amount of heat input (in mmBtu) 

divided by unit operating time (in hr) 

or, for a unit and a specific fuel, the 

amount of heat input attributed to the 


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fuel (in mmBtu) divided by the unit 

operating time (in hr) during which the 

unit combusts the fuel. 

Heat rate means, for a unit, the unit’s 

maximum design heat input (in Btu/hr), 

divided by the product of 1,000,000 

Btu/mmBtu and the unit’s maximum 

hourly load. 

Indian country means ‘‘Indian 

country’’ as defined in 18 U.S.C. 1151. 

Life-of-the-unit, firm power 

contractual arrangement means a unit 

participation power sales agreement 

under which a utility or industrial 

customer reserves, or is entitled to 

receive, a specified amount or 

percentage of nameplate capacity and 

associated energy generated by any 

specified unit and pays its proportional 

amount of such unit’s total costs, 

pursuant to a contract: 

(1) For the life of the unit; 

(2) For a cumulative term of no less 

than 30 years, including contracts that 

permit an election for early termination; 

or 

(3) For a period no less than 25 years 

or 70 percent of the economic useful life 

of the unit determined as of the time the 

unit is built, with option rights to 

purchase or release some portion of the 

nameplate capacity and associated 

energy generated by the unit at the end 

of the period. 

Maximum design heat input means, 

for a unit, the maximum amount of fuel 

per hour (in Btu/hr) that the unit is 

capable of combusting on a steady state 

basis as of the initial installation of the 

unit as specified by the manufacturer of 

the unit. 

Monitoring system means any 

monitoring system that meets the 

requirements of this subpart, including 

a continuous emission monitoring 

system, an alternative monitoring 

system, or an excepted monitoring 

system under part 75 of this chapter. 

Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe, rounded to 

the nearest tenth) that the generator is 

capable of producing on a steady state 

basis and during continuous operation 

(when not restricted by seasonal or 

other deratings) as of such installation 

as specified by the manufacturer of the 

generator or, starting from the 

completion of any subsequent physical 

change in the generator resulting in an 

increase in the maximum electrical 

generating output that the generator is 

capable of producing on a steady state 

basis and during continuous operation 

(when not restricted by seasonal or 

other deratings), such increased 

maximum amount (in MWe, rounded to 

the nearest tenth) as of such completion 

as specified by the person conducting 

the physical change. 

Natural gas means ‘‘natural gas’’ as 

defined in § 72.2 of this chapter. 

Newly affected TR SO2 Group 1 unit 

means a unit that was not a TR SO2

Group 1 unit when it began operating 

but that thereafter becomes a TR SO2

Group 1 unit. 

Operate or operation means, with 

regard to a unit, to combust fuel. 

Operator means, for a TR SO2 Group 

1 source or a TR SO2 Group 1 unit at 

a source respectively, any person who 

operates, controls, or supervises a TR 

SO2 Group 1 unit at the source or the 

TR SO2 Group 1 unit and shall include, 

but not be limited to, any holding 

company, utility system, or plant 

manager of such source or unit. 

Owner means, for a TR SO2 Group 1 

source or a TR SO2 Group 1 unit at a 

source respectively, any of the following 

persons: 

(1) Any holder of any portion of the 

legal or equitable title in a TR SO2

Group 1 unit at the source or the TR SO2

Group 1 unit; 

(2) Any holder of a leasehold interest 

in a TR SO2 Group 1 unit at the source 

or the TR SO2 Group 1 unit, provided 

that, unless expressly provided for in a 

leasehold agreement, ‘‘owner’’ shall not 

include a passive lessor, or a person 

who has an equitable interest through 

such lessor, whose rental payments are 

not based (either directly or indirectly) 

on the revenues or income from such TR 

SO2 Group 1 unit; and 

(3) Any purchaser of power from a TR 

SO2 Group 1 unit at the source or the 

TR SO2 Group 1 unit under a life-of-theunit, firm power contractual 

arrangement. 

Permanently retired means, with 

regard to a unit, a unit that is 

unavailable for service and that the 

unit’s owners and operators do not 

expect to return to service in the future. 

Permitting authority means 

‘‘permitting authority’’ as defined in 

§§ 70.2 and 71.2 of this chapter. 

Potential electrical output capacity 

means, for a unit, 33 percent of the 

unit’s maximum design heat input, 

divided by 3,413 Btu/kWh, divided by 

1,000 kWh/MWh, and multiplied by 

8,760 hr/yr. 

Receive or receipt of means, when 

referring to the Administrator, to come 

into possession of a document, 

information, or correspondence 

(whether sent in hard copy or by 

authorized electronic transmission), as 

indicated in an official log, or by a 

notation made on the document, 

information, or correspondence, by the 

Administrator in the regular course of 

business. 

Recordation, record, or recorded 

means, with regard to TR SO2 Group 1 

allowances, the moving of TR SO2

Group 1 allowances by the 

Administrator into, out of, or between 

Allowance Management System 

accounts, for purposes of allocation, 

auction, transfer, or deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter. 

Replacement, replace, or replaced 

means, with regard to a unit, the 

demolishing of a unit, or the permanent 

retirement and permanent disabling of a 

unit, and the construction of another 

unit (the replacement unit) to be used 

instead of the demolished or retired unit 

(the replaced unit). 

Sequential use of energy means: 

(1) The use of reject heat from 

electricity production in a useful 

thermal energy application or process; 

or 

(2) The use of reject heat from useful 

thermal energy application or process in 

electricity production. 

Serial number means, for a TR SO2

Group 1 allowance, the unique 

identification number assigned to each 

TR SO2 Group 1 allowance by the 

Administrator. 

Solid waste incineration unit means a 

stationary, fossil-fuel-fired boiler or 

stationary, fossil-fuel-fired combustion 

turbine that is a ‘‘solid waste 

incineration unit’’ as defined in section 

129(g)(1) of the Clean Air Act. 

Source means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. This definition 

does not change or otherwise affect the 

definition of ‘‘major source’’, ‘‘stationary 

source’’, or ‘‘source’’ as set forth and 

implemented in a title V operating 

permit program or any other program 

under the Clean Air Act. 

State means one of the States that is 

subject to the TR SO2 Group 1 Trading 

Program pursuant to § 52.39(a), (b), (d), 

(e), and (f) of this chapter. 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery; 

(4) Provided that compliance with any 

‘‘submission’’ or ‘‘service’’ deadline 

shall be determined by the date of 

dispatch, transmission, or mailing and 

not the date of receipt. 


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Topping-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful power, 

including electricity, where at least 

some of the reject heat from the 

electricity production is then used to 

provide useful thermal energy. 

Total energy input means, for a unit, 

total energy of all forms supplied to the 

unit, excluding energy produced by the 

unit. Each form of energy supplied shall 

be measured by the lower heating value 

of that form of energy calculated as 

follows: 

LHV = HHV ¥ 10.55(W + 9H) 

Where: 

LHV = lower heating value of the form of 

energy in Btu/lb, 

HHV = higher heating value of the form of 

energy in Btu/lb, 

W = weight % of moisture in the form of 

energy, and 

H = weight % of hydrogen in the form of 

energy. 

Total energy output means, for a unit, 

the sum of useful power and useful 

thermal energy produced by the unit. 

TR NOX Annual Trading Program 

means a multi-state NOX air pollution 

control and emission reduction program 

established in accordance with subpart 

AAAAA of this part and § 52.38(a) of 

this chapter (including such a program 

that is revised in a SIP revision 

approved by the Administrator under 

§ 52.38(a)(3) or (4) of this chapter or that 

is established in a SIP revision approved 

by the Administrator under § 52.38(a)(5) 

of this chapter), as a means of mitigating 

interstate transport of fine particulates 

and NOX.

TR NOX Ozone Season Trading 

Program means a multi-state NOX air 

pollution control and emission 

reduction program established in 

accordance with subpart BBBBB of this 

part and § 52.38(b) of this chapter 

(including such a program that is 

revised in a SIP revision approved by 

the Administrator under § 52.38(b)(3) or 

(4) of this chapter or that is established 

in a SIP revision approved by the 

Administrator under § 52.38(b)(5) of this 

chapter), as a means of mitigating 

interstate transport of ozone and NOX.

TR SO2 Group 1 allowance means a 

limited authorization issued and 

allocated or auctioned by the 

Administrator under this subpart, or by 

a State or permitting authority under a 

SIP revision approved by the 

Administrator under § 52.39(d), (e), or 

(f) of this chapter, to emit one ton of SO2

during a control period of the specified 

calendar year for which the 

authorization is allocated or auctioned 

or of any calendar year thereafter under 

the TR SO2 Group 1 Trading Program. 

TR SO2 Group 1 allowance deduction 

or deduct TR SO2 Group 1 allowances 

means the permanent withdrawal of TR 

SO2 Group 1 allowances by the 

Administrator from a compliance 

account (e.g., in order to account for 

compliance with the TR SO2 Group 1 

emissions limitation) or from an 

assurance account (e.g., in order to 

account for compliance with the 

assurance provisions under §§ 97.606 

and 97.625). 

TR SO2 Group 1 allowances held or 

hold TR SO2 Group 1 allowances means 

the TR SO2 Group 1 allowances treated 

as included in an Allowance 

Management System account as of a 

specified point in time because at that 

time they: 

(1) Have been recorded by the 

Administrator in the account or 

transferred into the account by a 

correctly submitted, but not yet 

recorded, TR SO2 Group 1 allowance 

transfer in accordance with this subpart; 

and 

(2) Have not been transferred out of 

the account by a correctly submitted, 

but not yet recorded, TR SO2 Group 1 

allowance transfer in accordance with 

this subpart. 

TR SO2 Group 1 emissions limitation 

means, for a TR SO2 Group 1 source, the 

tonnage of SO2 emissions authorized in 

a control period by the TR SO2 Group 

1 allowances available for deduction for 

the source under § 97.624(a) for such 

control period. 

TR SO2 Group 1 source means a 

source that includes one or more TR 

SO2 Group 1 units. 

TR SO2 Group 1 Trading Program 

means a multi-state SO2 air pollution 

control and emission reduction program 

established in accordance with this 

subpart and § 52.39(a), (b), (d) through 

(f), (j), and (k) of this chapter (including 

such a program that is revised in a SIP 

revision approved by the Administrator 

under § 52.39(d) or (e) of this chapter or 

that is established in a SIP revision 

approved by the Administrator under 

§ 52.39(f) of this chapter), as a means of 

mitigating interstate transport of fine 

particulates and SO2.

TR SO2 Group 1 unit means a unit 

that is subject to the TR SO2 Group 1 

Trading Program under § 97.604. 

Unit means a stationary, fossil-fuelfired 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 processing or treatment of 

fuel combusted at the unit and any onsite emission controls). 

Useful thermal energy means thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process (not a power 

production process), excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heating application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., in an absorption 

chiller). 

Utility power distribution system 

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers. 

§ 97.603 Measurements, abbreviations, 

and acronyms. 

Measurements, abbreviations, and 

acronyms used in this subpart are 

defined as follows: 

Btu—British thermal unit 

CO2—carbon dioxide 

H2O—water 

hr—hour 

kW—kilowatt electrical 

kWh—kilowatt hour 

lb—pound 

mmBtu—million Btu 

MWe—megawatt electrical 

MWh—megawatt hour 

NOX—nitrogen oxides 

O2—oxygen 

ppm—parts per million 

scfh—standard cubic feet per hour 

SO2—sulfur dioxide 

yr—year 

§ 97.604 Applicability. 

(a) Except as provided in paragraph 

(b) of this section: 

(1) The following units in a State (and 

Indian country within the borders of 

such State) shall be TR SO2 Group 1 

units, and any source that includes one 

or more such units shall be a TR SO2

Group 1 source, subject to the 

requirements of this subpart: any 

stationary, fossil-fuel-fired boiler or 


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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 (and Indian 

country within the borders of such 

State) that otherwise is a TR SO2 Group 

1 unit under paragraph (a) of this 

section and that meets the requirements 

set forth in paragraph (b)(1)(i) or (2)(i) of 

this section shall not be a TR SO2 Group 

1 unit: 

(1)(i) Any unit: 

(A) Qualifying as a cogeneration unit 

throughout the later of 2005 or the 12- 

month period starting on the date the 

unit first produces electricity and 

continuing to qualify as a cogeneration 

unit throughout each calendar year 

ending after the later of 2005 or such 12- 

month period; and 

(B) Not supplying in 2005 or any 

calendar year thereafter more than onethird of the unit’s potential electric 

output capacity or 219,000 MWh, 

whichever is greater, to any utility 

power distribution system for sale. 

(ii) If, after qualifying under 

paragraph (b)(1)(i) of this section as not 

being a TR SO2 Group 1 unit, a unit 

subsequently no longer meets all the 

requirements of paragraph (b)(1)(i) of 

this section, the unit shall become a TR 

SO2 Group 1 unit starting on the earlier 

of January 1 after the first calendar year 

during which the unit first no longer 

qualifies as a cogeneration unit or 

January 1 after the first calendar year 

during which the unit no longer meets 

the requirements of paragraph 

(b)(1)(i)(B) of this section. The unit shall 

thereafter continue to be a TR SO2

Group 1 unit. 

(2)(i) Any unit: 

(A) Qualifying as a solid waste 

incineration unit throughout the later of 

2005 or the 12-month period starting on 

the date the unit first produces 

electricity and continuing to qualify as 

a solid waste incineration unit 

throughout each calendar year ending 

after the later of 2005 or such 12-month 

period; and 

(B) With an average annual fuel 

consumption of fossil fuel for the first 

3 consecutive calendar years of 

operation starting no earlier than 2005 

of less than 20 percent (on a Btu basis) 

and an average annual fuel consumption 

of fossil fuel for any 3 consecutive 

calendar years thereafter of less than 20 

percent (on a Btu basis). 

(ii) If, after qualifying under 

paragraph (b)(2)(i) of this section as not 

being a TR SO2 Group 1 unit, a unit 

subsequently no longer meets all the 

requirements of paragraph (b)(1)(i) of 

this section, the unit shall become a TR 

SO2 Group 1 unit starting on the earlier 

of January 1 after the first calendar year 

during which the unit first no longer 

qualifies as a solid waste incineration 

unit or January 1 after the first 3 

consecutive calendar years after 2005 

for which the unit has an average 

annual fuel consumption of fossil fuel of 

20 percent or more. The unit shall 

thereafter continue to be a TR SO2

Group 1 unit. 

(c) A certifying official of an owner or 

operator of any unit or other equipment 

may submit a petition (including any 

supporting documents) to the 

Administrator at any time for a 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section or a SIP revision 

approved under § 52.39(e) or (f) of this 

chapter, of the TR SO2 Group 1 Trading 

Program to the unit or other equipment. 

(1) Petition content. The petition shall 

be in writing and include the 

identification of the unit or other 

equipment and the relevant facts about 

the unit or other equipment. The 

petition and any other documents 

provided to the Administrator in 

connection with the petition shall 

include the following certification 

statement, signed by the certifying 

official: ‘‘I am authorized to make this 

submission on behalf of the owners and 

operators of the unit or other equipment 

for which the submission is made. I 

certify under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(2) Response. The Administrator will 

issue a written response to the petition 

and may request supplemental 

information determined by the 

Administrator to be relevant to such 

petition. The Administrator’s 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section, of the TR SO2 Group 

1 Trading Program to the unit or other 

equipment shall be binding on any State 

or permitting authority unless the 

Administrator determines that the 

petition or other documents or 

information provided in connection 

with the petition contained significant, 

relevant errors or omissions. 

§ 97.605 Retired unit exemption. 

(a)(1) Any TR SO2 Group 1 unit that 

is permanently retired shall be exempt 

from § 97.606(b) and (c)(1), § 97.624, 

and §§ 97.630 through 97.635. 

(2) The exemption under paragraph 

(a)(1) of this section shall become 

effective the day on which the TR SO2

Group 1 unit is permanently retired. 

Within 30 days of the unit’s permanent 

retirement, the designated 

representative shall submit a statement 

to the Administrator. The statement 

shall state, in a format prescribed by the 

Administrator, that the unit was 

permanently retired on a specified date 

and will comply with the requirements 

of paragraph (b) of this section. 

(b) Special provisions. (1) A unit 

exempt under paragraph (a) of this 

section shall not emit any SO2, starting 

on the date that the exemption takes 

effect. 

(2) For a period of 5 years from the 

date the records are created, the owners 

and operators of a unit exempt under 

paragraph (a) of this section shall retain, 

at the source that includes the unit, 

records demonstrating that the unit is 

permanently retired. The 5-year period 

for keeping records may be extended for 

cause, at any time before the end of the 

period, in writing by the Administrator. 

The owners and operators bear the 

burden of proof that the unit is 

permanently retired. 

(3) The owners and operators and, to 

the extent applicable, the designated 

representative of a unit exempt under 

paragraph (a) of this section shall 

comply with the requirements of the TR 

SO2 Group 1 Trading Program 

concerning all periods for which the 

exemption is not in effect, even if such 

requirements arise, or must be complied 

with, after the exemption takes effect. 

(4) A unit exempt under paragraph (a) 

of this section shall lose its exemption 

on the first date on which the unit 

resumes operation. Such unit shall be 

treated, for purposes of applying 

allocation, monitoring, reporting, and 

recordkeeping requirements under this 

subpart, as a unit that commences 

commercial operation on the first date 

on which the unit resumes operation. 


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§ 97.606 Standard requirements. 

(a) Designated representative 

requirements. The owners and operators 

shall comply with the requirement to 

have a designated representative, and 

may have an alternate designated 

representative, in accordance with 

§§ 97.613 through 97.618. 

(b) Emissions monitoring, reporting, 

and recordkeeping requirements. (1) 

The owners and operators, and the 

designated representative, of each TR 

SO2 Group 1 source and each TR SO2

Group 1 unit at the source shall comply 

with the monitoring, reporting, and 

recordkeeping requirements of §§ 97.630 

through 97.635. 

(2) The emissions data determined in 

accordance with §§ 97.630 through 

97.635 shall be used to calculate 

allocations of TR SO2 Group 1 

allowances under §§ 97.611(a)(2) and (b) 

and 97.612 and to determine 

compliance with the TR SO2 Group 1 

emissions limitation and assurance 

provisions under paragraph (c) of this 

section, provided that, for each 

monitoring location from which mass 

emissions are reported, the mass 

emissions amount used in calculating 

such allocations and determining such 

compliance shall be the mass emissions 

amount for the monitoring location 

determined in accordance with 

§§ 97.630 through 97.635 and rounded 

to the nearest ton, with any fraction of 

a ton less than 0.50 being deemed to be 

zero. 

(c) SO2 emissions requirements. (1) 

TR SO2 Group 1 emissions limitation. (i) 

As of the allowance transfer deadline for 

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 

(B) The owners and operators of the 

source and each TR SO2 Group 1 unit 

at the source shall pay any fine, penalty, 

or assessment or comply with any other 

remedy imposed, for the same 

violations, under the Clean Air Act, and 

each ton of such excess emissions and 

each day of such control period shall 

constitute a separate violation of this 

subpart and the Clean Air Act. 

(2) TR SO2 Group 1 assurance 

provisions. (i) If total SO2 emissions 

during a control period in a given year 

from all TR SO2 Group 1 units at TR SO2

Group 1 sources in a State (and Indian 

country within the borders of such 

State) exceed the State assurance level, 

then the owners and operators of such 

sources and units in each group of one 

or more sources and units having a 

common designated representative for 

such control period, where the common 

designated representative’s share of 

such SO2 emissions during such control 

period exceeds the common designated 

representative’s assurance level for the 

State and such control period, shall 

hold (in the assurance account 

established for the owners and operators 

of such group) TR SO2 Group 1 

allowances available for deduction for 

such control period under § 97.625(a) in 

an amount equal to two times the 

product (rounded to the nearest whole 

number), as determined by the 

Administrator in accordance with 

§ 97.625(b), of multiplying— 

(A) The quotient of the amount by 

which the common designated 

representative’s share of such SO2

emissions exceeds the common 

designated representative’s assurance 

level divided by the sum of the 

amounts, determined for all common 

designated representatives for such 

sources and units in the State (and 

Indian country within the borders of 

such State) for such control period, by 

which each common designated 

representative’s share of such SO2

emissions exceeds the respective 

common designated representative’s 

assurance level; and 

(B) The amount by which total SO2

emissions from all TR SO2 Group 1 

units at TR SO2 Group 1 sources in the 

State (and Indian country within the 

borders of such State) for such control 

period exceed the State assurance level. 

(ii) The owners and operators shall 

hold the TR SO2 Group 1 allowances 

required under paragraph (c)(2)(i) of this 

section, as of midnight of November 1 

(if it is a business day), or midnight of 

the first business day thereafter (if 

November 1 is not a business day), 

immediately after such control period. 

(iii) Total SO2 emissions from all TR 

SO2 Group 1 units at TR SO2 Group 1 

sources in a State (and Indian country 

within the borders of such State) during 

a control period in a given year exceed 

the State assurance level if such total 

SO2 emissions exceed the sum, for such 

control period, of the State SO2 Group 

1 trading budget under § 97.610(a) and 

the State’s variability limit under 

§ 97.610(b). 

(iv) It shall not be a violation of this 

subpart or of the Clean Air Act if total 

SO2 emissions from all TR SO2 Group 1 

units at TR SO2 Group 1 sources in a 

State (and Indian country within the 

borders of such State) during a control 

period exceed the State assurance level 

or if a common designated 

representative’s share of total SO2

emissions from the TR SO2 Group 1 

units at TR SO2 Group 1 sources in a 

State (and Indian country within the 

borders of such State) during a control 

period exceeds the common designated 

representative’s assurance level. 

(v) To the extent the owners and 

operators fail to hold TR SO2 Group 1 

allowances for a control period in a 

given year in accordance with 

paragraphs (c)(2)(i) through (iii) of this 

section, 

(A) The owners and operators shall 

pay any fine, penalty, or assessment or 

comply with any other remedy imposed 

under the Clean Air Act; and 

(B) Each TR SO2 Group 1 allowance 

that the owners and operators fail to 

hold for such control period in 

accordance with paragraphs (c)(2)(i) 

through (iii) of this section and each day 

of such control period shall constitute a 

separate violation of this subpart and 

the Clean Air Act. 

(3) Compliance periods. A TR SO2

Group 1 unit shall be subject to the 

requirements under paragraphs (c)(1) 

and (c)(2) of this section for the control 

period starting on the later of January 1, 

2012 or the deadline for meeting the 

unit’s monitor certification 

requirements under § 97.630(b) and for 

each control period thereafter. 

(4) Vintage of allowances held for 

compliance. (i) A TR SO2 Group 1 

allowance held for compliance with the 

requirements under paragraph (c)(1)(i) 

of this section for a control period in a 

given year must be a TR SO2 Group 1 

allowance that was allocated for such 

control period or a control period in a 

prior year. 

(ii) A TR SO2 Group 1 allowance held 

for compliance with the requirements 

under paragraphs (c)(1)(ii)(A) and (2)(i) 

through (iii) of this section for a control 

period in a given year must be a TR SO2

Group 1 allowance that was allocated 

for a control period in a prior year or the 

control period in the given year or in the 

immediately following year. 

(5) Allowance Management System 

requirements. Each TR SO2 Group 1 

allowance shall be held in, deducted 

from, or transferred into, out of, or 

between Allowance Management 


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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 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 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. 

(ii) All emissions monitoring 

information, in accordance with this 

subpart. 

(iii) Copies of all reports, compliance 

certifications, and other submissions 

and all records made or required under, 

or to demonstrate compliance with the 

requirements of, the TR SO2 Group 1 

Trading Program. 

(2) The designated representative of a 

TR SO2 Group 1 source and each TR 

SO2 Group 1 unit at the source shall 

make all submissions required under 

the TR SO2 Group 1 Trading Program, 

except as provided in § 97.618. This 

requirement does not change, create an 

exemption from, or or otherwise affect 

the responsible official submission 

requirements under a title V operating 

permit program in parts 70 and 71 of 

this chapter. 

(f) Liability. (1) Any provision of the 

TR SO2 Group 1 Trading Program that 

applies to a TR SO2 Group 1 source or 

the designated representative of a TR 

SO2 Group 1 source shall also apply to 

the owners and operators of such source 

and of the TR SO2 Group 1 units at the 

source. 

(2) Any provision of the TR SO2

Group 1 Trading Program that applies to 

a TR SO2 Group 1 unit or the designated 

representative of a TR SO2 Group 1 unit 

shall also apply to the owners and 

operators of such unit. 

(g) Effect on other authorities. No 

provision of the TR SO2 Group 1 

Trading Program or exemption under 

§ 97.605 shall be construed as 

exempting or excluding the owners and 

operators, and the designated 

representative, of a TR SO2 Group 1 

source or TR SO2 Group 1 unit from 

compliance with any other provision of 

the applicable, approved State 

implementation plan, a federally 

enforceable permit, or the Clean Air Act. 

§ 97.607 Computation of time. 

(a) Unless otherwise stated, any time 

period scheduled, under the TR SO2

Group 1 Trading Program, to begin on 

the occurrence of an act or event shall 

begin on the day the act or event occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the TR SO2

Group 1 Trading Program, to begin 

before the occurrence of an act or event 

shall be computed so that the period 

ends the day before the act or event 

occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the TR 

SO2 Group 1 Trading Program, is not a 

business day, the time period shall be 

extended to the next business day. 

§ 97.608 Administrative appeal 

procedures. 

The administrative appeal procedures 

for decisions of the Administrator under 

the TR SO2 Group 1 Trading Program 

are set forth in part 78 of this chapter. 

§ 97.609 [Reserved] 

§ 97.610 State SO2 Group 1 trading 

budgets, new unit set-asides, Indian 

country new unit set-aside, and variability 

limits. 

(a) The State SO2 Group 1 trading 

budgets, new unit set-asides, and Indian 

country new unit set-asides for 

allocations of TR SO2 Group 1 

allowances for the control periods in 

2012 and thereafter are as follows: 

State 

SO2 Group 1 trading budget (tons) * 

for 2012 and 2013 

New unit set-aside 

(tons) 

for 2012 and 2013 

Indian country new 

unit set-aside (tons) 

for 2012 and 2013 

Illinois ................................................................................................................... 234,889 11,744 ................................

Indiana ................................................................................................................. 285,424 8,563 ................................

Iowa ..................................................................................................................... 107,085 2,035 107 

Kentucky .............................................................................................................. 232,662 13,960 ................................

Maryland .............................................................................................................. 30,120 602 ................................

Michigan ............................................................................................................... 229,303 4,357 229 

Missouri ................................................................................................................ 207,466 4,149 ................................

New Jersey .......................................................................................................... 5,574 111 ................................


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State 

SO2 Group 1 trading budget (tons) * 

for 2012 and 2013 

New unit set-aside 

(tons) 

for 2012 and 2013 

Indian country new 

unit set-aside (tons) 

for 2012 and 2013 

New York ............................................................................................................. 27,325 520 27 

North Carolina ...................................................................................................... 136,881 10,813 137 

Ohio ..................................................................................................................... 310,230 6,205 ................................

Pennsylvania ........................................................................................................ 278,651 5,573 ................................

Tennessee ........................................................................................................... 148,150 2,963 ................................

Virginia ................................................................................................................. 70,820 2,833 ................................

West Virginia ........................................................................................................ 146,174 10,232 ................................

Wisconsin ............................................................................................................. 79,480 3,894 80 

State 

SO2 Group 1 trading budget (tons) * 

for 2014 and thereafter 

New unit set-aside 

(tons) 

for 2014 and thereafter 

Indian country new 

unit set-aside (tons) 

for 2014 and thereafter 

Illinois ................................................................................................................... 124,123 6,206 ................................

Indiana ................................................................................................................. 161,111 4,833 ................................

Iowa ..................................................................................................................... 75,184 1,429 75 

Kentucky .............................................................................................................. 106,284 6,377 ................................

Maryland .............................................................................................................. 28,203 564 ................................

Michigan ............................................................................................................... 143,995 2,736 144 

Missouri ................................................................................................................ 165,941 3,319 ................................

New Jersey .......................................................................................................... 5,574 111 ................................

New York ............................................................................................................. 18,585 353 19 

North Carolina ...................................................................................................... 57,620 4,552 58 

Ohio ..................................................................................................................... 137,077 2,742 ................................

Pennsylvania ........................................................................................................ 112,021 2,240 ................................

Tennessee ........................................................................................................... 58,833 1,177 ................................

Virginia ................................................................................................................. 35,057 1,402 ................................

West Virginia ........................................................................................................ 75,668 5,297 ................................

Wisconsin ............................................................................................................. 40,126 1,966 40 

* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-aside and does not include the 

variability limit. 

(b) The States’ variability limits for 

the State SO2 Group 1 trading budgets 

for the control periods in 2012 and 

thereafter are as follows: 

State Variability limits 

for 2012 and 2013 

Variability limits 

for 2014 and thereafter 

Illinois ....................................................................................................................................................... 42,280 22,342 

Indiana ..................................................................................................................................................... 51,376 29,000 

Iowa ......................................................................................................................................................... 19,275 13,533 

Kentucky .................................................................................................................................................. 41,879 19,131 

Maryland .................................................................................................................................................. 5,422 5,077 

Michigan ................................................................................................................................................... 41,275 25,919 

Missouri .................................................................................................................................................... 37,344 29,869 

New Jersey .............................................................................................................................................. 1,003 1,003 

New York ................................................................................................................................................. 4,919 3,345 

North Carolina .......................................................................................................................................... 24,639 10,372 

Ohio ......................................................................................................................................................... 55,841 24,674 

Pennsylvania ............................................................................................................................................ 50,157 20,164 

Tennessee ............................................................................................................................................... 26,667 10,590 

Virginia ..................................................................................................................................................... 12,748 6,310 

West Virginia ............................................................................................................................................ 26,311 13,620 

Wisconsin ................................................................................................................................................. 14,306 7,223 

§ 97.611 Timing requirements for TR SO2

Group 1 allowance allocations. 

(a) Existing units. (1) TR SO2 Group 1 

allowances are allocated, for the control 

periods in 2012 and each year 

thereafter, as provided in a notice of 

data availability issued by the 

Administrator. Providing an allocation 

to a unit in such notice does not 

constitute a determination that the unit 

is a TR SO2 Group 1 unit, and not 

providing an allocation to a unit in such 

notice does not constitute a 

determination that the unit is not a TR 

SO2 Group 1 unit. 

(2) Notwithstanding paragraph (a)(1) 

of this section, if a unit provided an 

allocation in the notice of data 

availability issued under paragraph 

(a)(1) of this section does not operate, 

starting after 2011, during the control 

period in two consecutive years, such 

unit will not be allocated the TR SO2

Group 1 allowances provided in 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 


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allocated to the new unit set-aside for 

the State where such unit is located and 

for the respective years involved. If such 

unit resumes operation, the 

Administrator will allocate TR SO2

Group 1 allowances to the unit in 

accordance with paragraph (b) of this 

section. 

(b) New units. (1) New unit set-asides. 

(i) By June 1, 2012 and June 1 of each 

year thereafter, the Administrator will 

calculate the TR SO2 Group 1 allowance 

allocation to each TR SO2 Group 1 unit 

in a State, in accordance with 

§ 97.612(a)(2) through (7) and (12), for 

the control period in the year of the 

applicable calculation deadline under 

this paragraph and will promulgate a 

notice of data availability of the results 

of the calculations. 

(ii) For each notice of data availability 

required in paragraph (b)(1)(i) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. 

(A) Objections shall be submitted by 

the deadline specified in each notice of 

data availability required in paragraph 

(b)(1)(i) of this section and shall be 

limited to addressing whether the 

calculations (including the 

identification of the TR SO2 Group 1 

units) are in accordance with 

§ 97.612(a)(2) through (7) and (12) and 

§§ 97.606(b)(2) and 97.630 through 

97.635. 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(1)(ii)(A) of this section. By August 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(1)(i) of this section, the 

Administrator will promulgate a notice 

of data availability of any adjustments 

that the Administrator determines to be 

necessary with regard to allocations 

under § 97.612(a)(2) through (7) and (12) 

and the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(1)(ii)(A) 

of this section. 

(iii) If the new unit set-aside for such 

control period contains any TR SO2

Group 1 allowances that have not been 

allocated in the applicable notice of data 

availability required in paragraph 

(b)(1)(ii) of this section, the 

Administrator will promulgate, by 

December 15 immediately after such 

notice, a notice of data availability that 

identifies any TR SO2 Group 1 units that 

commenced commercial operation 

during the period starting January 1 of 

the year before the year of such control 

period and ending November 30 of year 

of such control period. 

(iv) For each notice of data 

availability required in paragraph 

(b)(1)(iii) of this section, the 

Administrator will provide an 

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 each notice of data availability 

required in paragraph (b)(1)(iii) of this 

section to the extent necessary to ensure 

that it is in accordance with paragraph 

(b)(1)(iii) of this section and will 

calculate the TR SO2 Group 1 allowance 

allocation to each TR SO2 Group 1 unit 

in accordance with § 97.612(a)(9), (10), 

and (12) and §§ 97.606(b)(2) and 97.630 

through 97.635. By February 15 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(1)(iii) of this section, 

the Administrator will promulgate a 

notice of data availability of any 

adjustments of the identification of TR 

SO2 Group 1 units that the 

Administrator determines to be 

necessary, the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(1)(iv)(A) 

of this section, and the results of such 

calculations. 

(v) To the extent any TR SO2 Group 

1 allowances are added to the new unit 

set-aside after promulgation of each 

notice of data availability required in 

paragraph (b)(1)(iv) of this section, the 

Administrator will promulgate 

additional notices of data availability, as 

deemed appropriate, of the allocation of 

such TR SO2 Group 1 allowances in 

accordance with § 97.612(a)(10). 

(2) Indian country new unit setasides. (i) By June 1, 2012 and June 1 

of each year thereafter, the 

Administrator will calculate the TR SO2

Group 1 allowance allocation to each TR 

SO2 Group 1 unit in Indian country 

within the borders of a State, in 

accordance with § 97.612(b)(2) through 

(7) and (12), for the control period in the 

year of the applicable calculation 

deadline under this paragraph and will 

promulgate a notice of data availability 

of the results of the calculations. 

(ii) For each notice of data availability 

required in paragraph (b)(2)(i) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. 

(A) Objections shall be submitted by 

the deadline specified in each notice of 

data availability required in paragraph 

(b)(2)(i) of this section and shall be 

limited to addressing whether the 

calculations (including the 

identification of the TR SO2 Group 1 

units) are in accordance with 

§ 97.612(b)(2) through (7) and (12) and 

§§ 97.606(b)(2) and 97.630 through 

97.635. 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(ii)(A) of this section. By August 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(2)(i) of this section, the 

Administrator will promulgate a notice 

of data availability of any adjustments 

that the Administrator determines to be 

necessary with regard to allocations 

under § 97.612(b)(2) through (7) and (12) 

and the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(2)(ii)(A) 

of this section. 

(iii) If the Indian country new unit 

set-aside for such control period 

contains any TR SO2 Group 1 

allowances that have not been allocated 

in the applicable notice of data 

availability required in paragraph 

(b)(2)(ii) of this section, the 

Administrator will promulgate, by 

December 15 immediately after such 

notice, a notice of data availability that 

identifies any TR SO2 Group 1 units that 

commenced commercial operation 

during the period starting January 1 of 

the year before the year of such control 

period and ending November 30 of year 

of such control period. 

(iv) For each notice of data 

availability required in paragraph 

(b)(2)(iii) of this section, the 

Administrator will provide an 

opportunity for submission of objections 

to the identification of TR SO2 annual 

units in such notice. 

(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 each notice of data availability 

required in paragraph (b)(2)(iii) of this 

section to the extent necessary to ensure 

that it is in accordance with paragraph 

(b)(2)(iii) of this section and will 

calculate the TR SO2 Group 1 allowance 

allocation to each TR SO2 Group 1 unit 

in accordance with § 97.612(b)(9), (10), 


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and (12) and §§ 97.606(b)(2) and 97.630 

through 97.635. By February 15 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(2)(iii) of this section, 

the Administrator will promulgate a 

notice of data availability of any 

adjustments of the identification of TR 

SO2 Group 1 units that the 

Administrator determines to be 

necessary, the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(2)(iv)(A) 

of this section, and the results of such 

calculations. 

(v) To the extent any TR SO2 Group 

1 allowances are added to the Indian 

country new unit set-aside after 

promulgation of each notice of data 

availability required in paragraph 

(b)(2)(iv) of this section, the 

Administrator will promulgate 

additional notices of data availability, as 

deemed appropriate, of the allocation of 

such TR NOX Annual allowances in 

accordance with § 97.612(b)(10). 

(c) Units incorrectly allocated TR SO2

Group 1 allowances. (1) For each control 

period in 2012 and thereafter, if the 

Administrator determines that TR SO2

Group 1 allowances were allocated 

under paragraph (a) of this section, or 

under a provision of a SIP revision 

approved under § 52.39(d), (e), or (f) of 

this chapter, where such control period 

and the recipient are covered by the 

provisions of paragraph (c)(1)(i) of this 

section or were allocated under 

§ 97.612(a)(2) through (7), (9), and (12) 

and (b)(2) through (7), (9), and (12), or 

under a provision of a SIP revision 

approved under § 52.39(e) or (f) of this 

chapter, where such control period and 

the recipient are covered by the 

provisions of paragraph (c)(1)(ii) of this 

section, then the Administrator will 

notify the designated representative of 

the recipient and will act in accordance 

with the procedures set forth in 

paragraphs (c)(2) through (5) of this 

section: 

(i)(A) The recipient is not actually a 

TR SO2 Group 1 unit under § 97.604 as 

of January 1, 2012 and is allocated TR 

SO2 Group 1 allowances for such 

control period or, in the case of an 

allocation under a provision of a SIP 

revision approved under § 52.39(d), (e), 

or (f) of this chapter, the recipient is not 

actually a TR SO2 Group 1 unit as of 

January 1, 2012 and is allocated TR SO2

Group 1 allowances for such control 

period that the SIP revision provides 

should be allocated only to recipients 

that are TR SO2 Group 1 units as of 

January 1, 2012; or 

(B) The recipient is not located as of 

January 1 of the control period in the 

State from whose SO2 Group 1 trading 

budget the TR SO2 Group 1 allowances 

allocated under paragraph (a) of this 

section, or under a provision of a SIP 

revision approved under § 52.39(d), (e), 

or (f) of this chapter, were allocated for 

such control period. 

(ii) The recipient is not actually a TR 

SO2 Group 1 unit under § 97.604 as of 

January 1 of such control period and is 

allocated TR SO2 Group 1 allowances 

for such control period or, in the case 

of an allocation under a provision of a 

SIP revision approved under § 52.39(d), 

(e), or (f) of this chapter, the recipient 

is not actually a TR SO2 Group 1 unit 

as of January 1 of such control period 

and is allocated TR SO2 Group 1 

allowances for such control period that 

the SIP revision provides should be 

allocated only to recipients that are TR 

SO2 Group 1 units as of January 1 of 

such control period. 

(2) Except as provided in paragraph 

(c)(3) or (4) of this section, the 

Administrator will not record such TR 

SO2 Group 1 allowances under § 97.621. 

(3) If the Administrator already 

recorded such TR SO2 Group 1 

allowances under § 97.621 and if the 

Administrator makes the determination 

under paragraph (c)(1) of this section 

before making deductions for the source 

that includes such recipient under 

§ 97.624(b) for such control period, then 

the Administrator will deduct from the 

account in which such TR SO2 Group 1 

allowances were recorded an amount of 

TR SO2 Group 1 allowances allocated 

for the same or a prior control period 

equal to the amount of such already 

recorded TR SO2 Group 1 allowances. 

The authorized account representative 

shall ensure that there are sufficient TR 

SO2 Group 1 allowances in such 

account for completion of the 

deduction. 

(4) If the Administrator already 

recorded such TR SO2 Group 1 

allowances under § 97.621 and if the 

Administrator makes the determination 

under paragraph (c)(1) of this section 

after making deductions for the source 

that includes such recipient under 

§ 97.624(b) for such control period, then 

the Administrator will not make any 

deduction to take account of such 

already recorded TR SO2 Group 1 

allowances. 

(5)(i) With regard to the TR SO2 Group 

1 allowances that are not recorded, or 

that are deducted as an incorrect 

allocation, in accordance with 

paragraphs (c)(2) and (3) of this section 

for a recipient under paragraph (c)(1)(i) 

of this section, the Administrator will: 

(A) Transfer such TR SO2 Group 1 

allowances to the new unit set-aside for 

such control period for the State from 

whose SO2 Group 1 trading budget the 

TR SO2 Group 1 allowances were 

allocated; or 

(B) If the State has a SIP revision 

approved under § 52.39(e) or (f) 

covering such control period, include 

such TR SO2 Group 1 allowances in the 

portion of the State SO2 Group 1 trading 

budget that may be allocated for such 

control period in accordance with such 

SIP revision. 

(ii) With regard to the TR SO2 Group 

1 allowances that were not allocated 

from the Indian country new unit setaside for such control period and that 

are not recorded, or that are deducted as 

an incorrect allocation, in accordance 

with paragraphs (c)(2) and (3) of this 

section for a recipient under paragraph 

(c)(1)(ii) of this paragraph, the 

Administrator will: 

(A) Transfer such TR SO2 Group 1 

allowances to the new unit set-aside for 

such control period; or 

(B) If the State has a SIP revision 

approved under § 52.39(e) or (f) 

covering such control period, include 

such TR SO2 Group 1 allowances in the 

portion of the State SO2 Group 1 trading 

budget that may be allocated for such 

control period in accordance with such 

SIP revision. 

(iii) With regard to the TR SO2 Group 

1 allowances that were allocated from 

the Indian country new unit set-aside 

for such control period and that are not 

recorded, or that are deducted as an 

incorrect allocation, in accordance with 

paragraphs (c)(2) and (3) of this section 

for a recipient under paragraph (c)(1)(ii) 

of this paragraph, the Administrator will 

transfer such TR SO2 Group 1 

allowances to the Indian country new 

unit set-aside for such control period. 

§ 97.612 TR SO2 Group 1 allowance 

allocations to new units. 

(a) For each control period in 2012 

and thereafter and for the TR SO2 Group 

1 units in each State, the Administrator 

will allocate TR SO2 Group 1 

allowances to the TR SO2 Group 1 units 

as follows: 

(1) The TR SO2 Group 1 allowances 

will be allocated to the following TR 

SO2 Group 1 units, except as provided 

in paragraph (a)(10) of this section: 

(i) TR SO2 Group 1 units that are not 

allocated an amount of TR SO2 Group 1 

allowances in the notice of data 

availability issued under § 97.611(a)(1); 

(ii) TR SO2 Group 1 units whose 

allocation of an amount of TR SO2

Group 1 allowances for such control 

period in the notice of data availability 

issued under § 97.611(a)(1) is covered 

by § 97.611(c)(2) or (3); 

(iii) TR SO2 Group 1 units that are 

allocated an amount of TR SO2 Group 1 

allowances for such control period in 


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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) For purposes of paragraph (a)(9) 

of this section, TR SO2 Group 1 units 

under § 97.611(c)(1)(ii) whose allocation 

of an amount of TR SO2 Group 1 

allowances for such control period in 

the notice of data availability issued 

under § 97.611(b)(1)(ii)(B) is covered by 

§ 97.611(c)(2) or (3). 

(2) The Administrator will establish a 

separate new unit set-aside for the State 

for each such control period. Each such 

new unit 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 

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 State after operating 

in another jurisdiction and for which 

the unit is not already allocated one or 

more TR SO2 Group 1 allowances; and 

(iv) For a unit described in paragraph 

(a)(1)(iii) of this section, the first control 

period after the control period in which 

the unit resumes operation. 

(4)(i) The allocation to each TR SO2

annual unit described in paragraph 

(a)(1)(i) through (iii) of this section and 

for each control period described in 

paragraph (a)(3) of this section will be 

an amount equal to the unit’s total tons 

of SO2 emissions during the 

immediately preceding control period. 

(ii) The Administrator will adjust the 

allocation amount in paragraph (a)(4)(i) 

in accordance with paragraphs (a)(5) 

through (7) and (12) of this section. 

(5) The Administrator will calculate 

the sum of the TR SO2 Group 1 

allowances determined for all such TR 

SO2 Group 1 units under paragraph 

(a)(4)(i) of this section in the State for 

such control period. 

(6) If the amount of TR SO2 Group 1 

allowances in the new unit 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 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 

§ 97.611(b)(1)(i) and (ii), of the amount 

of TR SO2 Group 1 allowances allocated 

under paragraphs (a)(2) through (7) and 

(12) of this section for such control 

period to each TR SO2 Group 1 unit 

eligible for such allocation. 

(9) If, after completion of the 

procedures under paragraphs (a)(5) 

through (8) of this section for such 

control period, any unallocated TR SO2

Group 1 allowances remain in the new 

unit set-aside for the State for such 

control period, the Administrator will 

allocate such TR SO2 Group 1 

allowances as follows— 

(i) The Administrator will determine, 

for each unit described in paragraph 

(a)(1) of this section that commenced 

commercial operation during the period 

starting January 1 of the year before the 

year of such control period and ending 

November 30 of year of such control 

period, the positive difference (if any) 

between the unit’s emissions during 

such control period and the amount of 

TR SO2 Group 1 allowances referenced 

in the notice of data availability 

required under § 97.611(b)(1)(ii) for the 

unit for such control period; 

(ii) The Administrator will determine 

the sum of the positive differences 

determined under paragraph (a)(9)(i) of 

this section; 

(iii) If the amount of unallocated TR 

SO2 Group 1 allowances remaining in 

the new unit set-aside for the State for 

such control period is greater than or 

equal to the sum determined under 

paragraph (a)(9)(ii) of this section, then 

the Administrator will allocate the 

amount of TR SO2 Group 1 allowances 

determined for each such TR SO2 Group 

1 unit under paragraph (a)(9)(i) of this 

section; and 

(iv) If the amount of unallocated TR 

SO2 Group 1 allowances remaining in 

the new unit set-aside for the State for 

such control period is less than the sum 

under paragraph (a)(9)(ii) of this section, 

then the Administrator will allocate to 

each such TR SO2 Group 1 unit the 

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 paragraphs (a)(9) and 

(12) 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 

to each TR SO2 Group 1 unit that is in 

the State, is allocated an amount of TR 

SO2 Group 1 allowances in the notice of 

data availability issued under 

§ 97.611(a)(1), and continues to be 

allocated TR SO2 Group 1 allowances 

for such control period in accordance 

with § 97.611(a)(2), an amount of TR 

SO2 Group 1 allowances equal to the 

following: The total amount of such 

remaining unallocated TR SO2 Group 1 

allowances in such new unit set-aside, 

multiplied by the unit’s allocation 

under § 97.611(a) for such control 

period, divided by the remainder of the 

amount of tons in the applicable State 

SO2 Group 1 trading budget minus the 

sum of the amounts of tons in such new 

unit set-aside and the Indian country 

new unit set-aside for the State for such 

control period, and rounded to the 

nearest allowance. 

(11) The Administrator will notify the 

public, through the promulgation of the 

notices of data availability described in 

§ 97.611(b)(1)(iii), (iv), and (v), of the 

amount of TR SO2 Group 1 allowances 

allocated under paragraphs (a)(9), (10), 

and (12) of this section for such control 

period to each TR SO2 Group 1 unit 

eligible for such allocation. 

(12)(i) Notwithstanding the 

requirements of paragraphs (a)(2) 

through (11) of this section, if the 

calculations of allocations of a new unit 

set-aside for a control period in a given 

year under paragraph (a)(7) of this 

section, paragraphs (a)(6) and (9)(iv) of 

this section, or paragraphs (a)(6), (9)(iii), 

and (10) of this section would otherwise 

result in total allocations of such new 

unit set-aside exceeding the total 

amount of such new unit set-aside, then 


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the Administrator will adjust the results 

of the calculations under paragraph 

(a)(7), (9)(iv), or (10) of this section, as 

applicable, as follows. The 

Administrator will list the TR SO2

Group 1 units in descending order based 

on the amount of such units’ allocations 

under paragraph (a)(7), (9)(iv), or (10) of 

this section, as applicable, and, in cases 

of equal allocation amounts, in 

alphabetical order of the relevant 

source’s name and numerical order of 

the relevant unit’s identification 

number, and will reduce each unit’s 

allocation under paragraph (a)(7), 

(9)(iv), or (10) of this section, as 

applicable, by one TR SO2 Group 1 

allowance (but not below zero) in the 

order in which the units are listed and 

will repeat this reduction process as 

necessary, until the total allocations of 

such new unit set-aside equal the total 

amount of such new unit set-aside. 

(ii) Notwithstanding the requirements 

of paragraphs (a)(10) and (11) of this 

section, if the calculations of allocations 

of a new unit set-aside for a control 

period in a given year under paragraphs 

(a)(6), (9)(iii), and (10) of this section 

would otherwise result in a total 

allocations of such new unit set-aside 

less than the total amount of such new 

unit set-aside, then the Administrator 

will adjust the results of the calculations 

under paragraph (a)(10) of this section, 

as follows. The Administrator will list 

the TR SO2 Group 1 units in descending 

order based on the amount of such 

units’ allocations under paragraph 

(a)(10) of this section and, in cases of 

equal allocation amounts, in 

alphabetical order of the relevant 

source’s name and numerical order of 

the relevant unit’s identification 

number, and will increase each unit’s 

allocation under paragraph (a)(10) of 

this section by one TR SO2 Group 1 

allowance in the order in which the 

units are listed and will repeat this 

increase process as necessary, until the 

total allocations of such new unit setaside equal the total amount of such 

new unit set-aside. 

(b) For each control period in 2012 

and thereafter and for the TR SO2 Group 

1 units located in Indian country within 

the borders of each State, the 

Administrator will allocate TR SO2

Group 1 allowances to the TR SO2

Group 1 units as follows: 

(1) The TR SO2 Group 1 allowances 

will be allocated to the following TR 

SO2 Group 1 units, except as provided 

in paragraph (b)(10) of this section: 

(i) TR SO2 Group 1 units that are not 

allocated an amount of TR SO2 Group 1 

allowances in the notice of data 

availability issued under § 97.611(a)(1); 

or 

(ii) For purposes of paragraph (b)(9) of 

this section, TR SO2 Group 1 units 

under § 97.611(c)(1)(ii) whose allocation 

of an amount of TR SO2 Group 1 

allowances for such control period in 

the notice of data availability issued 

under § 97.611(b)(2)(ii)(B) is covered by 

§ 97.611(c)(2) or (3). 

(2) The Administrator will establish a 

separate Indian country new unit setaside for the State for each such control 

period. Each such Indian country new 

unit set-aside will be allocated TR SO2

Group 1 allowances in an amount equal 

to the applicable amount of tons of SO2

emissions as set forth in § 97.610(a) and 

will be allocated additional TR SO2

Group 1 allowances (if any) in 

accordance with § 97.611(c)(5). 

(3) The Administrator will determine, 

for each TR SO2 Group 1 unit described 

in paragraph (b)(1) of this section, an 

allocation of TR SO2 Group 1 

allowances for the later of the following 

control periods and for each subsequent 

control period: 

(i) The control period in 2012; and 

(ii) The first control period after the 

control period in which the TR SO2

Group 1 unit commences commercial 

operation. 

(4)(i) The allocation to each TR SO2

annual unit described in paragraph 

(b)(1)(i) of this section and for each 

control period described in paragraph 

(b)(3) of this section will be an amount 

equal to the unit’s total tons of SO2

emissions during the immediately 

preceding control period. 

(ii) The Administrator will adjust the 

allocation amount in paragraph (b)(4)(i) 

in accordance with paragraphs (b)(5) 

through (7) and (12) of this section. 

(5) The Administrator will calculate 

the sum of the TR SO2 Group 1 

allowances determined for all such TR 

SO2 Group 1 units under paragraph 

(b)(4)(i) of this section in Indian country 

within the borders of the State for such 

control period. 

(6) If the amount of TR SO2 Group 1 

allowances in the Indian country new 

unit set-aside for the State for such 

control period is greater than or equal to 

the sum under paragraph (b)(5) of this 

section, then the Administrator will 

allocate the amount of TR SO2 Group 1 

allowances determined for each such TR 

SO2 Group 1 unit under paragraph 

(b)(4)(i) of this section. 

(7) If the amount of TR SO2 Group 1 

allowances in the Indian country new 

unit set-aside for the State for such 

control period is less than the sum 

under paragraph (b)(5) of this section, 

then the Administrator will allocate to 

each such TR SO2 Group 1 unit the 

amount of the TR SO2 Group 1 

allowances determined under paragraph 

(b)(4)(i) of this section for the unit, 

multiplied by the amount of TR SO2

Group 1 allowances in the Indian 

country new unit set-aside for such 

control period, divided by the sum 

under paragraph (b)(5) of this section, 

and rounded to the nearest allowance. 

(8) The Administrator will notify the 

public, through the promulgation of the 

notices of data availability described in 

§ 97.611(b)(2)(i) and (ii), of the amount 

of TR SO2 Group 1 allowances allocated 

under paragraphs (b)(2) through (7) and 

(12) of this section for such control 

period to each TR SO2 Group 1 unit 

eligible for such allocation. 

(9) If, after completion of the 

procedures under paragraphs (b)(5) 

through (8) of this section for such 

control period, any unallocated TR SO2

Group 1 allowances remain in the 

Indian country new unit 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 referenced 

in the notice of data availability 

required under § 97.611(b)(2)(ii) for the 

unit for such control period; 

(ii) The Administrator will determine 

the sum of the positive differences 

determined under paragraph (b)(9)(i) of 

this section; 

(iii) If the amount of unallocated TR 

SO2 Group 1 allowances remaining in 

the Indian country new unit set-aside 

for the State for such control period is 

greater than or equal to the sum 

determined under paragraph (b)(9)(ii) of 

this section, then the Administrator will 

allocate the amount of TR SO2 Group 1 

allowances determined for each such TR 

SO2 Group 1 unit under paragraph 

(b)(9)(i) of this section; and 

(iv) If the amount of unallocated TR 

SO2 Group 1 allowances remaining in 

the Indian country new unit set-aside 

for the State for such control period is 

less than the sum under paragraph 

(b)(9)(ii) of this section, then the 

Administrator will allocate to each such 

TR SO2 Group 1 unit the amount of the 

TR SO2 Group 1 allowances determined 

under paragraph (b)(9)(i) of this section 

for the unit, multiplied by the amount 

of unallocated TR SO2 Group 1 

allowances remaining in the Indian 

country new unit set-aside for such 

control period, divided by the sum 


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under paragraph (b)(9)(ii) of this section, 

and rounded to the nearest allowance. 

(10) If, after completion of the 

procedures under paragraphs (b)(9) and 

(12) of this section for such control 

period, any unallocated TR SO2 Group 

1 allowances remain in the Indian 

country new unit set-aside for the State 

for such control period, the 

Administrator will: 

(i) Transfer such unallocated TR SO2

Group 1 allowances to the new unit setaside for the State for such control 

period; or 

(ii) If the State has a SIP revision 

approved under § 52.39(d), (e), or (f) of 

this chapter covering such control 

period, include such unallocated TR 

SO2 Group 1 allowances in the portion 

of the State SO2 Group 1 trading budget 

that may be allocated for such control 

period in accordance with such SIP 

revision. 

(11) The Administrator will notify the 

public, through the promulgation of the 

notices of data availability described in 

§ 97.611(b)(2)(iii), (iv), and (v), of the 

amount of TR SO2 Group 1 allowances 

allocated under paragraphs (b)(9), (10), 

and (12) for such control period to each 

TR SO2 Group 1 unit eligible for such 

allocation. 

(12)(i) Notwithstanding the 

requirements of paragraphs (b)(2) 

through (11) of this section, if the 

calculations of allocations of an Indian 

country new unit set-aside for a control 

period in a given year under paragraph 

(b)(7) of this section, paragraphs (b)(6) 

and (9)(iv) of this section, or paragraphs 

(b)(6), (9)(iii), and (10) of this section 

would otherwise result in total 

allocations of such Indian country new 

unit set-aside exceeding the total 

amount of such Indian country new unit 

set-aside, then the Administrator will 

adjust the results of the calculations 

under paragraph (b)(7), (9)(iv), or (10) of 

this section, as applicable, as follows. 

The Administrator will list the TR SO2

Group 1 units in descending order based 

on the amount of such units’ allocations 

under paragraph (b)(7), (9)(iv), or (10) of 

this section, as applicable, and, in cases 

of equal allocation amounts, in 

alphabetical order of the relevant 

source’s name and numerical order of 

the relevant unit’s identification 

number, and will reduce each unit’s 

allocation under paragraph (b)(7), 

(9)(iv), or (10) of this section, as 

applicable, by one TR SO2 Group 1 

allowance (but not below zero) in the 

order in which the units are listed and 

will repeat this reduction process as 

necessary, until the total allocations of 

such Indian country new unit set-aside 

equal the total amount of such Indian 

country new unit set-aside. 

(ii) Notwithstanding the requirements 

of paragraphs (b)(10) and (11) of this 

section, if the calculations of allocations 

of an Indian country new unit set-aside 

for a control period in a given year 

under paragraphs (b)(6), (9)(iii), and (10) 

of this section would otherwise result in 

a total allocations of such Indian 

country new unit set-aside less than the 

total amount of such Indian country 

new unit set-aside, then the 

Administrator will adjust the results of 

the calculations under paragraph (b)(10) 

of this section, as follows. The 

Administrator will list the TR SO2

Group 1 units in descending order based 

on the amount of such units’ allocations 

under paragraph (b)(10) of this section 

and, in cases of equal allocation 

amounts, in alphabetical order of the 

relevant source’s name and numerical 

order of the relevant unit’s 

identification number, and will increase 

each unit’s allocation under paragraph 

(b)(10) of this section by one TR SO2

Group 1 allowance in the order in 

which the units are listed and will 

repeat this increase process as 

necessary, until the total allocations of 

such Indian country new unit set-aside 

equal the total amount of such Indian 

country new unit set-aside. 

§ 97.613 Authorization of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.615, 

each TR SO2 Group 1 source, including 

all TR SO2 Group 1 units at the source, 

shall have one and only one designated 

representative, with regard to all matters 

under the TR SO2 Group 1 Trading 

Program. 

(1) The designated representative 

shall be selected by an agreement 

binding on the owners and operators of 

the source and all TR SO2 Group 1 units 

at the source and shall act in accordance 

with the certification statement in 

§ 97.616(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.616: 

(i) The designated representative shall 

be authorized and shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each owner and operator of the source 

and each TR SO2 Group 1 unit at the 

source in all matters pertaining to the 

TR SO2 Group 1 Trading Program, 

notwithstanding any agreement between 

the designated representative and such 

owners and operators; and 

(ii) The owners and operators of the 

source and each TR SO2 Group 1 unit 

at the source shall be bound by any 

decision or order issued to the 

designated representative by the 

Administrator regarding the source or 

any such unit. 

(b) Except as provided under § 97.615, 

each TR SO2 Group 1 source may have 

one and only one alternate designated 

representative, who may act on behalf of 

the designated representative. The 

agreement by which the alternate 

designated representative is selected 

shall include a procedure for 

authorizing the alternate designated 

representative to act in lieu of the 

designated representative. 

(1) The alternate designated 

representative shall be selected by an 

agreement binding on the owners and 

operators of the source and all TR SO2

Group 1 units at the source and shall act 

in accordance with the certification 

statement in § 97.616(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.616, 

(i) The alternate designated 

representative shall be authorized; 

(ii) Any representation, action, 

inaction, or submission by the alternate 

designated representative shall be 

deemed to be a representation, action, 

inaction, or submission by the 

designated representative; and 

(iii) The owners and operators of the 

source and each TR SO2 Group 1 unit 

at the source shall be bound by any 

decision or order issued to the alternate 

designated representative by the 

Administrator regarding the source or 

any such unit. 

(c) Except in this section, § 97.602, 

and §§ 97.614 through 97.618, whenever 

the term ‘‘designated representative’’ (as 

distinguished from the term ‘‘common 

designated representative’’) is used in 

this subpart, the term shall be construed 

to include the designated representative 

or any alternate designated 

representative. 

§ 97.614 Responsibilities of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.618 

concerning delegation of authority to 

make submissions, each submission 

under the TR SO2 Group 1 Trading 

Program shall be made, signed, and 

certified by the 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 


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penalty of law that I have personally 

examined, and am familiar with, the 

statements and information submitted 

in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(b) The Administrator will accept or 

act on a submission made for a TR SO2

Group 1 source or a TR SO2 Group 1 

unit only if the submission has been 

made, signed, and certified in 

accordance with paragraph (a) of this 

section and § 97.618. 

§ 97.615 Changing designated 

representative and alternate designated 

representative; changes in owners and 

operators; changes in units at the source. 

(a) Changing designated 

representative. The designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.616. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous designated 

representative before the time and date 

when the Administrator receives the 

superseding certificate of representation 

shall be binding on the new designated 

representative and the owners and 

operators of the TR SO2 Group 1 source 

and the TR SO2 Group 1 units at the 

source. 

(b) Changing alternate designated 

representative. The alternate designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.616. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous alternate 

designated representative before the 

time and date when the Administrator 

receives the superseding certificate of 

representation shall be binding on the 

new alternate designated representative, 

the designated representative, and the 

owners and operators of the TR SO2

Group 1 source and the TR SO2 Group 

1 units at the source. 

(c) Changes in owners and operators. 

(1) In the event an owner or operator of 

a TR SO2 Group 1 source or a TR SO2

Group 1 unit at the source is not 

included in the list of owners and 

operators in the certificate of 

representation under § 97.616, such 

owner or operator shall be deemed to be 

subject to and bound by the certificate 

of representation, the representations, 

actions, inactions, and submissions of 

the designated representative and any 

alternate designated representative of 

the source or unit, and the decisions 

and orders of the Administrator, as if 

the owner or operator were included in 

such list. 

(2) Within 30 days after any change in 

the owners and operators of a TR SO2

Group 1 source or a TR SO2 Group 1 

unit at the source, including the 

addition or removal of an owner or 

operator, the designated representative 

or any alternate designated 

representative shall submit a revision to 

the certificate of representation under 

§ 97.616 amending the list of owners 

and operators to reflect the change. 

(d) Changes in units at the source. 

Within 30 days of any change in which 

units are located at a TR SO2 Group 1 

source (including the addition or 

removal of a unit), the designated 

representative or any alternate 

designated representative shall submit a 

certificate of representation under 

§ 97.616 amending the list of units to 

reflect the change. 

(1) If the change is the addition of a 

unit that operated (other than for 

purposes of testing by the manufacturer 

before initial installation) before being 

located at the source, then the certificate 

of representation shall identify, in a 

format prescribed by the Administrator, 

the entity from whom the unit was 

purchased or otherwise obtained 

(including name, address, telephone 

number, and facsimile number (if any)), 

the date on which the unit was 

purchased or otherwise obtained, and 

the date on which the unit became 

located at the source. 

(2) If the change is the removal of a 

unit, then the certificate of 

representation shall identify, in a format 

prescribed by the Administrator, the 

entity to which the unit was sold or that 

otherwise obtained the unit (including 

name, address, telephone number, and 

facsimile number (if any)), the date on 

which the unit was sold or otherwise 

obtained, and the date on which the 

unit became no longer located at the 

source. 

§ 97.616 Certificate of representation. 

(a) A complete certificate of 

representation for a designated 

representative or an alternate designated 

representative shall include the 

following elements in a format 

prescribed by the Administrator: 

(1) Identification of the TR SO2 Group 

1 source, and each TR SO2 Group 1 unit 

at the source, for which the certificate 

of representation is submitted, 

including source name, source category 

and NAICS code (or, in the absence of 

a NAICS code, an equivalent code), 

State, plant code, county, latitude and 

longitude, unit identification number 

and type, identification number and 

nameplate capacity (in MWe, rounded 

to the nearest tenth) of each generator 

served by each such unit, actual or 

projected date of commencement of 

commercial operation, and a statement 

of whether such source is located in 

Indian Country. If a projected date of 

commencement of commercial 

operation is provided, the actual date of 

commencement of commercial 

operation shall be provided when such 

information becomes available. 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the designated representative and any 

alternate designated representative. 

(3) A list of the owners and operators 

of the TR SO2 Group 1 source and of 

each TR SO2 Group 1 unit at the source. 

(4) The following certification 

statements by the designated 

representative and any alternate 

designated representative— 

(i) ‘‘I certify that I was selected as the 

designated representative or alternate 

designated representative, as applicable, 

by an agreement binding on the owners 

and operators of the source and each TR 

SO2 Group 1 unit at the source.’’ 

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the TR 

SO2 Group 1 Trading Program on behalf 

of the owners and operators of the 

source and of each TR SO2 Group 1 unit 

at the source and that each such owner 

and operator shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any decision or 

order issued to me by the Administrator 

regarding the source or unit.’’ 

(iii) ‘‘Where there are multiple 

holders of a legal or equitable title to, or 

a leasehold interest in, a TR SO2 Group 

1 unit, or where a utility or industrial 

customer purchases power from a TR 

SO2 Group 1 unit under a life-of-theunit, firm power contractual 

arrangement, I certify that: I have given 

a written notice of my selection as the 

‘designated representative’ or ‘alternate 

designated representative’, as 

applicable, and of the agreement by 

which I was selected to each owner and 

operator of the source and of each TR 

SO2 Group 1 unit at the source; and TR 

SO2 Group 1 allowances and proceeds 

of transactions involving TR SO2 Group 

1 allowances will be deemed to be held 

or distributed in proportion to each 


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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 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 

disputes concerning the proceeds of TR 

SO2 Group 1 allowance transfers. 

§ 97.618 Delegation by designated 

representative and alternate designated 

representative. 

(a) A designated representative may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(b) An alternate designated 

representative may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(c) In order to delegate authority to a 

natural person to make an electronic 

submission to the Administrator in 

accordance with paragraph (a) or (b) of 

this section, the designated 

representative or alternate designated 

representative, as appropriate, must 

submit to the Administrator a notice of 

delegation, in a format prescribed by the 

Administrator, that includes the 

following elements: 

(1) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of such 

designated representative or alternate 

designated representative; 

(2) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of each 

such natural person (referred to in this 

section as an ‘‘agent’’); 

(3) For each such natural person, a list 

of the type or types of electronic 

submissions under paragraph (a) or (b) 

of this section for which authority is 

delegated to him or her; and 

(4) The following certification 

statements by such designated 

representative or alternate designated 

representative: 

(i) ‘‘I agree that any electronic 

submission to the Administrator that is 

made by an agent identified in this 

notice of delegation and of a type listed 

for such agent in this notice of 

delegation and that is made when I am 

a designated representative or alternate 

designated representative, as 

appropriate, and before this notice of 

delegation is superseded by another 

notice of delegation under 40 CFR 

97.618(d) shall be deemed to be an 

electronic submission by me.’’ 

(ii) ‘‘Until this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 97.618(d), I 

agree to maintain an e-mail account and 

to notify the Administrator immediately 

of any change in my e-mail address 

unless all delegation of authority by me 

under 40 CFR 97.618 is terminated.’’. 

(d) A notice of delegation submitted 

under paragraph (c) of this section shall 

be effective, with regard to the 

designated representative or alternate 

designated representative identified in 

such notice, upon receipt of such notice 

by the Administrator and until receipt 

by the Administrator of a superseding 

notice of delegation submitted by such 

designated representative or alternate 

designated representative, as 

appropriate. The superseding notice of 

delegation may replace any previously 

identified agent, add a new agent, or 

eliminate entirely any delegation of 

authority. 

(e) Any electronic submission covered 

by the certification in paragraph (c)(4)(i) 

of this section and made in accordance 

with a notice of delegation effective 

under paragraph (d) of this section shall 

be deemed to be an electronic 

submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

§ 97.619 [Reserved] 

§ 97.620 Establishment of compliance 

accounts, assurance accounts, and general 

accounts. 

(a) Compliance accounts. Upon 

receipt of a complete certificate of 

representation under § 97.616, the 

Administrator will establish a 

compliance account for the TR SO2

Group 1 source for which the certificate 

of representation was submitted, unless 

the source already has a compliance 

account. The designated representative 

and any alternate designated 

representative of the source shall be the 

authorized account representative and 

the alternate authorized account 

representative respectively of the 

compliance account. 

(b) Assurance accounts. The 

Administrator will establish assurance 

accounts for certain owners and 

operators and States in accordance with 

§ 97.625(b)(3). 

(c) General accounts. (1) Application 

for general account. (i) Any person may 

apply to open a general account, for the 

purpose of holding and transferring TR 

SO2 Group 1 allowances, by submitting 

to the Administrator a complete 

application for a general account. Such 

application shall designate one and only 

one authorized account representative 

and may designate one and only one 

alternate authorized account 

representative who may act on behalf of 

the authorized account representative. 

(A) The authorized account 

representative and alternate authorized 

account representative shall be selected 

by an agreement binding on the persons 

who have an ownership interest with 

respect to TR SO2 Group 1 allowances 

held in the general account. 

(B) The agreement by which the 

alternate authorized account 

representative is selected shall include 

a procedure for authorizing the alternate 

authorized account representative to act 

in lieu of the authorized account 

representative. 

(ii) A complete application for a 

general account shall include the 


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following elements in a format 

prescribed by the Administrator: 

(A) Name, mailing address, e-mail 

address (if any), telephone number, and 

facsimile transmission number (if any) 

of the authorized account representative 

and any alternate authorized account 

representative; 

(B) An identifying name for the 

general account; 

(C) A list of all persons subject to a 

binding agreement for the authorized 

account representative and any alternate 

authorized account representative to 

represent their ownership interest with 

respect to the TR SO2 Group 1 

allowances held in the general account; 

(D) The following certification 

statement by the authorized account 

representative and any alternate 

authorized account representative: ‘‘I 

certify that I was selected as the 

authorized account representative or the 

alternate authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to TR SO2 Group 1 allowances 

held in the general account. I certify that 

I have all the necessary authority to 

carry out my duties and responsibilities 

under the TR SO2 Group 1 Trading 

Program on behalf of such persons and 

that each such person shall be fully 

bound by my representations, actions, 

inactions, or submissions and by any 

decision or order issued to me by the 

Administrator regarding the general 

account.’’ 

(E) The signature of the authorized 

account representative and any alternate 

authorized account representative and 

the dates signed. 

(iii) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the application for a 

general account shall not be submitted 

to the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

(2) Authorization of authorized 

account representative and alternate 

authorized account representative. (i) 

Upon receipt by the Administrator of a 

complete application for a general 

account under paragraph (b)(1) of this 

section, the Administrator will establish 

a general account for the person or 

persons for whom the application is 

submitted, and upon and after such 

receipt by the Administrator: 

(A) The authorized account 

representative of the general account 

shall be authorized and shall represent 

and, by his or her representations, 

actions, inactions, or submissions, 

legally bind each person who has an 

ownership interest with respect to TR 

SO2 Group 1 allowances held in the 

general account in all matters pertaining 

to the TR SO2 Group 1 Trading Program, 

notwithstanding any agreement between 

the authorized account representative 

and such person. 

(B) Any alternate authorized account 

representative shall be authorized, and 

any representation, action, inaction, or 

submission by any alternate authorized 

account representative shall be deemed 

to be a representation, action, inaction, 

or submission by the authorized account 

representative. 

(C) Each person who has an 

ownership interest with respect to TR 

SO2 Group 1 allowances held in the 

general account shall be bound by any 

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, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(iii) Except in this section, whenever 

the term ‘‘authorized account 

representative’’ is used in this subpart, 

the term shall be construed to include 

the authorized account representative or 

any alternate authorized account 

representative. 

(3) Changing authorized account 

representative and alternate authorized 

account representative; changes in 

persons with ownership interest. (i) The 

authorized account representative of a 

general account may be changed at any 

time upon receipt by the Administrator 

of a superseding complete application 

for a general account under paragraph 

(c)(1) of this section. Notwithstanding 

any such change, all representations, 

actions, inactions, and submissions by 

the previous authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

authorized account representative and 

the persons with an ownership interest 

with respect to the TR SO2 Group 1 

allowances in the general account. 

(ii) The alternate authorized account 

representative of a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (c)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous alternate authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

alternate authorized account 

representative, the authorized account 

representative, and the persons with an 

ownership interest with respect to the 

TR SO2 Group 1 allowances in the 

general account. 

(iii)(A) In the event a person having 

an ownership interest with respect to 

TR SO2 Group 1 allowances in the 

general account is not included in the 

list of such persons in the application 

for a general account, such person shall 

be deemed to be subject to and bound 

by the application for a general account, 

the representation, actions, inactions, 

and submissions of the authorized 

account representative and any alternate 

authorized account representative of the 

account, and the decisions and orders of 

the Administrator, as if the person were 

included in such list. 

(B) Within 30 days after any change 

in the persons having an ownership 

interest with respect to SO2 Group 1 

allowances in the general account, 

including the addition or removal of a 

person, the authorized account 

representative or any alternate 

authorized account representative shall 

submit a revision to the application for 

a general account amending the list of 

persons having an ownership 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 


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authorized account representative. (i) 

Once a complete application for a 

general account under paragraph (c)(1) 

of this section has been submitted and 

received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section is received by the 

Administrator. 

(ii) Except as provided in paragraph 

(c)(4)(i) of this section, no objection or 

other communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission of the 

authorized account representative or 

any alternate authorized account 

representative of a general account shall 

affect any representation, action, 

inaction, or submission of the 

authorized account representative or 

any alternate authorized account 

representative or the finality of any 

decision or order by the Administrator 

under the TR SO2 Group 1 Trading 

Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account, including private legal 

disputes concerning the proceeds of TR 

SO2 Group 1 allowance transfers. 

(5) Delegation by authorized account 

representative and alternate authorized 

account representative. (i) An 

authorized account representative of a 

general account may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(ii) An alternate authorized account 

representative of a general account may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(iii) In order to delegate authority to 

a natural person to make an electronic 

submission to the Administrator in 

accordance with paragraph (c)(5)(i) or 

(ii) of this section, the authorized 

account representative or alternate 

authorized account representative, as 

appropriate, must submit to the 

Administrator a notice of delegation, in 

a format prescribed by the 

Administrator, that includes the 

following elements: 

(A) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of such authorized account 

representative or alternate authorized 

account representative; 

(B) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of each such natural person (referred to 

in this section as an ‘‘agent’’); 

(C) For each such natural person, a 

list of the type or types of electronic 

submissions under paragraph (c)(5)(i) or 

(ii) of this section for which authority is 

delegated to him or her; 

(D) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘I agree that any 

electronic submission to the 

Administrator that is made by an agent 

identified in this notice of delegation 

and of a type listed for such agent in 

this notice of delegation and that is 

made when I am an authorized account 

representative or alternate authorized 

representative, as appropriate, and 

before this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 97.620(c)(5)(iv) 

shall be deemed to be an electronic 

submission by me.’’; and 

(E) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘Until this 

notice of delegation is superseded by 

another notice of delegation under 40 

CFR 97.620(c)(5)(iv), I agree to maintain 

an 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. 

(v) Any electronic submission covered 

by the certification in paragraph 

(c)(5)(iii)(D) of this section and made in 

accordance with a notice of delegation 

effective under paragraph (c)(5)(iv) of 

this section shall be deemed to be an 

electronic submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

(6) Closing a general account. (i) The 

authorized account representative or 

alternate authorized account 

representative of a general account may 

submit to the Administrator a request to 

close the account. Such request shall 

include a correctly submitted TR SO2

Group 1 allowance transfer under 

§ 97.622 for any TR SO2 Group 1 

allowances in the account to one or 

more other Allowance Management 

System accounts. 

(ii) If a general account has no TR SO2

Group 1 allowance transfers to or from 

the account for a 12-month period or 

longer and does not contain any TR SO2

Group 1 allowances, the Administrator 

may notify the authorized account 

representative for the account that the 

account will be closed after 30 days 

after the notice is sent. The account will 

be closed after the 30-day period unless, 

before the end of the 30-day period, the 

Administrator receives a correctly 

submitted TR SO2 Group 1 allowance 

transfer under § 97.622 to the account or 

a statement submitted by the authorized 

account representative or alternate 

authorized account representative 

demonstrating to the satisfaction of the 

Administrator good cause as to why the 

account should not be closed. 

(d) Account identification. The 

Administrator will assign a unique 

identifying number to each account 

established under paragraph (a), (b), or 

(c) of this section. 

(e) Responsibilities of authorized 

account representative and alternate 

authorized account representative. After 

the establishment of a compliance 

account or general account, the 

Administrator will accept or act on a 

submission pertaining to the account, 

including, but not limited to, 

submissions concerning the deduction 

or transfer of TR SO2 Group 1 

allowances in the account, only if the 

submission has been made, signed, and 

certified in accordance with §§ 97.614(a) 

and 97.618 or paragraphs (c)(2)(ii) and 

(c)(5) of this section. 

§ 97.621 Recordation of TR SO2 Group 1 

allowance allocations and auction results. 

(a) By November 7, 2011, the 

Administrator will record in each TR 

SO2 Group 1 source’s compliance 

account the TR SO2 Group 1 allowances 

allocated to the TR SO2 Group 1 units 

at the source in accordance with 

§ 97.611(a) for the control period in 

2012. 

(b) By November 7, 2011, 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 


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§ 97.611(a) for the control period in 

2013, unless the State in which the 

source is located notifies the 

Administrator in writing by October 17, 

2011 of the State’s intent to submit to 

the Administrator a complete SIP 

revision by April 1, 2012 meeting the 

requirements of § 52.39(d)(1) through (4) 

of this chapter. 

(1) If, by April 1, 2012, the State does 

not submit to the Administrator such 

complete SIP revision, the 

Administrator will record by April 15, 

2012 in each TR SO2 Group 1 source’s 

compliance account the TR SO2 Group 

1 allowances allocated to the TR SO2

Group 1 units at the source in 

accordance with § 97.611(a) for the 

control period in 2013. 

(2) If the State submits to the 

Administrator by April 1, 2012, and the 

Administrator approves by October 1, 

2012, such complete SIP revision, the 

Administrator will record by October 1, 

2012 in each TR SO2 Group 1 source’s 

compliance account the TR SO2 Group 

1 allowances allocated to the TR SO2

Group 1 units at the source as provided 

in such approved, complete SIP revision 

for the control period in 2013. 

(3) If the State submits to the 

Administrator by April 1, 2012, and the 

Administrator does not approve by 

October 1, 2012, such complete SIP 

revision, the Administrator will record 

by October 1, 2012 in each TR SO2

Group 1 source’s compliance account 

the TR SO2 Group 1 allowances 

allocated to the TR SO2 Group 1 units 

at the source in accordance with 

§ 97.611(a) for the control period in 

2013. 

(c) By July 1, 2013, the Administrator 

will record in each TR SO2 Group 1 

source’s compliance account the TR SO2

Group 1 allowances allocated to the TR 

SO2 Group 1 units at the source, or in 

each appropriate Allowance 

Management System account the TR 

SO2 Group 1 allowances auctioned to 

TR SO2 Group 1 units, in accordance 

with § 97.611(a), or with a SIP revision 

approved under § 52.39(e) or (f) of this 

chapter, for the control period in 2014 

and 2015. 

(d) By July 1, 2014, the Administrator 

will record in each TR SO2 Group 1 

source’s compliance account the TR SO2

Group 1 allowances allocated to the TR 

SO2 Group 1 units at the source, or in 

each appropriate Allowance 

Management System account the TR 

SO2 Group 1 allowances auctioned to 

TR SO2 Group 1 units, in accordance 

with § 97.611(a), or with a SIP revision 

approved under § 52.39(e) or (f) of this 

chapter, for the control period in 2016 

and 2017. 

(e) By July 1, 2015, the Administrator 

will record in each TR SO2 Group 1 

source’s compliance account the TR SO2

Group 1 allowances allocated to the TR 

SO2 Group 1 units at the source, or in 

each appropriate Allowance 

Management System account the TR 

SO2 Group 1 allowances auctioned to 

TR SO2 Group 1 units, in accordance 

with § 97.611(a), or with a SIP revision 

approved under § 52.39(e) or (f) of this 

chapter, for the control period in 2018 

and 2019. 

(f) By July 1, 2016 and July 1 of each 

year thereafter, the Administrator will 

record in each TR SO2 Group 1 source’s 

compliance account the TR SO2 Group 

1 allowances allocated to the TR SO2

Group 1 units at the source, or in each 

appropriate Allowance Management 

System account the TR SO2 Group 1 

allowances auctioned to TR SO2 Group 

1 units, in accordance with § 97.611(a), 

or with a SIP revision approved under 

§ 52.39(e) and (f) of this chapter, for the 

control period in the fourth year after 

the year of the applicable recordation 

deadline under this paragraph. 

(g) By August 1, 2012 and August 1 

of each year thereafter, the 

Administrator will record in each TR 

SO2 Group 1 source’s compliance 

account the TR SO2 Group 1 allowances 

allocated to the TR SO2 Group 1 units 

at the source, or in each appropriate 

Allowance Management System account 

the TR SO2 Group 1 allowances 

auctioned to TR SO2 Group 1 units, in 

accordance with § 97.612(a)(2) through 

(8) and (12), or with a SIP revision 

approved under § 52.39(e) and (f) of this 

chapter, for the control period in the 

year of the applicable recordation 

deadline under this paragraph. 

(h) By August 1, 2012 and August 1 

of each year thereafter, the 

Administrator will record in each TR 

SO2 Group 1 source’s compliance 

account the TR SO2 Group 1 allowances 

allocated to the TR SO2 Group 1 units 

at the source in accordance with 

§ 97.612(b)(2) through (8) and (12) for 

the control period in the year of the 

applicable recordation deadline under 

this paragraph. 

(i) By February 15, 2013 and February 

15 of each year thereafter, the 

Administrator will record in each TR 

SO2 Group 1 source’s compliance 

account the TR SO2 Group 1 allowances 

allocated to the TR SO2 Group 1 units 

at the source in accordance with 

§ 97.612(a)(9) through (12), for the 

control period in the year before the 

year of the applicable recordation 

deadline under this paragraph. 

(j) By the date on which any 

allocation or auction results, other than 

an allocation or auction results 

described in paragraphs (a) through (i) 

of this section, of TR SO2 Group 1 

allowances to a recipient is made by or 

are submitted to the Administrator in 

accordance with § 97.611 or § 97.612 or 

with a SIP revision approved under 

§ 52.39(e) or (f) of this chapter, the 

Administrator will record such 

allocation or auction results in the 

appropriate Allowance Management 

System account. 

(k) When recording the allocation or 

auction of TR SO2 Group 1 allowances 

to a TR SO2 Group 1 unit or other entity 

in an Allowance Management System 

account, the Administrator will assign 

each TR SO2 Group 1 allowance a 

unique identification number that will 

include digits identifying the year of the 

control period for which the TR SO2

Group 1 allowance is allocated or 

auctioned. 

§ 97.622 Submission of TR SO2 Group 1 

allowance transfers. 

(a) An authorized account 

representative seeking recordation of a 

TR SO2 Group 1 allowance transfer shall 

submit the transfer to the Administrator. 

(b) A TR SO2 Group 1 allowance 

transfer shall be correctly submitted if: 

(1) The transfer includes the following 

elements, in a format prescribed by the 

Administrator: 

(i) The account numbers established 

by the Administrator for both the 

transferor and transferee accounts; 

(ii) The serial number of each TR SO2

Group 1 allowance that is in the 

transferor account and is to be 

transferred; and 

(iii) The name and signature of the 

authorized account representative of the 

transferor account and the date signed; 

and 

(2) When the Administrator attempts 

to record the transfer, the transferor 

account includes each TR SO2 Group 1 

allowance identified by serial number in 

the transfer. 

§ 97.623 Recordation of TR SO2 Group 1 

allowance transfers. 

(a) Within 5 business days (except as 

provided in paragraph (b) of this 

section) of receiving a TR SO2 Group 1 

allowance transfer that is correctly 

submitted under § 97.622, the 

Administrator will record a TR SO2

Group 1 allowance transfer by moving 

each TR SO2 Group 1 allowance from 

the transferor account to the transferee 

account as specified in the transfer. 

(b) A TR SO2 Group 1 allowance 

transfer to or from a compliance account 

that is submitted for recordation after 

the allowance transfer deadline for a 

control period and that includes any TR 

SO2 Group 1 allowances allocated for 


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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, the Administrator 

will notify the authorized account 

representatives of both the transferor 

and transferee accounts. 

(e) Within 10 business days of receipt 

of a TR SO2 Group 1 allowance transfer 

that is not correctly submitted under 

§ 97.622, the Administrator will notify 

the authorized account representatives 

of both accounts subject to the transfer 

of: 

(1) A decision not to record the 

transfer, and 

(2) The reasons for such nonrecordation. 

§ 97.624 Compliance with TR SO2 Group 1 

emissions limitation. 

(a) Availability for deduction for 

compliance. TR SO2 Group 1 allowances 

are available to be deducted for 

compliance with a source’s TR SO2

Group 1 emissions limitation for a 

control period in a given year only if the 

TR SO2 Group 1 allowances: 

(1) Were allocated for 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 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 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 a control 

period in a prior year or the control 

period in the year of the excess 

emissions or in the immediately 

following year, equal to two times the 

number of tons of the source’s excess 

emissions. 

(e) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraphs (b) and (d) of this section. 

§ 97.625 Compliance with TR SO2 Group 1 

assurance provisions. 

(a) Availability for deduction. TR SO2

Group 1 allowances are available to be 

deducted for compliance with the TR 

SO2 Group 1 assurance provisions for a 

control period in a given year by the 

owners and operators of a group of one 

or more TR SO2 Group 1 sources and 

units in a State (and Indian country 

within the borders of such State) only if 

the TR SO2 Group 1 allowances: 

(1) Were allocated for a control period 

in a prior year or the control period in 

the given year or in the immediately 

following year; and 

(2) Are held in the assurance account, 

established by the Administrator for 

such owners and operators of such 

group of TR SO2 Group 1 sources and 

units in such State (and Indian country 

within the borders of such State) under 

paragraph (b)(3) of this section, as of the 

deadline established in paragraph (b)(4) 

of this section. 

(b) Deductions for compliance. The 

Administrator will deduct TR SO2

Group 1 allowances available under 

paragraph (a) of this section for 

compliance with the TR SO2 Group 1 

assurance provisions for a State for a 

control period in a given year in 

accordance with the following 

procedures: 

(1) By June 1, 2013 and June 1 of each 

year thereafter, the Administrator will: 

(i) Calculate, for each State (and 

Indian country within the borders of 

such State), the total SO2 emissions 

from all TR SO2 Group 1 units at TR SO2

Group 1 sources in the State (and Indian 

country within the borders of such 

State) during the control period in the 

year before the year of this calculation 

deadline and the amount, if any, by 

which such total SO2 emissions exceed 

the State assurance level as described in 

§ 97.606(c)(2)(iii); and 

(ii) Promulgate a notice of data 

availability of the results of the 

calculations required in paragraph 

(b)(1)(i) of this section, including 

separate calculations of the SO2

emissions from each TR SO2 Group 1 

source. 

(2) For each notice of data availability 

required in paragraph (b)(1)(ii) of this 

section and for any State (and Indian 

country within the borders of such 

State) identified in such notice as 

having TR SO2 Group 1 units with total 

SO2 emissions exceeding the State 

assurance level for a control period in 

a given year, as described in 

§ 97.606(c)(2)(iii): 

(i) By July 1 immediately after the 

promulgation of such notice, the 

designated representative of each TR 

SO2 Group 1 source in each such State 

(and Indian country within the borders 

of such State) shall submit a statement, 

in a format prescribed by the 

Administrator, providing for each TR 

SO2 Group 1 unit (if any) at the source 


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that operates during, but is not allocated 

an amount of TR SO2 Group 1 

allowances for, such control period, the 

unit’s allowable SO2 emission rate for 

such control period and, if such rate is 

expressed in lb per mmBtu, the unit’s 

heat rate. 

(ii) By August 1 immediately after the 

promulgation of such notice, the 

Administrator will calculate, for each 

such State (and Indian country within 

the borders of such State) and such 

control period and each common 

designated representative for such 

control period for a group of one or 

more TR SO2 Group 1 sources and units 

in the State (and Indian country within 

the borders of such State), the common 

designated representative’s share of the 

total SO2 emissions from all TR SO2

Group 1 units at TR SO2 Group 1 

sources in the State (and Indian country 

within the borders of such State), the 

common designated representative’s 

assurance level, and the amount (if any) 

of TR SO2 Group 1 allowances that the 

owners and operators of such group of 

sources and units must hold in 

accordance with the calculation formula 

in § 97.606(c)(2)(i) and will promulgate 

a notice of data availability of the results 

of these calculations. 

(iii) The Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

by the notice of data availability 

required in paragraph (b)(2)(ii) of this 

section and the calculations referenced 

by the relevant notice of data 

availability required in paragraph 

(b)(1)(i) of this section. 

(A) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations referenced in 

the relevant notice required under 

paragraph (b)(1)(ii) of this section and 

referenced in the notice required under 

paragraph (b)(2)(ii) of this section are in 

accordance with § 97.606(c)(2)(iii), 

§§ 97.606(b) and 97.630 through 97.635, 

the definitions of ‘‘common designated 

representative’’, ‘‘common designated 

representative’s assurance level’’, and 

‘‘common designated representative’s 

share’’ in § 97.602, and the calculation 

formula in § 97.606(c)(2)(i). 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(iii)(A) of this section. By October 

1 immediately after the promulgation of 

such notice, the Administrator will 

promulgate a notice of data availability 

of any adjustments that the 

Administrator determines to be 

necessary and the reasons for accepting 

or rejecting any objections submitted in 

accordance with paragraph (b)(2)(iii)(A) 

of this section. 

(3) For any State (and Indian country 

within the borders of such State) 

referenced in each notice of data 

availability required in paragraph 

(b)(2)(iii)(B) of this section as having TR 

SO2 Group 1 units with total SO2

emissions exceeding the State assurance 

level for a control period in a given year, 

the Administrator will establish one 

assurance account for each set of owners 

and operators referenced, in the notice 

of data availability required under 

paragraph (b)(2)(iii)(B) of this section, as 

all of the owners and operators of a 

group of TR SO2 Group 1 sources and 

units in the State (and Indian country 

within the borders of such State) having 

a common designated representative for 

such control period and as being 

required to hold TR SO2 Group 1 

allowances. 

(4)(i) As of midnight of November 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(2)(iii)(B) of this section, 

the owners and operators described in 

paragraph (b)(3) of this section shall 

hold in the assurance account 

established for them and for the 

appropriate TR SO2 Group 1 sources, TR 

SO2 Group 1 units, and State (and 

Indian country within the borders of 

such State) under paragraph (b)(3) of 

this section a total amount of TR SO2

Group 1 allowances, available for 

deduction under paragraph (a) of this 

section, equal to the amount such 

owners and operators are required to 

hold with regard to such sources, units 

and State (and Indian country within 

the borders of such State) as calculated 

by the Administrator and referenced in 

such notice. 

(ii) Notwithstanding the allowanceholding deadline specified in paragraph 

(b)(4)(i) of this section, if November 1 is 

not a business day, then such 

allowance-holding deadline shall be 

midnight of the first business day 

thereafter. 

(5) After November 1 (or the date 

described in paragraph (b)(4)(ii) of this 

section) immediately after the 

promulgation of each notice of data 

availability required in paragraph 

(b)(2)(iii)(B) of this section and after the 

recordation, in accordance with 

§ 97.623, of TR SO2 Group 1 allowance 

transfers submitted by midnight of such 

date, the Administrator will determine 

whether the owners and operators 

described in paragraph (b)(3) of this 

section hold, in the assurance account 

for the appropriate TR SO2 Group 1 

sources, TR SO2 Group 1 units, and 

State (and Indian country within the 

borders of such State) established under 

paragraph (b)(3) of this section, the 

amount of TR SO2 Group 1 allowances 

available under paragraph (a) of this 

section that the owners and operators 

are required to hold with regard to such 

sources, units, and State (and Indian 

country within the borders of such 

State) as calculated by the 

Administrator and referenced in the 

notice required in paragraph 

(b)(2)(iii)(B) of this section. 

(6) Notwithstanding any other 

provision of this subpart and any 

revision, made by or submitted to the 

Administrator after the promulgation of 

the notice of data availability required 

in paragraph (b)(2)(iii)(B) of this section 

for a control period in a given year, of 

any data used in making the 

calculations referenced in such notice, 

the amounts of TR SO2 Group 1 

allowances that the owners and 

operators are required to hold in 

accordance with § 97.606(c)(2)(i) for 

such control period shall continue to be 

such amounts as calculated by the 

Administrator and referenced in such 

notice required in paragraph 

(b)(2)(iii)(B) of this section, except as 

follows: 

(i) If any such data are revised by the 

Administrator as a result of a decision 

in or settlement of litigation concerning 

such data on appeal under part 78 of 

this chapter of such notice, or on appeal 

under section 307 of the Clean Air Act 

of a decision rendered under part 78 of 

this chapter on appeal of such notice, 

then the Administrator will use the data 

as so revised to recalculate the amounts 

of TR SO2 Group 1 allowances that 

owners and operators are required to 

hold in accordance with the calculation 

formula in § 97.606(c)(2)(i) for such 

control period with regard to the TR SO2

Group 1 sources, TR SO2 Group 1 units, 

and State (and Indian country within 

the borders of such State) involved, 

provided that such litigation under part 

78 of this chapter, or the proceeding 

under part 78 of this chapter that 

resulted in the decision appealed in 

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 


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accordance with the calculation formula 

in § 97.606(c)(2)(i) for such control 

period with regard to the TR SO2 Group 

1 sources, TR SO2 Group 1 units, and 

State (and Indian country within the 

borders of such State) involved, 

provided that such litigation was 

initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(2)(iii)(B) of this section. 

(iii) If the revised data are used to 

recalculate, in accordance with 

paragraphs (b)(6)(i) and (ii) of this 

section, the amount of TR SO2 Group 1 

allowances that the owners and 

operators are required to hold for such 

control period with regard to the TR SO2

Group 1 sources, TR SO2 Group 1 units, 

and State (and Indian country within 

the borders of such State) involved— 

(A) Where the amount of TR SO2

Group 1 allowances that the owners and 

operators are required to hold increases 

as a result of the use of all such revised 

data, the Administrator will establish a 

new, reasonable deadline on which the 

owners and operators shall hold the 

additional amount of TR SO2 Group 1 

allowances in the assurance account 

established by the Administrator for the 

appropriate TR SO2 Group 1 sources, TR 

SO2 Group 1 units, and State (and 

Indian country within the borders of 

such State) under paragraph (b)(3) of 

this section. The owners’ and operators’ 

failure to hold such additional amount, 

as required, before the new deadline 

shall not be a violation of the Clean Air 

Act. The owners’ and operators’ failure 

to hold such additional amount, as 

required, as of the new deadline shall be 

a violation of the Clean Air Act. Each 

TR SO2 Group 1 allowance that the 

owners and operators fail to hold as 

required as of the new deadline, and 

each day in such control period, shall be 

a separate violation of the Clean Air Act. 

(B) For the owners and operators for 

which the amount of TR SO2 Group 1 

allowances required to be held 

decreases as a result of the use of all 

such revised data, the Administrator 

will record, in all accounts from which 

TR SO2 Group 1 allowances were 

transferred by such owners and 

operators for such control period to the 

assurance account established by the 

Administrator for the appropriate TR 

SO2 Group 1 sources, TR SO2 Group 1 

units, and State (and Indian country 

within the borders of such State) under 

paragraph (b)(3) of this section, a total 

amount of the TR SO2 Group 1 

allowances held in such assurance 

account equal to the amount of the 

decrease. If TR SO2 Group 1 allowances 

were transferred to such assurance 

account from more than one account, 

the amount of TR SO2 Group 1 

allowances recorded in each such 

transferor account will be in proportion 

to the percentage of the total amount of 

TR SO2 Group 1 allowances transferred 

to such assurance account for such 

control period from such transferor 

account. 

(C) Each TR SO2 Group 1 allowance 

held under paragraph (b)(6)(iii)(A) of 

this section as a result of recalculation 

of requirements under the TR SO2

Group 1 assurance provisions for such 

control period must be a TR SO2 Group 

1 allowance allocated for a control 

period in a year before or the year 

immediately following, or in the same 

year as, the year of such control period. 

§ 97.626 Banking. 

(a) A TR SO2 Group 1 allowance may 

be banked for future use or transfer in 

a compliance account or a general 

account in accordance with paragraph 

(b) of this section. 

(b) Any TR SO2 Group 1 allowance 

that is held in a compliance account or 

a general account will remain in such 

account unless and until the TR SO2

Group 1 allowance is deducted or 

transferred under § 97.611(c), § 97.623, 

§ 97.624, § 97.625, § 97.627, or § 97.628. 

§ 97.627 Account error. 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any 

Allowance Management System 

account. Within 10 business days of 

making such correction, the 

Administrator will notify the authorized 

account representative for the account. 

§ 97.628 Administrator’s action on 

submissions. 

(a) The Administrator may review and 

conduct independent audits concerning 

any submission under the TR SO2

Group 1 Trading Program and make 

appropriate adjustments of the 

information in the submission. 

(b) The Administrator may deduct TR 

SO2 Group 1 allowances from or transfer 

TR SO2 Group 1 allowances to a 

compliance account or an assurance 

account, based on the information in a 

submission, as adjusted under 

paragraph (a)(1) of this section, and 

record such deductions and transfers. 

§ 97.629 [Reserved] 

§ 97.630 General monitoring, 

recordkeeping, and reporting requirements. 

The owners and operators, and to the 

extent applicable, the designated 

representative, of a TR SO2 Group 1 

unit, shall comply with the monitoring, 

recordkeeping, and reporting 

requirements as provided in this subpart 

and subparts F and G of part 75 of this 

chapter. For purposes of applying such 

requirements, the definitions in § 97.602 

and in § 72.2 of this chapter shall apply, 

the terms ‘‘affected unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) in part 75 of this chapter shall 

be deemed to refer to the terms ‘‘TR SO2

Group 1 unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) respectively as defined in 

§ 97.602, and the term ‘‘newly affected 

unit’’ shall be deemed to mean ‘‘newly 

affected TR SO2 Group 1 unit’’. The 

owner or operator of a unit that is not 

a TR SO2 Group 1 unit but that is 

monitored under § 75.16(b)(2) of this 

chapter shall comply with the same 

monitoring, recordkeeping, and 

reporting requirements as a TR SO2

Group 1 unit. 

(a) Requirements for installation, 

certification, and data accounting. The 

owner or operator of each TR SO2 Group 

1 unit shall: 

(1) Install all monitoring systems 

required under this subpart for 

monitoring SO2 mass emissions and 

individual unit heat input (including all 

systems required to monitor SO2

concentration, stack gas moisture 

content, stack gas flow rate, CO2 or O2

concentration, and fuel flow rate, as 

applicable, in accordance with §§ 75.11 

and 75.16 of this chapter); 

(2) Successfully complete all 

certification tests required under 

§ 97.631 and meet all other 

requirements of this subpart and part 75 

of this chapter applicable to the 

monitoring systems under paragraph 

(a)(1) of this section; and 

(3) Record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section. 

(b) Compliance deadlines. Except as 

provided in paragraph (e) of this 

section, the owner or operator shall 

meet the monitoring system certification 

and other requirements of paragraphs 

(a)(1) and (2) of this section on or before 

the following dates and shall record, 

report, and quality-assure the data from 

the monitoring systems under paragraph 

(a)(1) of this section on and after the 

following dates. 

(1) For the owner or operator of a TR 

SO2 Group 1 unit that commences 

commercial operation before July 1, 

2011, January 1, 2012. 

(2) For the owner or operator of a TR 

SO2 Group 1 unit that commences 

commercial operation on or after July 1, 

2011, by the later of the following: 

(i) January 1, 2012; or 

(ii) 180 calendar days after the date on 

which the unit commences commercial 

operation. 


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(3) The owner or operator of a TR SO2

Group 1 unit for which construction of 

a new stack or flue or installation of 

add-on SO2 emission controls is 

completed after the applicable deadline 

under paragraph (b)(1) or (2) of this 

section shall meet the requirements of 

§§ 75.4(e)(1) through (e)(4) of this 

chapter, except that: 

(i) Such requirements shall apply to 

the monitoring systems required under 

§ 97.630 through § 97.635, rather than 

the monitoring systems required under 

part 75 of this chapter; 

(ii) SO2 concentration, stack gas 

moisture content, stack gas volumetric 

flow rate, and O2 or CO2 concentration 

data shall be determined and reported, 

rather than the data listed in § 75.4(e)(2) 

of this chapter; and 

(iii) Any petition for another 

procedure under § 75.4(e)(2) of this 

chapter shall be submitted under 

§ 97.635, rather than § 75.66. 

(c) Reporting data. The owner or 

operator of a TR SO2 Group 1 unit that 

does not meet the applicable 

compliance date set forth in paragraph 

(b) of this section for any monitoring 

system under paragraph (a)(1) of this 

section shall, for each such monitoring 

system, determine, record, and report 

maximum potential (or, as appropriate, 

minimum potential) values for SO2

concentration, stack gas flow rate, stack 

gas moisture content, fuel flow rate, and 

any other parameters required to 

determine SO2 mass emissions and heat 

input in accordance with § 75.31(b)(2) 

or (c)(3) of this chapter or section 2.4 of 

appendix D to part 75 of this chapter, as 

applicable. 

(d) Prohibitions. (1) No owner or 

operator of a TR SO2 Group 1 unit shall 

use any alternative monitoring system, 

alternative reference method, or any 

other alternative to any requirement of 

this subpart without having obtained 

prior written approval in accordance 

with § 97.635. 

(2) No owner or operator of a TR SO2

Group 1 unit shall operate the unit so 

as to discharge, or allow to be 

discharged, SO2 to the atmosphere 

without accounting for all such SO2 in 

accordance with the applicable 

provisions of this subpart and part 75 of 

this chapter. 

(3) No owner or operator of a TR SO2

Group 1 unit shall disrupt the 

continuous emission monitoring system, 

any portion thereof, or any other 

approved emission monitoring method, 

and thereby avoid monitoring and 

recording SO2 mass discharged into the 

atmosphere or heat input, except for 

periods of recertification or periods 

when calibration, quality assurance 

testing, or maintenance is performed in 

accordance with the applicable 

provisions of this subpart and part 75 of 

this chapter. 

(4) No owner or operator of a TR SO2

Group 1 unit shall retire or permanently 

discontinue use of the continuous 

emission monitoring system, any 

component thereof, or any other 

approved monitoring system under this 

subpart, except under any one of the 

following circumstances: 

(i) During the period that the unit is 

covered by an exemption under § 97.605 

that is in effect; 

(ii) The owner or operator is 

monitoring emissions from the unit with 

another certified monitoring system 

approved, in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter, by the 

Administrator for use at that unit that 

provides emission data for the same 

pollutant or parameter as the retired or 

discontinued monitoring system; or 

(iii) The designated representative 

submits notification of the date of 

certification testing of a replacement 

monitoring system for the retired or 

discontinued monitoring system in 

accordance with § 97.631(d)(3)(i). 

(e) Long-term cold storage. The owner 

or operator of a TR SO2 Group 1 unit is 

subject to the applicable provisions of 

§ 75.4(d) of this chapter concerning 

units in long-term cold storage. 

§ 97.631 Initial monitoring system 

certification and recertification procedures. 

(a) The owner or operator of a TR SO2

Group 1 unit shall be exempt from the 

initial certification requirements of this 

section for a monitoring system under 

§ 97.630(a)(1) if the following conditions 

are met: 

(1) The monitoring system has been 

previously certified in accordance with 

part 75 of this chapter; and 

(2) The applicable quality-assurance 

and quality-control requirements of 

§ 75.21 of this chapter and appendices 

B and D to part 75 of this chapter are 

fully met for the certified monitoring 

system described in paragraph (a)(1) of 

this section. 

(b) The recertification provisions of 

this section shall apply to a monitoring 

system under § 97.630(a)(1) that is 

exempt from initial certification 

requirements under paragraph (a) of this 

section. 

(c) [Reserved] 

(d) Except as provided in paragraph 

(a) of this section, the owner or operator 

of a TR SO2 Group 1 unit shall comply 

with the following initial certification 

and recertification procedures, for a 

continuous monitoring system (i.e., a 

continuous emission monitoring system 

and an excepted monitoring system 

under appendix D to part 75 of this 

chapter) under § 97.630(a)(1). The 

owner or operator of a unit that qualifies 

to use the low mass emissions excepted 

monitoring methodology under § 75.19 

of this chapter or that qualifies to use an 

alternative monitoring system under 

subpart E of part 75 of this chapter shall 

comply with the procedures in 

paragraph (e) or (f) of this section 

respectively. 

(1) Requirements for initial 

certification. The owner or operator 

shall ensure that each continuous 

monitoring system under § 97.630(a)(1) 

(including the automated data 

acquisition and handling system) 

successfully completes all of the initial 

certification testing required under 

§ 75.20 of this chapter by the applicable 

deadline in § 97.630(b). In addition, 

whenever the owner or operator installs 

a monitoring system to meet the 

requirements of this subpart in a 

location where no such monitoring 

system was previously installed, initial 

certification in accordance with § 75.20 

of this chapter is required. 

(2) Requirements for recertification. 

Whenever the owner or operator makes 

a replacement, modification, or change 

in any certified continuous emission 

monitoring system under § 97.630(a)(1) 

that may significantly affect the ability 

of the system to accurately measure or 

record SO2 mass emissions or heat input 

rate or to meet the quality-assurance and 

quality-control requirements of § 75.21 

of this chapter or appendix B to part 75 

of this chapter, the owner or operator 

shall recertify the monitoring system in 

accordance with § 75.20(b) of this 

chapter. Furthermore, whenever the 

owner or operator makes a replacement, 

modification, or change to the flue gas 

handling system or the unit’s operation 

that may significantly change the stack 

flow or concentration profile, the owner 

or operator shall recertify each 

continuous emission monitoring system 

whose accuracy is potentially affected 

by the change, in accordance with 

§ 75.20(b) of this chapter. Examples of 

changes to a continuous emission 

monitoring system that require 

recertification include: Replacement of 

the analyzer, complete replacement of 

an existing continuous emission 

monitoring system, or change in 

location or orientation of the sampling 

probe or site. Any fuel flowmeter system 

under § 97.630(a)(1) is subject to the 

recertification requirements in 

§ 75.20(g)(6) of this chapter. 

(3) Approval process for initial 

certification and recertification. For 

initial certification of a continuous 

monitoring system under § 97.630(a)(1), 

paragraphs (d)(3)(i) through (v) of this 


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section apply. For recertifications of 

such monitoring systems, paragraphs 

(d)(3)(i) through (iv) of this section and 

the procedures in §§ 75.20(b)(5) and 

(g)(7) of this chapter (in lieu of the 

procedures in paragraph (d)(3)(v) of this 

section) apply, provided that in 

applying paragraphs (d)(3)(i) through 

(iv) of this section, the words 

‘‘certification’’ and ‘‘initial certification’’ 

are replaced by the word 

‘‘recertification’’ and the word 

‘‘certified’’ is replaced by the word 

‘‘recertified’’. 

(i) Notification of certification. The 

designated representative shall submit 

to the appropriate EPA Regional Office 

and the Administrator written notice of 

the dates of certification testing, in 

accordance with § 97.633. 

(ii) Certification application. The 

designated representative shall submit 

to the Administrator a certification 

application for each monitoring system. 

A complete certification application 

shall include the information specified 

in § 75.63 of this chapter. 

(iii) Provisional certification date. The 

provisional certification date for a 

monitoring system shall be determined 

in accordance with § 75.20(a)(3) of this 

chapter. A provisionally certified 

monitoring system may be used under 

the TR SO2 Group 1 Trading Program for 

a period not to exceed 120 days after 

receipt by the Administrator of the 

complete certification application for 

the monitoring system under paragraph 

(d)(3)(ii) of this section. Data measured 

and recorded by the provisionally 

certified monitoring system, in 

accordance with the requirements of 

part 75 of this chapter, will be 

considered valid quality-assured data 

(retroactive to the date and time of 

provisional certification), provided that 

the Administrator does not invalidate 

the provisional certification by issuing a 

notice of disapproval within 120 days of 

the date of receipt of the complete 

certification application by the 

Administrator. 

(iv) Certification application approval 

process. The Administrator will issue a 

written notice of approval or 

disapproval of the certification 

application to the owner or operator 

within 120 days of receipt of the 

complete certification application under 

paragraph (d)(3)(ii) of this section. In the 

event the Administrator does not issue 

such a notice within such 120-day 

period, each monitoring system that 

meets the applicable performance 

requirements of part 75 of this chapter 

and is included in the certification 

application will be deemed certified for 

use under the TR SO2 Group 1 Trading 

Program. 

(A) Approval notice. If the 

certification application is complete and 

shows that each monitoring system 

meets the applicable performance 

requirements of part 75 of this chapter, 

then the Administrator will issue a 

written notice of approval of the 

certification application within 120 

days of receipt. 

(B) Incomplete application notice. If 

the certification application is not 

complete, then the Administrator will 

issue a written notice of incompleteness 

that sets a reasonable date by which the 

designated representative must submit 

the additional information required to 

complete the certification application. If 

the designated representative does not 

comply with the notice of 

incompleteness by the specified date, 

then the Administrator may issue a 

notice of disapproval under paragraph 

(d)(3)(iv)(C) of this section. 

(C) Disapproval notice. If the 

certification application shows that any 

monitoring system does not meet the 

performance requirements of part 75 of 

this chapter or if the certification 

application is incomplete and the 

requirement for disapproval under 

paragraph (d)(3)(iv)(B) of this section is 

met, then the Administrator will issue a 

written notice of disapproval of the 

certification application. Upon issuance 

of such notice of disapproval, the 

provisional certification is invalidated 

by the Administrator and the data 

measured and recorded by each 

uncertified monitoring system shall not 

be considered valid quality-assured data 

beginning with the date and hour of 

provisional certification (as defined 

under § 75.20(a)(3) of this chapter). 

(D) Audit decertification. The 

Administrator may issue a notice of 

disapproval of the certification status of 

a monitor in accordance with 

§ 97.632(b). 

(v) Procedures for loss of certification. 

If the Administrator issues a notice of 

disapproval of a certification 

application under paragraph 

(d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under 

paragraph (d)(3)(iv)(D) of this section, 

then: 

(A) The owner or operator shall 

substitute the following values, for each 

disapproved monitoring system, for 

each hour of unit operation during the 

period of invalid data specified under 

§ 75.20(a)(4)(iii), § 75.20(g)(7), or 

§ 75.21(e) of this chapter and continuing 

until the applicable date and hour 

specified under § 75.20(a)(5)(i) or (g)(7) 

of this chapter: 

(1) For a disapproved SO2 pollutant 

concentration monitor and disapproved 

flow monitor, respectively, the 

maximum potential concentration of 

SO2 and the maximum potential flow 

rate, as defined in sections 2.1.1.1 and 

2.1.4.1 of appendix A to part 75 of this 

chapter. 

(2) For a disapproved moisture 

monitoring system and disapproved 

diluent gas monitoring system, 

respectively, the minimum potential 

moisture percentage and either the 

maximum potential CO2 concentration 

or the minimum potential O2

concentration (as applicable), as defined 

in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 

appendix A to part 75 of this chapter. 

(3) For a disapproved fuel flowmeter 

system, the maximum potential fuel 

flow rate, as defined in section 2.4.2.1 

of appendix D to part 75 of this chapter. 

(B) The designated representative 

shall submit a notification of 

certification retest dates and a new 

certification application in accordance 

with paragraphs (d)(3)(i) and (ii) of this 

section. 

(C) The owner or operator shall repeat 

all certification tests or other 

requirements that were failed by the 

monitoring system, as indicated in the 

Administrator’s notice of disapproval, 

no later than 30 unit operating days 

after the date of issuance of the notice 

of disapproval. 

(e) The owner or operator of a unit 

qualified to use the low mass emissions 

(LME) excepted methodology under 

§ 75.19 of this chapter shall meet the 

applicable certification and 

recertification requirements in 

§§ 75.19(a)(2) and 75.20(h) of this 

chapter. If the owner or operator of such 

a unit elects to certify a fuel flowmeter 

system for heat input determination, the 

owner or operator shall also meet the 

certification and recertification 

requirements in § 75.20(g) of this 

chapter. 

(f) The designated representative of 

each unit for which the owner or 

operator intends to use an alternative 

monitoring system approved by the 

Administrator under subpart E of part 

75 of this chapter shall comply with the 

applicable notification and application 

procedures of § 75.20(f) of this chapter. 

§ 97.632 Monitoring system out-of-control 

periods. 

(a) General provisions. Whenever any 

monitoring system fails to meet the 

quality-assurance and quality-control 

requirements or data validation 

requirements of part 75 of this chapter, 

data shall be substituted using the 

applicable missing data procedures in 

subpart D or appendix D to part 75 of 

this chapter. 

(b) Audit decertification. Whenever 

both an audit of a monitoring system 


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and a review of the initial certification 

or recertification application reveal that 

any monitoring system should not have 

been certified or recertified because it 

did not meet a particular performance 

specification or other requirement under 

§ 97.631 or the applicable provisions of 

part 75 of this chapter, both at the time 

of the initial certification or 

recertification application submission 

and at the time of the audit, the 

Administrator will issue a notice of 

disapproval of the certification status of 

such monitoring system. For the 

purposes of this paragraph, an audit 

shall be either a field audit or an audit 

of any information submitted to the 

Administrator or any State or permitting 

authority. By issuing the notice of 

disapproval, the Administrator revokes 

prospectively the certification status of 

the monitoring system. The data 

measured and recorded by the 

monitoring system shall not be 

considered valid quality-assured data 

from the date of issuance of the 

notification of the revoked certification 

status until the date and time that the 

owner or operator completes 

subsequently approved initial 

certification or recertification tests for 

the monitoring system. The owner or 

operator shall follow the applicable 

initial certification or recertification 

procedures in § 97.631 for each 

disapproved monitoring system. 

§ 97.633 Notifications concerning 

monitoring. 

The designated representative of a TR 

SO2 Group 1 unit shall submit written 

notice to the Administrator in 

accordance with § 75.61 of this chapter. 

§ 97.634 Recordkeeping and reporting. 

(a) General provisions. The designated 

representative shall comply with all 

recordkeeping and reporting 

requirements in paragraphs (b) through 

(e) of this section, the applicable 

recordkeeping and reporting 

requirements in subparts F and G of part 

75 of this chapter, and the requirements 

of § 97.614(a). 

(b) Monitoring plans. The owner or 

operator of a TR SO2 Group 1 unit shall 

comply with requirements of § 75.62 of 

this chapter. 

(c) Certification applications. The 

designated representative shall submit 

an application to the Administrator 

within 45 days after completing all 

initial certification or recertification 

tests required under § 97.631, including 

the information required under § 75.63 

of this chapter. 

(d) Quarterly reports. The designated 

representative shall submit quarterly 

reports, as follows: 

(1) The designated representative 

shall report the SO2 mass emissions data 

and heat input data for the TR SO2

Group 1 unit, in an electronic quarterly 

report in a format prescribed by the 

Administrator, for each calendar quarter 

beginning with: 

(i) For a unit that commences 

commercial operation before July 1, 

2011, the calendar quarter covering 

January 1, 2012 through March 31, 2012; 

or 

(ii) For a unit that commences 

commercial operation on or after July 1, 

2011, the calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 97.630(b), unless 

that quarter is the third or fourth quarter 

of 2011, in which case reporting shall 

commence in the quarter covering 

January 1, 2012 through March 31, 2012. 

(2) The designated representative 

shall submit each quarterly report to the 

Administrator within 30 days after the 

end of the calendar quarter covered by 

the report. Quarterly reports shall be 

submitted in the manner specified in 

§ 75.64 of this chapter. 

(3) For TR SO2 Group 1 units that are 

also subject to the Acid Rain Program, 

TR NOX Annual Trading Program, or TR 

NOX Ozone Season Trading Program, 

quarterly reports shall include the 

applicable data and information 

required by subparts F through H of part 

75 of this chapter as applicable, in 

addition to the SO2 mass emission data, 

heat input data, and other information 

required by this subpart. 

(4) The Administrator may review and 

conduct independent audits of any 

quarterly report in order to determine 

whether the quarterly report meets the 

requirements of this subpart and part 75 

of this chapter, including the 

requirement to use substitute data. 

(i) The Administrator will notify the 

designated representative of any 

determination that the quarterly report 

fails to meet any such requirements and 

specify in such notification any 

corrections that the Administrator 

believes are necessary to make through 

resubmission of the quarterly report and 

a reasonable time period within which 

the designated representative must 

respond. Upon request by the 

designated representative, the 

Administrator may specify reasonable 

extensions of such time period. Within 

the time period (including any such 

extensions) specified by the 

Administrator, the designated 

representative shall resubmit the 

quarterly report with the corrections 

specified by the Administrator, except 

to the extent the designated 

representative provides information 

demonstrating that a specified 

correction is not necessary because the 

quarterly report already meets the 

requirements of this subpart and part 75 

of this chapter that are relevant to the 

specified correction. 

(ii) Any resubmission of a quarterly 

report shall meet the requirements 

applicable to the submission of a 

quarterly report under this subpart and 

part 75 of this chapter, except for the 

deadline set forth in paragraph (d)(2) of 

this section. 

(e) Compliance certification. The 

designated representative shall submit 

to the Administrator a compliance 

certification (in a format prescribed by 

the Administrator) in support of each 

quarterly report based on reasonable 

inquiry of those persons with primary 

responsibility for ensuring that all of the 

unit’s emissions are correctly and fully 

monitored. The certification shall state 

that: 

(1) The monitoring data submitted 

were recorded in accordance with the 

applicable requirements of this subpart 

and part 75 of this chapter, including 

the quality assurance procedures and 

specifications; and 

(2) For a unit with add-on SO2

emission controls and for all hours 

where SO2 data are substituted in 

accordance with § 75.34(a)(1) of this 

chapter, the add-on emission controls 

were operating within the range of 

parameters listed in the quality 

assurance/quality control program 

under appendix B to part 75 of this 

chapter and the substitute data values 

do not systematically underestimate SO2

emissions. 

§ 97.635 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

(a) The designated representative of a 

TR SO2 Group 1 unit may submit a 

petition under § 75.66 of this chapter to 

the Administrator, requesting approval 

to apply an alternative to any 

requirement of §§ 97.630 through 

97.634. 

(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 


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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 

Sec. 

97.701 Purpose. 

97.702 Definitions. 

97.703 Measurements, abbreviations, and 

acronyms. 

97.704 Applicability. 

97.705 Retired unit exemption. 

97.706 Standard requirements. 

97.707 Computation of time. 

97.708 Administrative appeal procedures. 

97.709 [Reserved] 

97.710 State SO2 Group 2 trading budgets, 

new unit set-asides, Indian country new 

unit set-asides and variability limits. 

97.711 Timing requirements for TR SO2

Group 2 allowance allocations. 

97.712 TR SO2 Group 2 allowance 

allocations to new units. 

97.713 Authorization of designated 

representative and alternate designated 

representative. 

97.714 Responsibilities of designated 

representative and alternate designated 

representative. 

97.715 Changing designated representative 

and alternate designated representative; 

changes in owners and operators. 

97.716 Certificate of representation. 

97.717 Objections concerning designated 

representative and alternate designated 

representative. 

97.718 Delegation by designated 

representative and alternate designated 

representative. 

97.719 [Reserved] 

97.720 Establishment of compliance 

accounts and general accounts. 

97.721 Recordation of TR SO2 Group 2 

allowance allocations. 

97.722 Submission of TR SO2 Group 2 

allowance transfers. 

97.723 Recordation of TR SO2 Group 2 

allowance transfers. 

97.724 Compliance with TR SO2 Group 2 

emissions limitation. 

97.725 Compliance with TR SO2 Group 2 

assurance provisions. 

97.726 Banking. 

97.727 Account error. 

97.728 Administrator’s action on 

submissions. 

97.729 [Reserved] 

97.730 General monitoring, recordkeeping, 

and reporting requirements. 

97.731 Initial monitoring system 

certification and recertification 

procedures. 

97.732 Monitoring system out-of-control 

periods. 

97.733 Notifications concerning 

monitoring. 

97.734 Recordkeeping and reporting. 

97.735 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

Subpart DDDDD—TR SO2 Group 2 

Trading Program 

§ 97.701 Purpose. 

This subpart sets forth the general, 

designated representative, allowance, 

and monitoring provisions for the 

Transport Rule (TR) SO2 Group 2 

Trading Program, under section 110 of 

the Clean Air Act and § 52.39 of this 

chapter, as a means of mitigating 

interstate transport of fine particulates 

and sulfur dioxide. 

§ 97.702 Definitions. 

The terms used in this subpart shall 

have the meanings set forth in this 

section as follows: 

Acid Rain Program means a multistate SO2 and NOX air pollution control 

and emission reduction program 

established by the Administrator under 

title IV of the Clean Air Act and parts 

72 through 78 of this chapter. 

Administrator means the 

Administrator of the United States 

Environmental Protection Agency or the 

Director of the Clean Air Markets 

Division (or its successor determined by 

the Administrator) of the United States 

Environmental Protection Agency, the 

Administrator’s duly authorized 

representative under this subpart. 

Allocate or allocation means, with 

regard to TR SO2 Group 2 allowances, 

the determination by the Administrator, 

State, or permitting authority, in 

accordance with this subpart and any 

SIP revision submitted by the State and 

approved by the Administrator under 

§ 52.39(g), (h), or (i) of this chapter, of 

the amount of such TR SO2 Group 2 

allowances to be initially credited, at no 

cost to the recipient, to: 

(1) A TR SO2 Group 2 unit; 

(2) A new unit set-aside; 

(3) An Indian country new unit setaside; or 

(4) An entity not listed in paragraphs 

(1) through (3) of this definition; 

(5) Provided that, if the 

Administrator, State, or permitting 

authority initially credits, to a TR SO2

Group 2 unit qualifying for an initial 

credit, a credit in the amount of zero TR 

SO2 Group 2 allowances, the TR SO2

Group 2 unit will be treated as being 

allocated an amount (i.e., zero) of TR 

SO2 Group 2 allowances. 

Allowable SO2 emission rate means, 

for a unit, the most stringent State or 

federal SO2 emission rate limit (in lb/ 

MWhr or, if in lb/mmBtu, converted to 

lb/MWhr by multiplying it by the unit’s 

heat rate in mmBtu/MWhr) that is 

applicable to the unit and covers the 

longest averaging period not exceeding 

one year. 

Allowance Management System 

means the system by which the 

Administrator records allocations, 

deductions, and transfers of TR SO2

Group 2 allowances under the TR SO2

Group 2 Trading Program. Such 

allowances are allocated, recorded, 

held, deducted, or transferred only as 

whole allowances. 

Allowance Management System 

account means an account in the 

Allowance Management System 

established by the Administrator for 

purposes of recording the allocation, 

holding, transfer, or deduction of TR 

SO2 Group 2 allowances. 

Allowance transfer deadline means, 

for a control period in a given year, 

midnight of March 1 (if it is a business 

day), or midnight of the first business 

day thereafter (if March 1 is not a 

business day), immediately after such 

control period and is the deadline by 

which a TR SO2 Group 2 allowance 

transfer must be submitted for 

recordation in a TR SO2 Group 2 

source’s compliance account in order to 

be available for use in complying with 

the source’s TR SO2 Group 2 emissions 

limitation for such control period in 

accordance with §§ 97.706 and 97.724. 

Alternate designated representative 

means, for a TR SO2 Group 2 source and 

each TR SO2 Group 2 unit at the source, 

the natural person who is authorized by 

the owners and operators of the source 

and all such units at the source, in 

accordance with this subpart, to act on 

behalf of the designated representative 

in matters pertaining to the TR SO2

Group 2 Trading Program. If the TR SO2

Group 2 source is also subject to the 

Acid Rain Program, TR NOX Annual 

Trading Program, or TR NOX Ozone 

Season Trading Program, then this 

natural person shall be the same natural 

person as the alternate designated 

representative, as defined in the 

respective program. 

Assurance account means an 

Allowance Management System 

account, established by the 

Administrator under § 97.725(b)(3) for 

certain owners and operators of a group 

of one or more TR SO2 Group 2 sources 

and units in a given State (and Indian 

country within the borders of such 

State), in which are held TR SO2 Group 

2 allowances available for use for a 

control period in a given year in 


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complying with the TR SO2 Group 2 

assurance provisions in accordance with 

§§ 97.706 and 97.725. 

Authorized account representative 

means, for a general account, the natural 

person who is authorized, in accordance 

with this subpart, to transfer and 

otherwise dispose of TR SO2 Group 2 

allowances held in the general account 

and, for a TR SO2 Group 2 source’s 

compliance account, the designated 

representative of the source. 

Automated data acquisition and 

handling system or DAHS means the 

component of the continuous emission 

monitoring system, or other emissions 

monitoring system approved for use 

under this subpart, designed to interpret 

and convert individual output signals 

from pollutant concentration monitors, 

flow monitors, diluent gas monitors, 

and other component parts of the 

monitoring system to produce a 

continuous record of the measured 

parameters in the measurement units 

required by this subpart. 

Biomass means— 

(1) Any organic material grown for the 

purpose of being converted to energy; 

(2) Any organic byproduct of 

agriculture that can be converted into 

energy; or 

(3) Any material that can be converted 

into energy and is nonmerchantable for 

other purposes, that is segregated from 

other material that is nonmerchantable 

for other purposes, and that is; 

(i) A forest-related organic resource, 

including mill residues, precommercial 

thinnings, slash, brush, or byproduct 

from conversion of trees to 

merchantable material; or 

(ii) A wood material, including 

pallets, crates, dunnage, manufacturing 

and construction materials (other than 

pressure-treated, chemically-treated, or 

painted wood products), and landscape 

or right-of-way tree trimmings. 

Boiler means an enclosed fossil- or 

other-fuel-fired combustion device used 

to produce heat and to transfer heat to 

recirculating water, steam, or other 

medium. 

Bottoming-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful thermal 

energy, where at least some of the reject 

heat from the useful thermal energy 

application or process is then used for 

electricity production. 

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 of 

the corporation in charge of a principal 

business function or any other person 

who performs similar policy- or 

decision-making functions for the 

corporation; 

(2) For a partnership or sole 

proprietorship, a general partner or the 

proprietor respectively; or 

(3) For a local government entity or 

State, federal, or other public agency, a 

principal executive officer or ranking 

elected official. 

Clean Air Act means the Clean Air 

Act, 42 U.S.C. 7401, et seq. 

Coal means ‘‘coal’’ as defined in 

§ 72.2 of this chapter. 

Coal-derived fuel means any fuel 

(whether in a solid, liquid, or gaseous 

state) produced by the mechanical, 

thermal, or chemical processing of coal. 

Cogeneration system means an 

integrated group, at a source, of 

equipment (including a boiler, or 

combustion turbine, and a steam turbine 

generator) designed to produce useful 

thermal energy for industrial, 

commercial, heating, or cooling 

purposes and electricity through the 

sequential use of energy. 

Cogeneration unit means a stationary, 

fossil-fuel-fired boiler or stationary, 

fossil-fuel-fired combustion turbine that 

is a topping-cycle unit or a bottomingcycle unit: 

(1) Operating as part of a cogeneration 

system; and 

(2) Producing on an annual average 

basis— 

(i) For a topping-cycle unit, 

(A) Useful thermal energy not less 

than 5 percent of total energy output; 

and 

(B) Useful power that, when added to 

one-half of useful thermal energy 

produced, is not less than 42.5 percent 

of total energy input, 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 systemwide basis the requirement in paragraph 

(2)(i)(B) or (2)(ii) of this definition, the 

unit shall be deemed to meet such 

requirement during that 12-month 

period or calendar year. 

Combustion turbine means an 

enclosed device comprising: 

(1) If the device is simple cycle, a 

compressor, a combustor, and a turbine 

and in which the flue gas resulting from 

the combustion of fuel in the combustor 

passes through the turbine, rotating the 

turbine; and 

(2) If the device is combined cycle, 

the equipment described in paragraph 

(1) of this definition and any associated 

duct burner, heat recovery steam 

generator, and steam turbine. 

Commence commercial operation 

means, with regard to a unit: 

(1) To have begun to produce steam, 

gas, or other heated medium used to 

generate electricity for sale or use, 

including test generation, except as 

provided in § 97.705. 

(i) For a unit that is a TR SO2 Group 

2 unit under § 97.704 on the later of 

January 1, 2005 or the date the unit 

commences commercial operation as 

defined in the introductory text of 

paragraph (1) of this definition and that 

subsequently undergoes a physical 

change or is moved to a new location or 

source, such date shall remain the date 

of commencement of commercial 

operation of the unit, which shall 

continue to be treated as the same unit. 

(ii) For a unit that is a TR SO2 Group 

2 unit under § 97.704 on the later of 

January 1, 2005 or the date the unit 

commences commercial operation as 

defined in the introductory text of 

paragraph (1) of this definition and that 

is subsequently replaced by a unit at the 

same or a different source, such date 

shall remain the replaced unit’s date of 

commencement of commercial 

operation, and the replacement unit 

shall be treated as a separate unit with 

a separate date for commencement of 

commercial operation as defined in 

paragraph (1) or (2) of this definition as 

appropriate. 

(2) Notwithstanding paragraph (1) of 

this definition and except as provided 

in § 97.705, for a unit that is not a TR 

SO2 Group 2 unit under § 97.704 on the 

later of January 1, 2005 or the date the 

unit commences commercial operation 

as defined in introductory text of 

paragraph (1) of this definition, the 

unit’s date for commencement of 

commercial operation shall be the date 

on which the unit becomes a TR SO2

Group 2 unit under § 97.704. 

(i) For a unit with a date for 

commencement of commercial 

operation as defined in the introductory 

text of paragraph (2) of this definition 


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and that subsequently undergoes a 

physical change or is moved to a 

different location or source, such date 

shall remain the date of commencement 

of commercial operation of the unit, 

which shall continue to be treated as the 

same unit. 

(ii) For a unit with a date for 

commencement of commercial 

operation as defined in the introductory 

text of paragraph (2) of this definition 

and that is subsequently replaced by a 

unit at the same or a different source, 

such date shall remain the replaced 

unit’s date of commencement of 

commercial operation, and the 

replacement unit shall be treated as a 

separate unit with a separate date for 

commencement of commercial 

operation as defined in paragraph (1) or 

(2) of this definition as appropriate. 

Common designated representative 

means, with regard to a control period 

in a given year, a designated 

representative where, as of April 1 

immediately after the allowance transfer 

deadline for such control period, the 

same natural person is authorized under 

§§ 97.713(a) and 97.715(a) as the 

designated representative for a group of 

one or more TR SO2 Group 2 sources 

and units located in a State (and Indian 

country within the borders of such 

State). 

Common designated representative’s 

assurance level means, with regard to a 

specific common designated 

representative and a State (and Indian 

country within the borders of such 

State) and control period in a given year 

for which the State assurance level is 

exceeded as described in 

§ 97.706(c)(2)(iii), the common 

designated representative’s share of the 

State SO2 Group 2 trading budget with 

the variability limit for the State for 

such control period. 

Common designated representative’s 

share means, with regard to a specific 

common designated representative for a 

control period in a given year: 

(1) With regard to a total amount of 

SO2 emissions from all TR SO2 Group 2 

units in a State (and Indian country 

within the borders of such State) during 

such control period, the total tonnage of 

SO2 emissions during such control 

period from a group of one or more TR 

SO2 Group 2 units located in such State 

(and such Indian country) and having 

the common designated representative 

for such control period; 

(2) With regard to a State SO2 Group 

2 trading budget with the variability 

limit for such control period, the 

amount (rounded to the nearest 

allowance) equal to the sum of the total 

amount of TR SO2 Group 2 allowances 

allocated for such control period to a 

group of one or more TR SO2 Group 2 

units located in the State (and Indian 

country within the borders of such 

State) and having the common 

designated representative for such 

control period and of the total amount 

of TR SO2 Group 2 allowances 

purchased by an owner or operator of 

such TR SO2 Group 2 units in an 

auction for such control period and 

submitted by the State or the permitting 

authority to the Administrator for 

recordation in the compliance accounts 

for such TR SO2 Group 2 units in 

accordance with the TR SO2 Group 2 

allowance auction provisions in a SIP 

revision approved by the Administrator 

under § 52.39(h) or (i) of this chapter, 

multiplied by the sum of the State SO2

Group 2 trading budget under 

§ 97.710(a) and the State’s variability 

limit under § 97.710(b) for such control 

period and divided by such State SO2

Group 2 trading budget; 

(3) Provided that, in the case of a unit 

that operates during, but has no amount 

of TR SO2 Group 2 allowances allocated 

under §§ 97.711 and 97.712 for, such 

control period, the unit shall be treated, 

solely for purposes of this definition, as 

being allocated an amount (rounded to 

the nearest allowance) of TR SO2 Group 

2 allowances for such control period 

equal to the unit’s allowable SO2

emission rate applicable to such control 

period, multiplied by a capacity factor 

of 0.85 (if the unit is a boiler combusting 

any amount of coal or coal-derived fuel 

during such control period), 0.24 (if the 

unit is a simple combustion turbine 

during such control period), 0.67 (if the 

unit is a combined cycle turbine during 

such control period), 0.74 (if the unit is 

an integrated coal gasification combined 

cycle unit during such control period), 

or 0.36 (for any other unit), multiplied 

by the unit’s maximum hourly load as 

reported in accordance with this subpart 

and by 8,760 hours/control period, and 

divided by 2,000 lb/ton. 

Common stack means a single flue 

through which emissions from 2 or 

more units are exhausted. 

Compliance account means an 

Allowance Management System 

account, established by the 

Administrator for a TR SO2 Group 2 

source under this subpart, in which any 

TR SO2 Group 2 allowance allocations 

to the TR SO2 Group 2 units at the 

source are recorded and in which are 

held any TR SO2 Group 2 allowances 

available for use for a control period in 

a given year in complying with the 

source’s TR SO2 Group 2 emissions 

limitation in accordance with §§ 97.706 

and 97.724. 

Continuous emission monitoring 

system or CEMS means the equipment 

required under this subpart to sample, 

analyze, measure, and provide, by 

means of readings recorded at least once 

every 15 minutes and using an 

automated data acquisition and 

handling system (DAHS), a permanent 

record of SO2 emissions, stack gas 

volumetric flow rate, stack gas moisture 

content, and O2 or CO2 concentration (as 

applicable), in a manner consistent with 

part 75 of this chapter and §§ 97.730 

through 97.735. The following systems 

are the principal types of continuous 

emission monitoring systems: 

(1) A flow monitoring system, 

consisting of a stack flow rate monitor 

and an automated data acquisition and 

handling system and providing a 

permanent, continuous record of stack 

gas volumetric flow rate, in standard 

cubic feet per hour (scfh); 

(2) A SO2 monitoring system, 

consisting of a SO2 pollutant 

concentration monitor and an 

automated data acquisition and 

handling system and providing a 

permanent, continuous record of SO2

emissions, in parts per million (ppm); 

(3) A moisture monitoring system, as 

defined in § 75.11(b)(2) of this chapter 

and providing a permanent, continuous 

record of the stack gas moisture content, 

in percent H2O; 

(4) A CO2 monitoring system, 

consisting of a CO2 pollutant 

concentration monitor (or an O2 monitor 

plus suitable mathematical equations 

from which the CO2 concentration is 

derived) and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of CO2 emissions, in percent CO2; 

and 

(5) An O2 monitoring system, 

consisting of an O2 concentration 

monitor and an automated data 

acquisition and handling system and 

providing a permanent, continuous 

record of O2, in percent O2. 

Control period means the period 

starting January 1 of a calendar year, 

except as provided in § 97.706(c)(3), and 

ending on December 31 of the same 

year, inclusive. 

Designated representative means, for 

a TR SO2 Group 2 source and each TR 

SO2 Group 2 unit at the source, the 

natural person who is authorized by the 

owners and operators of the source and 

all such units at the source, in 

accordance with this subpart, to 

represent and legally bind each owner 

and operator in matters pertaining to the 

TR SO2 Group 2 Trading Program. If the 

TR SO2 Group 2 source is also subject 

to the Acid Rain Program, TR NOX

Annual Trading Program, or TR NOX

Ozone Season Trading Program, then 

this natural person shall be the same 


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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 (ii), natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material for the purpose of creating 

useful heat. 

Fossil-fuel-fired means, with regard to 

a unit, combusting any amount of fossil 

fuel in 2005 or any calendar year 

thereafter. 

General account means an Allowance 

Management System account, 

established under this subpart, that is 

not a compliance account or an 

assurance account. 

Generator means a device that 

produces electricity. 

Gross electrical output means, for a 

unit, electricity made available for use, 

including any such electricity used in 

the power production process (which 

process includes, but is not limited to, 

any on-site processing or treatment of 

fuel combusted at the unit and any onsite emission controls). 

Heat input means, for a unit for a 

specified period of time, the product (in 

mmBtu/time) of the gross calorific value 

of the fuel (in mmBtu/lb) fed into the 

unit multiplied by the fuel feed rate (in 

lb of fuel/time), as measured, recorded, 

and reported to the Administrator by the 

designated representative and as 

modified by the Administrator in 

accordance with this subpart and 

excluding the heat derived from 

preheated combustion air, recirculated 

flue gases, or exhaust. 

Heat input rate means, for a unit, the 

amount of heat input (in mmBtu) 

divided by unit operating time (in hr) 

or, for a unit and a specific fuel, the 

amount of heat input attributed to the 

fuel (in mmBtu) divided by the unit 

operating time (in hr) during which the 

unit combusts the fuel. 

Heat rate means, for a unit, the unit’s 

maximum design heat input (in Btu/hr), 

divided by the product of 1,000,000 

Btu/mmBtu and the unit’s maximum 

hourly load. 

Indian country means ‘‘Indian 

country’’ as defined in 18 U.S.C. 1151. 

Life-of-the-unit, firm power 

contractual arrangement means a unit 

participation power sales agreement 

under which a utility or industrial 

customer reserves, or is entitled to 

receive, a specified amount or 

percentage of nameplate capacity and 

associated energy generated by any 

specified unit and pays its proportional 

amount of such unit’s total costs, 

pursuant to a contract: 

(1) For the life of the unit; 

(2) For a cumulative term of no less 

than 30 years, including contracts that 

permit an election for early termination; 

or 

(3) For a period no less than 25 years 

or 70 percent of the economic useful life 

of the unit determined as of the time the 

unit is built, with option rights to 

purchase or release some portion of the 

nameplate capacity and associated 

energy generated by the unit at the end 

of the period. 

Maximum design heat input means, 

for a unit, the maximum amount of fuel 

per hour (in Btu/hr) that the unit is 

capable of combusting on a steady state 

basis as of the initial installation of the 

unit as specified by the manufacturer of 

the unit. 

Monitoring system means any 

monitoring system that meets the 

requirements of this subpart, including 

a continuous emission monitoring 

system, an alternative monitoring 

system, or an excepted monitoring 

system under part 75 of this chapter. 

Nameplate capacity means, starting 

from the initial installation of a 

generator, the maximum electrical 

generating output (in MWe, rounded to 

the nearest tenth) that the generator is 

capable of producing on a steady state 

basis and during continuous operation 

(when not restricted by seasonal or 

other deratings) as of such installation 

as specified by the manufacturer of the 

generator or, starting from the 

completion of any subsequent physical 

change in the generator resulting in an 

increase in the maximum electrical 

generating output that the generator is 

capable of producing on a steady state 

basis and during continuous operation 

(when not restricted by seasonal or 

other deratings), such increased 

maximum amount (in MWe, rounded to 

the nearest tenth) as of such completion 

as specified by the person conducting 

the physical change. 

Natural gas means ‘‘natural gas’’ as 

defined in § 72.2 of this chapter. 

Newly affected TR SO2 Group 2 unit 

means a unit that was not a TR SO2

Group 2 unit when it began operating 

but that thereafter becomes a TR SO2

Group 2 unit. 

Operate or operation means, with 

regard to a unit, to combust fuel. 

Operator means, for a TR SO2 Group 

2 source or a TR SO2 Group 2 unit at 

a source respectively, any person who 

operates, controls, or supervises a TR 

SO2 Group 2 unit at the source or the 

TR SO2 Group 2 unit and shall include, 

but not be limited to, any holding 

company, utility system, or plant 

manager of such source or unit. 

Owner means, for a TR SO2 Group 2 

source or a TR SO2 Group 2 unit at a 

source respectively, any of the following 

persons: 

(1) Any holder of any portion of the 

legal or equitable title in a TR SO2

Group 2 unit at the source or the TR SO2

Group 2 unit; 

(2) Any holder of a leasehold interest 

in a TR SO2 Group 2 unit at the source 

or the TR SO2 Group 2 unit, provided 

that, unless expressly provided for in a 

leasehold agreement, ‘‘owner’’ shall not 

include a passive lessor, or a person 

who has an equitable interest through 

such lessor, whose rental payments are 

not based (either directly or indirectly) 

on the revenues or income from such TR 

SO2 Group 2 unit; and 

(3) Any purchaser of power from a TR 

SO2 Group 2 unit at the source or the 

TR SO2 Group 2 unit under a life-of-theunit, firm power contractual 

arrangement. 

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, 


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information, or correspondence, by the 

Administrator in the regular course of 

business. 

Recordation, record, or recorded 

means, with regard to TR SO2 Group 2 

allowances, the moving of TR SO2

Group 2 allowances by the 

Administrator into, out of, or between 

Allowance Management System 

accounts, for purposes of allocation, 

auction, transfer, or deduction. 

Reference method means any direct 

test method of sampling and analyzing 

for an air pollutant as specified in 

§ 75.22 of this chapter. 

Replacement, replace, or replaced 

means, with regard to a unit, the 

demolishing of a unit, or the permanent 

retirement and permanent disabling of a 

unit, and the construction of another 

unit (the replacement unit) to be used 

instead of the demolished or retired unit 

(the replaced unit). 

Sequential use of energy means: 

(1) The use of reject heat from 

electricity production in a useful 

thermal energy application or process; 

or 

(2) The use of reject heat from useful 

thermal energy application or process in 

electricity production. 

Serial number means, for a TR SO2

Group 2 allowance, the unique 

identification number assigned to each 

TR SO2 Group 2 allowance by the 

Administrator. 

Solid waste incineration unit means a 

stationary, fossil-fuel-fired boiler or 

stationary, fossil-fuel-fired combustion 

turbine that is a ‘‘solid waste 

incineration unit’’ as defined in section 

129(g)(1) of the Clean Air Act. 

Source means all buildings, 

structures, or installations located in 

one or more contiguous or adjacent 

properties under common control of the 

same person or persons. This definition 

does not change or otherwise affect the 

definition of ‘‘major source’’, ‘‘stationary 

source’’, or ‘‘source’’ as set forth and 

implemented in a title V operating 

permit program or any other program 

under the Clean Air Act. 

State means one of the States that is 

subject to the TR SO2 Group 2 Trading 

Program pursuant to § 52.39(a), (c), (g), 

(h), and (i) of this chapter. 

Submit or serve means to send or 

transmit a document, information, or 

correspondence to the person specified 

in accordance with the applicable 

regulation: 

(1) In person; 

(2) By United States Postal Service; or 

(3) By other means of dispatch or 

transmission and delivery; 

(4) Provided that compliance with any 

‘‘submission’’ or ‘‘service’’ deadline 

shall be determined by the date of 

dispatch, transmission, or mailing and 

not the date of receipt. 

Topping-cycle unit means a unit in 

which the energy input to the unit is 

first used to produce useful power, 

including electricity, where at least 

some of the reject heat from the 

electricity production is then used to 

provide useful thermal energy. 

Total energy input means, for a unit, 

total energy of all forms supplied to the 

unit, excluding energy produced by the 

unit. Each form of energy supplied shall 

be measured by the lower heating value 

of that form of energy calculated as 

follows: 

LHV = HHV ¥ 10.55(W + 9H) 

Where: 

LHV = lower heating value of the form of 

energy in Btu/lb, 

HHV = higher heating value of the form of 

energy in Btu/lb, 

W = weight % of moisture in the form of 

energy, and 

H = weight % of hydrogen in the form of 

energy. 

Total energy output means, for a unit, 

the sum of useful power and useful 

thermal energy produced by the unit. 

TR NOX Annual Trading Program 

means a multi-state NOX air pollution 

control and emission reduction program 

established in accordance with subpart 

AAAAA of this part and § 52.38(a) of 

this chapter (including such a program 

that is revised in a SIP revision 

approved by the Administrator under 

§ 52.38(a)(3) or (4) of this chapter or that 

is established in a SIP revision approved 

by the Administrator under § 52.38(a)(5) 

of this chapter), as a means of mitigating 

interstate transport of fine particulates 

and NOX.

TR NOX Ozone Season Trading 

Program means a multi-state NOX air 

pollution control and emission 

reduction program established in 

accordance with subpart BBBBB of this 

part and § 52.38(b) of this chapter 

(including such a program that is 

revised in a SIP revision approved by 

the Administrator under § 52.38(b)(3) or 

(4) of this chapter or that is established 

in a SIP revision approved by the 

Administrator under § 52.38(b)(5) of this 

chapter), as a means of mitigating 

interstate transport of ozone and NOX.

TR SO2 Group 2 allowance means a 

limited authorization issued and 

allocated or auctioned by the 

Administrator under this subpart, or by 

a State or permitting authority under a 

SIP revision approved by the 

Administrator under § 52.39(g), (h), or 

(i) of this chapter, to emit one ton of SO2

during a control period of the specified 

calendar year for which the 

authorization is allocated or auctioned 

or of any calendar year thereafter under 

the TR SO2 Group 2 Trading Program. 

TR SO2 Group 2 allowance deduction 

or deduct TR SO2 Group 2 allowances 

means the permanent withdrawal of TR 

SO2 Group 2 allowances by the 

Administrator from a compliance 

account (e.g., in order to account for 

compliance with the TR SO2 Group 2 

emissions limitation) or from an 

assurance account (e.g., in order to 

account for compliance with the 

assurance provisions under §§ 97.706 

and 97.725). 

TR SO2 Group 2 allowances held or 

hold TR SO2 Group 2 allowances means 

the TR SO2 Group 2 allowances treated 

as included in an Allowance 

Management System account as of a 

specified point in time because at that 

time they: 

(1) Have been recorded by the 

Administrator in the account or 

transferred into the account by a 

correctly submitted, but not yet 

recorded, TR SO2 Group 2 allowance 

transfer in accordance with this subpart; 

and 

(2) Have not been transferred out of 

the account by a correctly submitted, 

but not yet recorded, TR SO2 Group 2 

allowance transfer in accordance with 

this subpart. 

TR SO2 Group 2 emissions limitation 

means, for a TR SO2 Group 2 source, the 

tonnage of SO2 emissions authorized in 

a control period by the TR SO2 Group 

2 allowances available for deduction for 

the source under § 97.724(a) for such 

control period. 

TR SO2 Group 2 source means a 

source that includes one or more TR 

SO2 Group 2 units. 

TR SO2 Group 2 Trading Program 

means a multi-state SO2 air pollution 

control and emission reduction program 

established in accordance with this 

subpart and § 52.39(a), (c), and (g) 

through (k) of this chapter (including 

such a program that is revised in a SIP 

revision approved by the Administrator 

under § 52.39(g) or (h) of this chapter or 

that is established in a SIP revision 

approved by the Administrator under 

§ 52.39(i) of this chapter), as a means of 

mitigating interstate transport of fine 

particulates and SO2.

TR SO2 Group 2 unit means a unit 

that is subject to the TR SO2 Group 2 

Trading Program under § 97.704. 

Unit means a stationary, fossil-fuelfired 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 


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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 onsite emission controls). 

Useful thermal energy means thermal 

energy that is: 

(1) Made available to an industrial or 

commercial process (not a power 

production process), excluding any heat 

contained in condensate return or 

makeup water; 

(2) Used in a heating application (e.g., 

space heating or domestic hot water 

heating); or 

(3) Used in a space cooling 

application (i.e., in an absorption 

chiller). 

Utility power distribution system 

means the portion of an electricity grid 

owned or operated by a utility and 

dedicated to delivering electricity to 

customers. 

§ 97.703 Measurements, abbreviations, 

and acronyms. 

Measurements, abbreviations, and 

acronyms used in this subpart are 

defined as follows: 

Btu—British thermal unit 

CO2—carbon dioxide 

H2O—water 

hr—hour 

kW—kilowatt electrical 

kWh—kilowatt hour 

lb—pound 

mmBtu—million Btu 

MWe—megawatt electrical 

MWh—megawatt hour 

NOX—nitrogen oxides 

O2—oxygen 

ppm—parts per million 

scfh—standard cubic feet per hour 

SO2—sulfur dioxide 

yr—year 

§ 97.704 Applicability. 

(a) Except as provided in paragraph 

(b) of this section: 

(1) The following units in a State (and 

Indian country within the borders of 

such State) shall be TR SO2 Group 2 

units, and any source that includes one 

or more such units shall be a TR SO2

Group 2 source, subject to the 

requirements of this subpart: Any 

stationary, 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 2 unit begins to combust 

fossil fuel or to serve a generator with 

nameplate capacity of more than 25 

MWe producing electricity for sale, the 

unit shall become a TR SO2 Group 2 

unit as provided in paragraph (a)(1) of 

this section on the first date on which 

it both combusts fossil fuel and serves 

such generator. 

(b) Any unit in a State (and Indian 

country within the borders of such 

State) that otherwise is a TR SO2 Group 

2 unit under paragraph (a) of this 

section and that meets the requirements 

set forth in paragraph (b)(1)(i) or (2)(i) of 

this section shall not be a TR SO2 Group 

2 unit: 

(1)(i) Any unit: 

(A) Qualifying as a cogeneration unit 

throughout the later of 2005 or the 

12-month period starting on the date the 

unit first produces electricity and 

continuing to qualify as a cogeneration 

unit throughout each calendar year 

ending after the later of 2005 or such 

12-month period; and 

(B) Not supplying in 2005 or any 

calendar year thereafter more than onethird of the unit’s potential electric 

output capacity or 219,000 MWh, 

whichever is greater, to any utility 

power distribution system for sale. 

(ii) If, after qualifying under 

paragraph (b)(1)(i) of this section as not 

being a TR SO2 Group 2 unit, a unit 

subsequently no longer meets all the 

requirements of paragraph (b)(1)(i) of 

this section, the unit shall become a TR 

SO2 Group 2 unit starting on the earlier 

of January 1 after the first calendar year 

during which the unit first no longer 

qualifies as a cogeneration unit or 

January 1 after the first calendar year 

during which the unit no longer meets 

the requirements of paragraph 

(b)(1)(i)(B) of this section. The unit shall 

thereafter continue to be a TR SO2

Group 2 unit. 

(2)(i) Any unit: 

(A) Qualifying as a solid waste 

incineration unit throughout the later of 

2005 or the 12-month period starting on 

the date the unit first produces 

electricity and continuing to qualify as 

a solid waste incineration unit 

throughout each calendar year ending 

after the later of 2005 or such 12-month 

period; and 

(B) With an average annual fuel 

consumption of fossil fuel for the first 

3 consecutive calendar years of 

operation starting no earlier than 2005 

of less than 20 percent (on a Btu basis) 

and an average annual fuel consumption 

of fossil fuel for any 3 consecutive 

calendar years thereafter of less than 20 

percent (on a Btu basis). 

(ii) If, after qualifying under 

paragraph (b)(2)(i) of this section as not 

being a TR SO2 Group 2 unit, a unit 

subsequently no longer meets all the 

requirements of paragraph (b)(1)(i) of 

this section, the unit shall become a TR 

SO2 Group 2 unit starting on the earlier 

of January 1 after the first calendar year 

during which the unit first no longer 

qualifies as a solid waste incineration 

unit or January 1 after the first 3 

consecutive calendar years after 2005 

for which the unit has an average 

annual fuel consumption of fossil fuel of 

20 percent or more. The unit shall 

thereafter continue to be a TR SO2

Group 2 unit. 

(c) A certifying official of an owner or 

operator of any unit or other equipment 

may submit a petition (including any 

supporting documents) to the 

Administrator at any time for a 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section or a SIP revision 

approved under § 52.39(h) or (i) of this 

chapter, of the TR SO2 Group 2 Trading 

Program to the unit or other equipment. 

(1) Petition content. The petition shall 

be in writing and include the 

identification of the unit or other 

equipment and the relevant facts about 

the unit or other equipment. The 

petition and any other documents 

provided to the Administrator in 

connection with the 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 


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and may request supplemental 

information determined by the 

Administrator to be relevant to such 

petition. The Administrator’s 

determination concerning the 

applicability, under paragraphs (a) and 

(b) of this section, of the TR SO2 Group 

2 Trading Program to the unit or other 

equipment shall be binding on any State 

or permitting authority unless the 

Administrator determines that the 

petition or other documents or 

information provided in connection 

with the petition contained significant, 

relevant errors or omissions. 

§ 97.705 Retired unit exemption. 

(a)(1) Any TR SO2 Group 2 unit that 

is permanently retired shall be exempt 

from § 97.706(b) and (c)(1), § 97.724, 

and §§ 97.730 through 97.735. 

(2) The exemption under paragraph 

(a)(1) of this section shall become 

effective the day on which the TR SO2

Group 2 unit is permanently retired. 

Within 30 days of the unit’s permanent 

retirement, the designated 

representative shall submit a statement 

to the Administrator. The statement 

shall state, in a format prescribed by the 

Administrator, that the unit was 

permanently retired on a specified date 

and will comply with the requirements 

of paragraph (b) of this section. 

(b) Special provisions. (1) A unit 

exempt under paragraph (a) of this 

section shall not emit any SO2, starting 

on the date that the exemption takes 

effect. 

(2) For a period of 5 years from the 

date the records are created, the owners 

and operators of a unit exempt under 

paragraph (a) of this section shall retain, 

at the source that includes the unit, 

records demonstrating that the unit is 

permanently retired. The 5-year period 

for keeping records may be extended for 

cause, at any time before the end of the 

period, in writing by the Administrator. 

The owners and operators bear the 

burden of proof that the unit is 

permanently retired. 

(3) The owners and operators and, to 

the extent applicable, the designated 

representative of a unit exempt under 

paragraph (a) of this section shall 

comply with the requirements of the TR 

SO2 Group 2 Trading Program 

concerning all periods for which the 

exemption is not in effect, even if such 

requirements arise, or must be complied 

with, after the exemption takes effect. 

(4) A unit exempt under paragraph (a) 

of this section shall lose its exemption 

on the first date on which the unit 

resumes operation. Such unit shall be 

treated, for purposes of applying 

allocation, monitoring, reporting, and 

recordkeeping requirements under this 

subpart, as a unit that commences 

commercial operation on the first date 

on which the unit resumes operation. 

§ 97.706 Standard requirements. 

(a) Designated representative 

requirements. The owners and operators 

shall comply with the requirement to 

have a designated representative, and 

may have an alternate designated 

representative, in accordance with 

§§ 97.713 through 97.718. 

(b) Emissions monitoring, reporting, 

and recordkeeping requirements. (1) 

The owners and operators, and the 

designated representative, of each TR 

SO2 Group 2 source and each TR SO2

Group 2 unit at the source shall comply 

with the monitoring, reporting, and 

recordkeeping requirements of §§ 97.730 

through 97.735. 

(2) The emissions data determined in 

accordance with §§ 97.730 through 

97.735 shall be used to calculate 

allocations of TR SO2 Group 2 

allowances under §§ 97.711(a)(2) and (b) 

and 97.712 and to determine 

compliance with the TR SO2 Group 2 

emissions limitation and assurance 

provisions under paragraph (c) of this 

section, provided that, for each 

monitoring location from which mass 

emissions are reported, the mass 

emissions amount used in calculating 

such allocations and determining such 

compliance shall be the mass emissions 

amount for the monitoring location 

determined in accordance with 

§§ 97.730 through 97.735 and rounded 

to the nearest ton, with any fraction of 

a ton less than 0.50 being deemed to be 

zero. 

(c) SO2 emissions requirements. (1) 

TR SO2 Group 2 emissions limitation. (i) 

As of the allowance transfer deadline for 

a control period in a given year, the 

owners and operators of each TR SO2

Group 2 source and each TR SO2 Group 

2 unit at the source shall hold, in the 

source’s compliance account, TR SO2

Group 2 allowances available for 

deduction for such control period under 

§ 97.724(a) in an amount not less than 

the tons of total SO2 emissions for such 

control period from all TR SO2 Group 2 

units at the source. 

(ii) If total SO2 emissions during a 

control period in a given year from the 

TR SO2 Group 2 units at a TR SO2

Group 2 source are in excess of the TR 

SO2 Group 2 emissions limitation set 

forth in paragraph (c)(1)(i) of this 

section, then: 

(A) The owners and operators of the 

source and each TR SO2 Group 2 unit 

at the source shall hold the TR SO2

Group 2 allowances required for 

deduction under § 97.724(d); and 

(B) The owners and operators of the 

source and each TR SO2 Group 2 unit 

at the source shall pay any fine, penalty, 

or assessment or comply with any other 

remedy imposed, for the same 

violations, under the Clean Air Act, and 

each ton of such excess emissions and 

each day of such control period shall 

constitute a separate violation of this 

subpart and the Clean Air Act. 

(2) TR SO2 Group 2 assurance 

provisions. (i) If total SO2 emissions 

during a control period in a given year 

from all TR SO2 Group 2 units at TR SO2

Group 2 sources in a State (and Indian 

country within the borders of such 

State) exceed the State assurance level, 

then the owners and operators of such 

sources and units in each group of one 

or more sources and units having a 

common designated representative for 

such control period, where the common 

designated representative’s share of 

such SO2 emissions during such control 

period exceeds the common designated 

representative’s assurance level for the 

State and such control period, shall 

hold (in the assurance account 

established for the owners and operators 

of such group) TR SO2 Group 2 

allowances available for deduction for 

such control period under § 97.725(a) in 

an amount equal to two times the 

product (rounded to the nearest whole 

number), as determined by the 

Administrator in accordance with 

§ 97.725(b), of multiplying— 

(A) The quotient of the amount by 

which the common designated 

representative’s share of such SO2

emissions exceeds the common 

designated representative’s assurance 

level divided by the sum of the 

amounts, determined for all common 

designated representatives for such 

sources and units in the State (and 

Indian country within the borders of 

such State) for such control period, by 

which each common designated 

representative’s share of such SO2

emissions exceeds the respective 

common designated representative’s 

assurance level; and 

(B) The amount by which total SO2

emissions from all TR SO2 Group 2 

units at TR SO2 Group 2 sources in the 

State (and Indian country within the 

borders of such State) for such control 

period exceed the State assurance level. 

(ii) The owners and operators shall 

hold the TR SO2 Group 2 allowances 

required under paragraph (c)(2)(i) of this 

section, as of midnight of November 1 

(if it is a business day), or midnight of 

the first business day thereafter (if 

November 1 is not a business day), 

immediately after such control period. 

(iii) Total SO2 emissions from all TR 

SO2 Group 2 units at TR SO2 Group 2 


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sources in a State (and Indian country 

within the borders of such State) during 

a control period in a given year exceed 

the State assurance level if such total 

SO2 emissions exceed the sum, for such 

control period, of the State SO2 Group 

2 trading budget under § 97.710(a) and 

the State’s variability limit under 

§ 97.710(b). 

(iv) It shall not be a violation of this 

subpart or of the Clean Air Act if total 

SO2 emissions from all TR SO2 Group 2 

units at TR SO2 Group 2 sources in a 

State (and Indian country within the 

borders of such State) during a control 

period exceed the State assurance level 

or if a common designated 

representative’s share of total SO2

emissions from the TR SO2 Group 2 

units at TR SO2 Group 2 sources in a 

State (and Indian country within the 

borders of such State) during a control 

period exceeds the common designated 

representative’s assurance level. 

(v) To the extent the owners and 

operators fail to hold TR SO2 Group 2 

allowances for a control period in a 

given year in accordance with 

paragraphs (c)(2)(i) through (iii) of this 

section, 

(A) The owners and operators shall 

pay any fine, penalty, or assessment or 

comply with any other remedy imposed 

under the Clean Air Act; and 

(B) Each TR SO2 Group 2 allowance 

that the owners and operators fail to 

hold for such control period in 

accordance with paragraphs (c)(2)(i) 

through (iii) of this section and each day 

of such control period shall constitute a 

separate violation of this subpart and 

the Clean Air Act. 

(3) Compliance periods. A TR SO2

Group 2 unit shall be subject to the 

requirements under paragraphs (c)(1) 

and (c)(2) of this section for the control 

period starting on the later of January 1, 

2012 or the deadline for meeting the 

unit’s monitor certification 

requirements under § 97.730(b) and for 

each control period thereafter. 

(4) Vintage of allowances held for 

compliance. (i) A TR SO2 Group 2 

allowance held for compliance with the 

requirements under paragraph (c)(1)(i) 

of this section for a control period in a 

given year must be a TR SO2 Group 2 

allowance that was allocated for such 

control period or a control period in a 

prior year. 

(ii) A TR SO2 Group 2 allowance held 

for compliance with the requirements 

under paragraphs (c)(1)(ii)(A) and (2)(i) 

through (iii) of this section for a control 

period in a given year must be a TR SO2

Group 2 allowance that was allocated 

for a control period in a prior year or the 

control period in the given year or in the 

immediately following year. 

(5) Allowance Management System 

requirements. Each TR SO2 Group 2 

allowance shall be held in, deducted 

from, or transferred into, out of, or 

between Allowance Management 

System accounts in accordance with 

this subpart. 

(6) Limited authorization. A TR SO2

Group 2 allowance is a limited 

authorization to emit one ton of SO2

during the control period in one year. 

Such authorization is limited in its use 

and duration as follows: 

(i) Such authorization shall only be 

used in accordance with the TR SO2

Group 2 Trading Program; and 

(ii) Notwithstanding any other 

provision of this subpart, the 

Administrator has the authority to 

terminate or limit the use and duration 

of such authorization to the extent the 

Administrator determines is necessary 

or appropriate to implement any 

provision of the Clean Air Act. 

(7) Property right. A TR SO2 Group 2 

allowance does not constitute a property 

right. 

(d) Title V permit requirements. (1) No 

title V permit revision shall be required 

for any allocation, holding, deduction, 

or transfer of TR SO2 Group 2 

allowances in accordance with this 

subpart. 

(2) A description of whether a unit is 

required to monitor and report SO2

emissions using a continuous emission 

monitoring system (under subpart H of 

part 75 of this chapter), an excepted 

monitoring system (under appendices D 

and E to part 75 of this chapter), a low 

mass emissions excepted monitoring 

methodology (under § 75.19 of this 

chapter), or an alternative monitoring 

system (under subpart E of part 75 of 

this chapter) in accordance with 

§§ 97.730 through 97.735 may be added 

to, or changed in, a title V permit using 

minor permit modification procedures 

in accordance with §§ 70.7(e)(2) and 

71.7(e)(1) of this chapter, provided that 

the requirements applicable to the 

described monitoring and reporting (as 

added or changed, respectively) are 

already incorporated in such permit. 

This paragraph explicitly provides that 

the addition of, or change to, a unit’s 

description as described in the prior 

sentence is eligible for minor permit 

modification procedures in accordance 

with §§ 70.7(e)(2)(i)(B) and 

71.7(e)(1)(i)(B) of this chapter. 

(e) Additional recordkeeping and 

reporting requirements. (1) Unless 

otherwise provided, the owners and 

operators of each TR SO2 Group 2 

source and each TR SO2 Group 2 unit 

at the source shall keep on site at the 

source each of the following documents 

(in hardcopy or electronic format) for a 

period of 5 years from the date the 

document is created. This period may 

be extended for cause, at any time 

before the end of 5 years, in writing by 

the Administrator. 

(i) The certificate of representation 

under § 97.716 for the designated 

representative for the source and each 

TR SO2 Group 2 unit at the source and 

all documents that demonstrate the 

truth of the statements in the certificate 

of representation; provided that the 

certificate and documents shall be 

retained on site at the source beyond 

such 5-year period until such certificate 

of representation and documents are 

superseded because of the submission of 

a new certificate of representation under 

§ 97.716 changing the designated 

representative. 

(ii) All emissions monitoring 

information, in accordance with this 

subpart. 

(iii) Copies of all reports, compliance 

certifications, and other submissions 

and all records made or required under, 

or to demonstrate compliance with the 

requirements of, the TR SO2 Group 2 

Trading Program. 

(2) The designated representative of a 

TR SO2 Group 2 source and each TR 

SO2 Group 2 unit at the source shall 

make all submissions required under 

the TR SO2 Group 2 Trading Program, 

except as provided in § 97.718. This 

requirement does not change, create an 

exemption from, or or otherwise affect 

the responsible official submission 

requirements under a title V operating 

permit program in parts 70 and 71 of 

this chapter. 

(f) Liability. (1) Any provision of the 

TR SO2 Group 2 Trading Program that 

applies to a TR SO2 Group 2 source or 

the designated representative of a TR 

SO2 Group 2 source shall also apply to 

the owners and operators of such source 

and of the TR SO2 Group 2 units at the 

source. 

(2) Any provision of the TR SO2

Group 2 Trading Program that applies to 

a TR SO2 Group 2 unit or the designated 

representative of a TR SO2 Group 2 unit 

shall also apply to the owners and 

operators of such unit. 

(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. 


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§ 97.707 Computation of time. 

(a) Unless otherwise stated, any time 

period scheduled, under the TR SO2

Group 2 Trading Program, to begin on 

the occurrence of an act or event shall 

begin on the day the act or event occurs. 

(b) Unless otherwise stated, any time 

period scheduled, under the TR SO2

Group 2 Trading Program, to begin 

before the occurrence of an act or event 

shall be computed so that the period 

ends the day before the act or event 

occurs. 

(c) Unless otherwise stated, if the final 

day of any time period, under the TR 

SO2 Group 2 Trading Program, is not a 

business day, the time period shall be 

extended to the next business day. 

§ 97.708 Administrative appeal 

procedures. 

The administrative appeal procedures 

for decisions of the Administrator under 

the TR SO2 Group 2 Trading Program 

are set forth in part 78 of this chapter. 

§ 97.709 [Reserved] 

§ 97.710 State SO2 Group 2 trading 

budgets, new unit set-asides, Indian 

country new unit set-aside, and variability 

limits. 

(a) The State SO2 Group 2 trading 

budgets, new unit set-asides, and Indian 

country new unit set-asides for 

allocations of TR SO2 Group 2 

allowances for the control periods in 

2012 and thereafter are as follows: 

State 

SO2 Group 2 trading budget (tons) * 

for 2012 and 2013 

New unit set-aside 

(tons) for 2012 and 

2013 

Indian country new 

unit set-aside (tons) 

for 2012 and 2013 

Alabama ............................................................................................................... 216,033 4,321 ................................

Georgia ................................................................................................................ 158,527 3,171 ................................

Kansas ................................................................................................................. 41,528 789 42 

Minnesota ............................................................................................................ 41,981 798 42 

Nebraska .............................................................................................................. 65,052 2,537 65 

South Carolina ..................................................................................................... 88,620 1,683 89 

Texas ................................................................................................................... 243,954 11,954 244 

State 

SO2 Group 2 trading budget (tons) * 

for 2014 and 

thereafter 

New unit set-aside 

(tons) for 2014 and 

thereafter 

Indian country new 

unit set-aside (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 1,683 89 

Texas ................................................................................................................... 243,954 11,954 244 

* Each trading budget includes the new unit set-aside and, where applicable, the Indian country new unit set-aside and does not include the 

variability limit. 

(b) The States’ variability limits for 

the State SO2 Group 2 trading budgets 

for the control periods in 2012 and 

thereafter are as follows: 

State Variability limits 

for 2012 and 2013 

Variability limits 

for 2014 and 

thereafter 

Alabama ........................................................................................................................................... 38,886 38,386 

Georgia ............................................................................................................................................ 28,535 17,142 

Kansas ............................................................................................................................................. 7,475 7,475 

Minnesota ........................................................................................................................................ 7,557 7,557 

Nebraska .......................................................................................................................................... 11,709 11,709 

South Carolina ................................................................................................................................. 15,952 15,952 

Texas ............................................................................................................................................... 43,912 43,912 

§ 97.711 Timing requirements for TR SO2

Group 2 allowance allocations. 

(a) Existing units. (1) TR SO2 Group 2 

allowances are allocated, for the control 

periods in 2012 and each year 

thereafter, as provided in a notice of 

data availability issued by the 

Administrator. Providing an allocation 

to a unit in such notice does not 

constitute a determination that the unit 

is a TR SO2 Group 2 unit, and not 

providing an allocation to a unit in such 

notice does not constitute a 

determination that the unit is not a TR 

SO2 Group 2 unit. 

(2) Notwithstanding paragraph (a)(1) 

of this section, if a unit provided an 

allocation in the notice of data 

availability issued under paragraph 

(a)(1) of this section does not operate, 

starting after 2011, during the control 

period in two consecutive years, such 

unit will not be allocated the TR SO2

Group 2 allowances provided in such 

notice for the unit for the control 

periods in the fifth year after the first 

such year and in each year after that 

fifth year. All TR SO2 Group 2 

allowances that would otherwise have 

been allocated to such unit will be 

allocated to the new unit set-aside for 

the State where such unit is located and 

for the respective years involved. If such 

unit resumes operation, the 

Administrator will allocate TR SO2

Group 2 allowances to the unit in 

accordance with paragraph (b) of this 

section. 


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(b) New units. (1) New unit set-asides. 

(i) By June 1, 2012 and June 1 of each 

year thereafter, the Administrator will 

calculate the TR SO2 Group 2 allowance 

allocation to each TR SO2 Group 2 unit 

in a State, in accordance with 

§ 97.712(a)(2) through (7) and (12), for 

the control period in the year of the 

applicable calculation deadline under 

this paragraph and will promulgate a 

notice of data availability of the results 

of the calculations. 

(ii) For each notice of data availability 

required in paragraph (b)(1)(i) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. 

(A) Objections shall be submitted by 

the deadline specified in each notice of 

data availability required in paragraph 

(b)(1)(i) of this section and shall be 

limited to addressing whether the 

calculations (including the 

identification of the TR SO2 Group 2 

units) are in accordance with 

§ 97.712(a)(2) through (7) and (12) and 

§§ 97.706(b)(2) and 97.730 through 

97.735. 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(1)(ii)(A) of this section. By August 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(1)(i) of this section, the 

Administrator will promulgate a notice 

of data availability of any adjustments 

that the Administrator determines to be 

necessary with regard to allocations 

under § 97.712(a)(2) through (7) and (12) 

and the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(1)(ii)(A) 

of this section. 

(iii) If the new unit set-aside for such 

control period contains any TR SO2

Group 2 allowances that have not been 

allocated in the applicable notice of data 

availability required in paragraph 

(b)(1)(ii) of this section, the 

Administrator will promulgate, by 

December 15 immediately after such 

notice, a notice of data availability that 

identifies any TR SO2 Group 2 units that 

commenced commercial operation 

during the period starting January 1 of 

the year before the year of such control 

period and ending November 30 of year 

of such control period. 

(iv) For each notice of data 

availability required in paragraph 

(b)(1)(iii) of this section, the 

Administrator will provide an 

opportunity for submission of objections 

to the identification of TR SO2 annual 

units in such notice. 

(A) Objections shall be submitted by 

the deadline specified in each notice of 

data availability required in paragraph 

(b)(1)(iii) of this section and shall be 

limited to addressing whether the 

identification of TR SO2 annual units in 

such notice is in accordance with 

paragraph (b)(1)(iii) of this section. 

(B) The Administrator will adjust the 

identification of TR SO2 Group 2 units 

in the each notice of data availability 

required in paragraph (b)(1)(iii) of this 

section to the extent necessary to ensure 

that it is in accordance with paragraph 

(b)(1)(iii) of this section and will 

calculate the TR SO2 Group 2 allowance 

allocation to each TR SO2 Group 2 unit 

in accordance with § 97.712(a)(9), (10), 

and (12) and §§ 97.706(b)(2) and 97.730 

through 97.735. By February 15 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(1)(iii) of this section, 

the Administrator will promulgate a 

notice of data availability of any 

adjustments of the identification of TR 

SO2 Group 2 units that the 

Administrator determines to be 

necessary, the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(1)(iv)(A) 

of this section, and the results of such 

calculations. 

(v) To the extent any TR SO2 Group 

2 allowances are added to the new unit 

set-aside after promulgation of each 

notice of data availability required in 

paragraph (b)(1)(iv) of this section, the 

Administrator will promulgate 

additional notices of data availability, as 

deemed appropriate, of the allocation of 

such TR SO2 Group 2 allowances in 

accordance with § 97.712(a)(10). 

(2) Indian country new unit setasides. (i) By June 1, 2012 and June 1 

of each year thereafter, the 

Administrator will calculate the TR SO2

Group 2 allowance allocation to each TR 

SO2 Group 2 unit in Indian country 

within the borders of a State, in 

accordance with § 97.712(b)(2) through 

(7) and (12), for the control period in the 

year of the applicable calculation 

deadline under this paragraph and will 

promulgate a notice of data availability 

of the results of the calculations. 

(ii) For each notice of data availability 

required in paragraph (b)(2)(i) of this 

section, the Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

in such notice. 

(A) Objections shall be submitted by 

the deadline specified in each notice of 

data availability required in paragraph 

(b)(2)(i) of this section and shall be 

limited to addressing whether the 

calculations (including the 

identification of the TR SO2 Group 2 

units) are in accordance with 

§ 97.712(b)(2) through (7) and (12) and 

§§ 97.706(b)(2) and 97.730 through 

97.735. 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(ii)(A) of this section. By August 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(2)(i) of this section, the 

Administrator will promulgate a notice 

of data availability of any adjustments 

that the Administrator determines to be 

necessary with regard to allocations 

under § 97.712(b)(2) through (7) and (12) 

and the reasons for accepting or 

rejecting any objections submitted in 

accordance with paragraph (b)(2)(ii)(A) 

of this section. 

(iii) If the Indian country new unit 

set-aside for such control period 

contains any TR SO2 Group 2 

allowances that have not been allocated 

in the applicable notice of data 

availability required in paragraph 

(b)(2)(ii) of this section, the 

Administrator will promulgate, by 

December 15 immediately after such 

notice, a notice of data availability that 

identifies any TR SO2 Group 2 units that 

commenced commercial operation 

during the period starting January 1 of 

the year before the year of such control 

period and ending November 30 of year 

of such control period. 

(iv) For each notice of data 

availability required in paragraph 

(b)(2)(iii) of this section, the 

Administrator will provide an 

opportunity for submission of objections 

to the identification of TR SO2 annual 

units in such notice. 

(A) Objections shall be submitted by 

the deadline specified in each notice of 

data availability required in paragraph 

(b)(2)(iii) of this section and shall be 

limited to addressing whether the 

identification of TR SO2 annual units in 

such notice is in accordance with 

paragraph (b)(2)(iii) of this section. 

(B) The Administrator will adjust the 

identification of TR SO2 Group 2 units 

in the each notice of data availability 

required in paragraph (b)(2)(iii) of this 

section to the extent necessary to ensure 

that it is in accordance with paragraph 

(b)(2)(iii) of this section and will 

calculate the TR SO2 Group 2 allowance 

allocation to each TR SO2 Group 2 unit 

in accordance with § 97.712(b)(9), (10), 

and (12) and §§ 97.706(b)(2) and 97.730 

through 97.735. By February 15 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(2)(iii) of this section, 

the Administrator will promulgate a 

notice of data availability of any 


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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. 

(v) To the extent any TR SO2 Group 

2 allowances are added to the Indian 

country new unit set-aside after 

promulgation of each notice of data 

availability required in paragraph 

(b)(2)(iv) of this section, the 

Administrator will promulgate 

additional notices of data availability, as 

deemed appropriate, of the allocation of 

such TR SO2 Group 2 allowances in 

accordance with § 97.712(b)(10). 

(c) Units incorrectly allocated TR SO2

Group 2 allowances. (1) For each control 

period in 2012 and thereafter, if the 

Administrator determines that TR SO2

Group 2 allowances were allocated 

under paragraph (a) of this section, or 

under a provision of a SIP revision 

approved § 52.39(g), (h), or (i) of this 

chapter, where such control period and 

the recipient are covered by the 

provisions of paragraph (c)(1)(i) of this 

section or were allocated under 

§ 97.712(a)(2) through (7), (9), and (12) 

and (b)(2) through (7), (9), and (12), or 

under a provision of a SIP revision 

approved § 52.39(h) or (i) of this 

chapter, where such control period and 

the recipient are covered by the 

provisions of paragraph (c)(1)(ii) of this 

section, then the Administrator will 

notify the designated representative of 

the recipient and will act in accordance 

with the procedures set forth in 

paragraphs (c)(2) through (5) of this 

section: 

(i)(A) The recipient is not actually a 

TR SO2 Group 2 unit under § 97.704 as 

of January 1, 2012 and is allocated TR 

SO2 Group 2 allowances for such 

control period or, in the case of an 

allocation under a provision of a SIP 

revision approved under § 52.39(g), (h), 

or (i) of this chapter, the recipient is not 

actually a TR SO2 Group 2 unit as of 

January 1, 2012 and is allocated TR SO2

Group 2 allowances for such control 

period that the SIP revision provides 

should be allocated only to recipients 

that are TR SO2 Group 2 units as of 

January 1, 2012; or 

(B) The recipient is not located as of 

January 1 of the control period in the 

State from whose SO2 Group 2 trading 

budget the TR SO2 Group 2 allowances 

allocated under paragraph (a) of this 

section, or under a provision of a SIP 

revision approved under § 52.39(g), (h), 

or (i) of this chapter, were allocated for 

such control period. 

(ii) The recipient is not actually a TR 

SO2 Group 2 unit under § 97.704 as of 

January 1 of such control period and is 

allocated TR SO2 Group 2 allowances 

for such control period or, in the case 

of an allocation under a provision of a 

SIP revision approved under § 52.39(g), 

(h), or (i) of this chapter, the recipient 

is not actually a TR SO2 Group 2 unit 

as of January 1 of such control period 

and is allocated TR SO2 Group 2 

allowances for such control period that 

the SIP revision provides should be 

allocated only to recipients that are TR 

SO2 Group 2 units as of January 1 of 

such control period. 

(2) Except as provided in paragraph 

(c)(3) or (4) of this section, the 

Administrator will not record such TR 

SO2 Group 2 allowances under § 97.721. 

(3) If the Administrator already 

recorded such TR SO2 Group 2 

allowances under § 97.721 and if the 

Administrator makes the determination 

under paragraph (c)(1) of this section 

before making deductions for the source 

that includes such recipient under 

§ 97.724(b) for such control period, then 

the Administrator will deduct from the 

account in which such TR SO2 Group 2 

allowances were recorded an amount of 

TR SO2 Group 2 allowances allocated 

for the same or a prior control period 

equal to the amount of such already 

recorded TR SO2 Group 2 allowances. 

The authorized account representative 

shall ensure that there are sufficient TR 

SO2 Group 2 allowances in such 

account for completion of the 

deduction. 

(4) If the Administrator already 

recorded such TR SO2 Group 2 

allowances under § 97.721 and if the 

Administrator makes the determination 

under paragraph (c)(1) of this section 

after making deductions for the source 

that includes such recipient under 

§ 97.724(b) for such control period, then 

the Administrator will not make any 

deduction to take account of such 

already recorded TR SO2 Group 2 

allowances. 

(5)(i) With regard to the TR SO2 Group 

2 allowances that are not recorded, or 

that are deducted as an incorrect 

allocation, in accordance with 

paragraphs (c)(2) and (3) of this section 

for a recipient under paragraph (c)(1)(i) 

of this section, the Administrator will: 

(A) Transfer such TR SO2 Group 2 

allowances to the new unit set-aside for 

such control period for the State from 

whose SO2 Group 2 trading budget the 

TR SO2 Group 2 allowances were 

allocated; or 

(B) If the State has a SIP revision 

approved under § 52.39(h) or (i) 

covering such control period, include 

such TR SO2 Group 2 allowances in the 

portion of the State SO2 Group 2 trading 

budget that may be allocated for such 

control period in accordance with such 

SIP revision. 

(ii) With regard to the TR SO2 Group 

2 allowances that were not allocated 

from the Indian country new unit setaside for such control period and that 

are not recorded, or that are deducted as 

an incorrect allocation, in accordance 

with paragraphs (c)(2) and (3) of this 

section for a recipient under paragraph 

(c)(1)(ii) of this paragraph, the 

Administrator will: 

(A) Transfer such TR SO2 Group 2 

allowances to the new unit set-aside for 

such control period; or 

(B) If the State has a SIP revision 

approved under § 52.39(h) or (i) 

covering such control period, include 

such TR SO2 Group 2 allowances in the 

portion of the State SO2 Group 2 trading 

budget that may be allocated for such 

control period in accordance with such 

SIP revision. 

(iii) With regard to the TR SO2 Group 

2 allowances that were allocated from 

the Indian country new unit set-aside 

for such control period and that are not 

recorded, or that are deducted as an 

incorrect allocation, in accordance with 

paragraphs (c)(2) and (3) of this section 

for a recipient under paragraph (c)(1)(ii) 

of this paragraph, the Administrator will 

transfer such TR SO2 Group 2 

allowances to the Indian country new 

unit set-aside for such control period. 

§ 97.712 TR SO2 Group 2 allowance 

allocations to new units. 

(a) For each control period in 2012 

and thereafter and for the TR SO2 Group 

2 units in each State, the Administrator 

will allocate TR SO2 Group 2 

allowances to the TR SO2 Group 2 units 

as follows: 

(1) The TR SO2 Group 2 allowances 

will be allocated to the following TR 

SO2 Group 2 units, except as provided 

in paragraph (a)(10) of this section: 

(i) TR SO2 Group 2 units that are not 

allocated an amount of TR SO2 Group 2 

allowances in the notice of data 

availability issued under § 97.711(a)(1); 

(ii) TR SO2 Group 2 units whose 

allocation of an amount of TR SO2

Group 2 allowances for such control 

period in the notice of data availability 

issued under § 97.711(a)(1) is covered 

by § 97.711(c)(2) or (3); 

(iii) TR SO2 Group 2 units that are 

allocated an amount of TR SO2 Group 2 

allowances for such control period in 

the notice of data availability issued 

under § 97.711(a)(1), which allocation is 

terminated for such control period 

pursuant to § 97.711(a)(2), and that 

operate during the control period 


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immediately preceding such control 

period; or 

(iv) For purposes of paragraph (a)(9) 

of this section, TR SO2 Group 2 units 

under § 97.711(c)(1)(ii) whose allocation 

of an amount of TR SO2 Group 2 

allowances for such control period in 

the notice of data availability issued 

under § 97.711(b)(1)(ii)(B) is covered by 

§ 97.711(c)(2) or (3). 

(2) The Administrator will establish a 

separate new unit set-aside for the State 

for each such control period. Each such 

new unit 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 

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 State after operating 

in another jurisdiction and for which 

the unit is not already allocated one or 

more TR SO2 Group 2 allowances; and 

(iv) For a unit described in paragraph 

(a)(1)(iii) of this section, the first control 

period after the control period in which 

the unit resumes operation. 

(4)(i) The allocation to each TR SO2

annual unit described in paragraph 

(a)(1)(i) through (iii) of this section and 

for each control period described in 

paragraph (a)(3) of this section will be 

an amount equal to the unit’s total tons 

of SO2 emissions during the 

immediately preceding control period. 

(ii) The Administrator will adjust the 

allocation amount in paragraph (a)(4)(i) 

in accordance with paragraphs (a)(5) 

through (7) and (12) of this section. 

(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 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 

§ 97.711(b)(1)(i) and (ii), of the amount 

of TR SO2 Group 2 allowances allocated 

under paragraphs (a)(2) through (7) and 

(12) of this section for such control 

period to each TR SO2 Group 2 unit 

eligible for such allocation. 

(9) If, after completion of the 

procedures under paragraphs (a)(5) 

through (8) of this section for such 

control period, any unallocated TR SO2

Group 2 allowances remain in the new 

unit set-aside for the State for such 

control period, the Administrator will 

allocate such TR SO2 Group 2 

allowances as follows— 

(i) The Administrator will determine, 

for each unit described in paragraph 

(a)(1) of this section that commenced 

commercial operation during the period 

starting January 1 of the year before the 

year of such control period and ending 

November 30 of year of such control 

period, the positive difference (if any) 

between the unit’s emissions during 

such control period and the amount of 

TR SO2 Group 2 allowances referenced 

in the notice of data availability 

required under § 97.711(b)(1)(ii) for the 

unit for such control period; 

(ii) The Administrator will determine 

the sum of the positive differences 

determined under paragraph (a)(9)(i) of 

this section; 

(iii) If the amount of unallocated TR 

SO2 Group 2 allowances remaining in 

the new unit set-aside for the State for 

such control period is greater than or 

equal to the sum determined under 

paragraph (a)(9)(ii) of this section, then 

the Administrator will allocate the 

amount of TR SO2 Group 2 allowances 

determined for each such TR SO2 Group 

2 unit under paragraph (a)(9)(i) of this 

section; and 

(iv) If the amount of unallocated TR 

SO2 Group 2 allowances remaining in 

the new unit set-aside for the State for 

such control period is less than the sum 

under paragraph (a)(9)(ii) of this section, 

then the Administrator will allocate to 

each such TR SO2 Group 2 unit the 

amount of the TR SO2 Group 2 

allowances determined under paragraph 

(a)(9)(i) of this section for the unit, 

multiplied by the amount of unallocated 

TR SO2 Group 2 allowances remaining 

in the new unit set-aside for such 

control period, divided by the sum 

under paragraph (a)(9)(ii) of this section, 

and rounded to the nearest allowance. 

(10) If, after completion of the 

procedures under paragraphs (a)(9) and 

(12) of this section for such control 

period, any unallocated TR SO2 Group 

2 allowances remain in the new unit setaside 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), (iv), and (v), of the 

amount of TR SO2 Group 2 allowances 

allocated under paragraphs (a)(9), (10), 

and (12) of this section for such control 

period to each TR SO2 Group 2 unit 

eligible for such allocation. 

(12)(i) Notwithstanding the 

requirements of paragraphs (a)(2) 

through (11) of this section, if the 

calculations of allocations of a new unit 

set-aside for a control period in a given 

year under paragraph (a)(7) of this 

section, paragraphs (a)(6) and (9)(iv) of 

this section, or paragraphs (a)(6), (9)(iii), 

and (10) of this section would otherwise 

result in total allocations of such new 

unit set-aside exceeding the total 

amount of such new unit set-aside, then 

the Administrator will adjust the results 

of the calculations under paragraph 

(a)(7), (9)(iv), or (10) of this section, as 

applicable, as follows. The 

Administrator will list the TR SO2

Group 2 units in descending order based 


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on the amount of such units’ allocations 

under paragraph (a)(7), (9)(iv), or (10) of 

this section, as applicable, and, in cases 

of equal allocation amounts, in 

alphabetical order of the relevant 

source’s name and numerical order of 

the relevant unit’s identification 

number, and will reduce each unit’s 

allocation under paragraph (a)(7), 

(9)(iv), or (10) of this section, as 

applicable, by one TR SO2 Group 2 

allowance (but not below zero) in the 

order in which the units are listed and 

will repeat this reduction process as 

necessary, until the total allocations of 

such new unit set-aside equal the total 

amount of such new unit set-aside. 

(ii) Notwithstanding the requirements 

of paragraphs (a)(10) and (11) of this 

section, if the calculations of allocations 

of a new unit set-aside for a control 

period in a given year under paragraphs 

(a)(6), (9)(iii), and (10) of this section 

would otherwise result in a total 

allocations of such new unit set-aside 

less than the total amount of such new 

unit set-aside, then the Administrator 

will adjust the results of the calculations 

under paragraph (a)(10) of this section, 

as follows. The Administrator will list 

the TR SO2 Group 2 units in descending 

order based on the amount of such 

units’ allocations under paragraph 

(a)(10) of this section and, in cases of 

equal allocation amounts, in 

alphabetical order of the relevant 

source’s name and numerical order of 

the relevant unit’s identification 

number, and will increase each unit’s 

allocation under paragraph (a)(10) of 

this section by one TR SO2 Group 2 

allowance in the order in which the 

units are listed and will repeat this 

increase process as necessary, until the 

total allocations of such new unit setaside equal the total amount of such 

new unit set-aside. 

(b) For each control period in 2012 

and thereafter and for the TR SO2 Group 

2 units located in Indian country within 

the borders of each State, the 

Administrator will allocate TR SO2

Group 2 allowances to the TR SO2

Group 2 units as follows: 

(1) The TR SO2 Group 2 allowances 

will be allocated to the following TR 

SO2 Group 2 units, except as provided 

in paragraph (b)(10) of this section: 

(i) TR SO2 Group 2 units that are not 

allocated an amount of TR SO2 Group 2 

allowances in the notice of data 

availability issued under § 97.711(a)(1); 

or 

(ii) For purposes of paragraph (b)(9) of 

this section, TR SO2 Group 2 units 

under § 97.711(c)(1)(ii) whose allocation 

of an amount of TR SO2 Group 2 

allowances for such control period in 

the notice of data availability issued 

under § 97.711(b)(2)(ii)(B) is covered by 

§ 97.711(c)(2) or (3). 

(2) The Administrator will establish a 

separate Indian country new unit setaside for the State for each such control 

period. Each such Indian country new 

unit set-aside will be allocated TR SO2

Group 2 allowances in an amount equal 

to the applicable amount of tons of SO2

emissions as set forth in § 97.710(a) and 

will be allocated additional TR SO2

Group 2 allowances (if any) in 

accordance with § 97.711(c)(5). 

(3) The Administrator will determine, 

for each TR SO2 Group 2 unit described 

in paragraph (b)(1) of this section, an 

allocation of TR SO2 Group 2 

allowances for the later of the following 

control periods and for each subsequent 

control period: 

(i) The control period in 2012; and 

(ii) The first control period after the 

control period in which the TR SO2

Group 2 unit commences commercial 

operation. 

(4)(i) The allocation to each TR SO2

annual unit described in paragraph 

(b)(1)(i) of this section and for each 

control period described in paragraph 

(b)(3) of this section will be an amount 

equal to the unit’s total tons of SO2

emissions during the immediately 

preceding control period. 

(ii) The Administrator will adjust the 

allocation amount in paragraph (b)(4)(i) 

in accordance with paragraphs (b)(5) 

through (7) and (12) of this section. 

(5) The Administrator will calculate 

the sum of the TR SO2 Group 2 

allowances determined for all such TR 

SO2 Group 2 units under paragraph 

(b)(4)(i) of this section in Indian country 

within the borders of the State for such 

control period. 

(6) If the amount of TR SO2 Group 2 

allowances in the Indian country new 

unit set-aside for the State for such 

control period is greater than or equal to 

the sum under paragraph (b)(5) of this 

section, then the Administrator will 

allocate the amount of TR SO2 Group 2 

allowances determined for each such TR 

SO2 Group 2 unit under paragraph 

(b)(4)(i) of this section. 

(7) If the amount of TR SO2 Group 2 

allowances in the Indian country new 

unit set-aside for the State for such 

control period is less than the sum 

under paragraph (b)(5) of this section, 

then the Administrator will allocate to 

each such TR SO2 Group 2 unit the 

amount of the TR SO2 Group 2 

allowances determined under paragraph 

(b)(4)(i) of this section for the unit, 

multiplied by the amount of TR SO2

Group 2 allowances in the Indian 

country new unit set-aside for such 

control period, divided by the sum 

under paragraph (b)(5) of this section, 

and rounded to the nearest allowance. 

(8) The Administrator will notify the 

public, through the promulgation of the 

notices of data availability described in 

§ 97.711(b)(2)(i) and (ii), of the amount 

of TR SO2 Group 2 allowances allocated 

under paragraphs (b)(2) through (7) and 

(12) of this section for such control 

period to each TR SO2 Group 2 unit 

eligible for such allocation. 

(9) If, after completion of the 

procedures under paragraphs (b)(5) 

through (8) of this section for such 

control period, any unallocated TR SO2

Group 2 allowances remain in the 

Indian country new unit 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 referenced 

in the notice of data availability 

required under § 97.711(b)(2)(ii) for the 

unit for such control period; 

(ii) The Administrator will determine 

the sum of the positive differences 

determined under paragraph (b)(9)(i) of 

this section; 

(iii) If the amount of unallocated TR 

SO2 Group 2 allowances remaining in 

the Indian country new unit set-aside 

for the State for such control period is 

greater than or equal to the sum 

determined under paragraph (b)(9)(ii) of 

this section, then the Administrator will 

allocate the amount of TR SO2 Group 2 

allowances determined for each such TR 

SO2 Group 2 unit under paragraph 

(b)(9)(i) of this section; and 

(iv) If the amount of unallocated TR 

SO2 Group 2 allowances remaining in 

the Indian country new unit set-aside 

for the State for such control period is 

less than the sum under paragraph 

(b)(9)(ii) of this section, then the 

Administrator will allocate to each such 

TR SO2 Group 2 unit the amount of the 

TR SO2 Group 2 allowances determined 

under paragraph (b)(9)(i) of this section 

for the unit, multiplied by the amount 

of unallocated TR SO2 Group 2 

allowances remaining in the Indian 

country new unit set-aside for such 

control period, divided by the sum 

under paragraph (b)(9)(ii) of this section, 

and rounded to the nearest allowance. 

(10) If, after completion of the 

procedures under paragraphs (b)(9) and 

(12) of this section for such control 


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Federal Register / Vol. 76, No. 152 / Monday, August 8, 2011 / Rules and Regulations 48471 

period, any unallocated TR SO2 Group 

2 allowances remain in the Indian 

country new unit set-aside for the State 

for such control period, the 

Administrator will: 

(i) Transfer such unallocated TR SO2

Group 2 allowances to the new unit setaside for the State for such control 

period; or 

(ii) If the State has a SIP revision 

approved under § 52.39(g), (h), or (i) of 

this chapter covering such control 

period, include such unallocated TR 

SO2 Group 2 allowances in the portion 

of the State SO2 Group 2 trading budget 

that may be allocated for such control 

period in accordance with such SIP 

revision. 

(11) The Administrator will notify the 

public, through the promulgation of the 

notices of data availability described in 

§ 97.711(b)(2)(iii), (iv), and (v), of the 

amount of TR SO2 Group 2 allowances 

allocated under paragraphs (b)(9), (10), 

and (12) of this section for such control 

period to each TR SO2 Group 2 unit 

eligible for such allocation. 

(12)(i) Notwithstanding the 

requirements of paragraphs (b)(2) 

through (11) of this section, if the 

calculations of allocations of an Indian 

country new unit set-aside for a control 

period in a given year under paragraph 

(b)(7) of this section, paragraphs (b)(6) 

and (9)(iv) of this section, or paragraphs 

(b)(6), (9)(iii), and (10) of this section 

would otherwise result in total 

allocations of such Indian country new 

unit set-aside exceeding the total 

amount of such Indian country new unit 

set-aside, then the Administrator will 

adjust the results of the calculations 

under paragraph (b)(7), (9)(iv), or (10) of 

this section, as applicable, as follows. 

The Administrator will list the TR SO2

Group 2 units in descending order based 

on the amount of such units’ allocations 

under paragraph (b)(7), (9)(iv), or (10) of 

this section, as applicable, and, in cases 

of equal allocation amounts, in 

alphabetical order of the relevant 

source’s name and numerical order of 

the relevant unit’s identification 

number, and will reduce each unit’s 

allocation under paragraph (b)(7), 

(9)(iv), or (10) of this section, as 

applicable, by one TR SO2 Group 2 

allowance (but not below zero) in the 

order in which the units are listed and 

will repeat this reduction process as 

necessary, until the total allocations of 

such Indian country new unit set-aside 

equal the total amount of such Indian 

country new unit set-aside. 

(ii) Notwithstanding the requirements 

of paragraphs (b)(10) and (11) of this 

section, if the calculations of allocations 

of an Indian country new unit set-aside 

for a control period in a given year 

under paragraphs (b)(6), (9)(iii), and (10) 

of this section would otherwise result in 

a total allocations of such Indian 

country new unit set-aside less than the 

total amount of such Indian country 

new unit set-aside, then the 

Administrator will adjust the results of 

the calculations under paragraph (b)(10) 

of this section, as follows. The 

Administrator will list the TR SO2

Group 2 units in descending order based 

on the amount of such units’ allocations 

under paragraph (b)(10) of this section 

and, in cases of equal allocation 

amounts, in alphabetical order of the 

relevant source’s name and numerical 

order of the relevant unit’s 

identification number, and will increase 

each unit’s allocation under paragraph 

(b)(10) of this section by one TR SO2

Group 2 allowance in the order in 

which the units are listed and will 

repeat this increase process as 

necessary, until the total allocations of 

such Indian country new unit set-aside 

equal the total amount of such Indian 

country new unit set-aside. 

§ 97.713 Authorization of designated 

representative and alternate designated 

representative. 

(a) Except as provided under § 97.715, 

each TR SO2 Group 2 source, including 

all TR SO2 Group 2 units at the source, 

shall have one and only one designated 

representative, with regard to all matters 

under the TR SO2 Group 2 Trading 

Program. 

(1) The designated representative 

shall be selected by an agreement 

binding on the owners and operators of 

the source and all TR SO2 Group 2 units 

at the source and shall act in accordance 

with the certification statement in 

§ 97.716(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.716: 

(i) The designated representative shall 

be authorized and shall represent and, 

by his or her representations, actions, 

inactions, or submissions, legally bind 

each owner and operator of the source 

and each TR SO2 Group 2 unit at the 

source in all matters pertaining to the 

TR SO2 Group 2 Trading Program, 

notwithstanding any agreement between 

the designated representative and such 

owners and operators; and 

(ii) The owners and operators of the 

source and each TR SO2 Group 2 unit 

at the source shall be bound by any 

decision or order issued to the 

designated representative by the 

Administrator regarding the source or 

any such unit. 

(b) Except as provided under § 97.715, 

each TR SO2 Group 2 source may have 

one and only one alternate designated 

representative, who may act on behalf of 

the designated representative. The 

agreement by which the alternate 

designated representative is selected 

shall include a procedure for 

authorizing the alternate designated 

representative to act in lieu of the 

designated representative. 

(1) The alternate designated 

representative shall be selected by an 

agreement binding on the owners and 

operators of the source and all TR SO2

Group 2 units at the source and shall act 

in accordance with the certification 

statement in § 97.716(a)(4)(iii). 

(2) Upon and after receipt by the 

Administrator of a complete certificate 

of representation under § 97.716, 

(i) The alternate designated 

representative shall be authorized; 

(ii) Any representation, action, 

inaction, or submission by the alternate 

designated representative shall be 

deemed to be a representation, action, 

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. 

§ 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 


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those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(b) The Administrator will accept or 

act on a submission made for a TR SO2

Group 2 source or a TR SO2 Group 2 

unit only if the submission has been 

made, signed, and certified in 

accordance with paragraph (a) of this 

section and § 97.718. 

§ 97.715 Changing designated 

representative and alternate designated 

representative; changes in owners and 

operators; changes in units at the source. 

(a) Changing designated 

representative. The designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.716. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous designated 

representative before the time and date 

when the Administrator receives the 

superseding certificate of representation 

shall be binding on the new designated 

representative and the owners and 

operators of the TR SO2 Group 2 source 

and the TR SO2 Group 2 units at the 

source. 

(b) Changing alternate designated 

representative. The alternate designated 

representative may be changed at any 

time upon receipt by the Administrator 

of a superseding complete certificate of 

representation under § 97.716. 

Notwithstanding any such change, all 

representations, actions, inactions, and 

submissions by the previous alternate 

designated representative before the 

time and date when the Administrator 

receives the superseding certificate of 

representation shall be binding on the 

new alternate designated representative, 

the designated representative, and the 

owners and operators of the TR SO2

Group 2 source and the TR SO2 Group 

2 units at the source. 

(c) Changes in owners and operators. 

(1) In the event an owner or operator of 

a TR SO2 Group 2 source or a TR SO2

Group 2 unit at the source is not 

included in the list of owners and 

operators in the certificate of 

representation under § 97.716, such 

owner or operator shall be deemed to be 

subject to and bound by the certificate 

of representation, the representations, 

actions, inactions, and submissions of 

the designated representative and any 

alternate designated representative of 

the source or unit, and the decisions 

and orders of the Administrator, as if 

the owner or operator were included in 

such list. 

(2) Within 30 days after any change in 

the owners and operators of a TR SO2

Group 2 source or a TR SO2 Group 2 

unit at the source, including the 

addition or removal of an owner or 

operator, the designated representative 

or any alternate designated 

representative shall submit a revision to 

the certificate of representation under 

§ 97.716 amending the list of owners 

and operators to reflect the change. 

(d) Changes in units at the source. 

Within 30 days of any change in which 

units are located at a TR SO2 Group 2 

source (including the addition or 

removal of a unit), the designated 

representative or any alternate 

designated representative shall submit a 

certificate of representation under 

§ 97.716 amending the list of units to 

reflect the change. 

(1) If the change is the addition of a 

unit that operated (other than for 

purposes of testing by the manufacturer 

before initial installation) before being 

located at the source, then the certificate 

of representation shall identify, in a 

format prescribed by the Administrator, 

the entity from whom the unit was 

purchased or otherwise obtained 

(including name, address, telephone 

number, and facsimile number (if any)), 

the date on which the unit was 

purchased or otherwise obtained, and 

the date on which the unit became 

located at the source. 

(2) If the change is the removal of a 

unit, then the certificate of 

representation shall identify, in a format 

prescribed by the Administrator, the 

entity to which the unit was sold or that 

otherwise obtained the unit (including 

name, address, telephone number, and 

facsimile number (if any)), the date on 

which the unit was sold or otherwise 

obtained, and the date on which the 

unit became no longer located at the 

source. 

§ 97.716 Certificate of representation. 

(a) A complete certificate of 

representation for a designated 

representative or an alternate designated 

representative shall include the 

following elements in a format 

prescribed by the Administrator: 

(1) Identification of the TR SO2 Group 

2 source, and each TR SO2 Group 2 unit 

at the source, for which the certificate 

of representation is submitted, 

including source name, source category 

and NAICS code (or, in the absence of 

a NAICS code, an equivalent code), 

State, plant code, county, latitude and 

longitude, unit identification number 

and type, identification number and 

nameplate capacity (in MWe, rounded 

to the nearest tenth) of each generator 

served by each such unit, actual or 

projected date of commencement of 

commercial operation, and a statement 

of whether such source is located in 

Indian Country. If a projected date of 

commencement of commercial 

operation is provided, the actual date of 

commencement of commercial 

operation shall be provided when such 

information becomes available. 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the designated representative and any 

alternate designated representative. 

(3) A list of the owners and operators 

of the TR SO2 Group 2 source and of 

each TR SO2 Group 2 unit at the source. 

(4) The following certification 

statements by the designated 

representative and any alternate 

designated representative— 

(i) ‘‘I certify that I was selected as the 

designated representative or alternate 

designated representative, as applicable, 

by an agreement binding on the owners 

and operators of the source and each TR 

SO2 Group 2 unit at the source.’’ 

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under the TR 

SO2 Group 2 Trading Program on behalf 

of the owners and operators of the 

source and of each TR SO2 Group 2 unit 

at the source and that each such owner 

and operator shall be fully bound by my 

representations, actions, inactions, or 

submissions and by any decision or 

order issued to me by the Administrator 

regarding the source or unit.’’ 

(iii) ‘‘Where there are multiple 

holders of a legal or equitable title to, or 

a leasehold interest in, a TR SO2 Group 

2 unit, or where a utility or industrial 

customer purchases power from a TR 

SO2 Group 2 unit under a life-of-theunit, firm power contractual 

arrangement, I certify that: I have given 

a written notice of my selection as the 

‘designated representative’ or ‘alternate 

designated representative’, as 

applicable, and of the agreement by 

which I was selected to each owner and 

operator of the source and of each TR 

SO2 Group 2 unit at the source; and TR 

SO2 Group 2 allowances and proceeds 

of transactions involving TR SO2 Group 

2 allowances will be deemed to be held 

or distributed in proportion to each 

holder’s legal, equitable, leasehold, or 

contractual reservation or entitlement, 

except that, if such multiple holders 

have expressly provided for a different 

distribution of TR SO2 Group 2 


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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 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 

disputes concerning the proceeds of TR 

SO2 Group 2 allowance transfers. 

§ 97.718 Delegation by designated 

representative and alternate designated 

representative. 

(a) A designated representative may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(b) An alternate designated 

representative may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(c) In order to delegate authority to a 

natural person to make an electronic 

submission to the Administrator in 

accordance with paragraph (a) or (b) of 

this section, the designated 

representative or alternate designated 

representative, as appropriate, must 

submit to the Administrator a notice of 

delegation, in a format prescribed by the 

Administrator, that includes the 

following elements: 

(1) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of such 

designated representative or alternate 

designated representative; 

(2) The name, address, e-mail address, 

telephone number, and facsimile 

transmission number (if any) of each 

such natural person (referred to in this 

section as an ‘‘agent’’); 

(3) For each such natural person, a list 

of the type or types of electronic 

submissions under paragraph (a) or (b) 

of this section for which authority is 

delegated to him or her; and 

(4) The following certification 

statements by such designated 

representative or alternate designated 

representative: 

(i) ‘‘I agree that any electronic 

submission to the Administrator that is 

made by an agent identified in this 

notice of delegation and of a type listed 

for such agent in this notice of 

delegation and that is made when I am 

a designated representative or alternate 

designated representative, as 

appropriate, and before this notice of 

delegation is superseded by another 

notice of delegation under 40 CFR 

97.718(d) shall be deemed to be an 

electronic submission by me.’’ 

(ii) ‘‘Until this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 97.718(d), I 

agree to maintain an e-mail account and 

to notify the Administrator immediately 

of any change in my e-mail address 

unless all delegation of authority by me 

under 40 CFR 97.718 is terminated.’’. 

(d) A notice of delegation submitted 

under paragraph (c) of this section shall 

be effective, with regard to the 

designated representative or alternate 

designated representative identified in 

such notice, upon receipt of such notice 

by the Administrator and until receipt 

by the Administrator of a superseding 

notice of delegation submitted by such 

designated representative or alternate 

designated representative, as 

appropriate. The superseding notice of 

delegation may replace any previously 

identified agent, add a new agent, or 

eliminate entirely any delegation of 

authority. 

(e) Any electronic submission covered 

by the certification in paragraph (c)(4)(i) 

of this section and made in accordance 

with a notice of delegation effective 

under paragraph (d) of this section shall 

be deemed to be an electronic 

submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

§ 97.719 [Reserved] 

§ 97.720 Establishment of compliance 

accounts, assurance accounts, and general 

accounts. 

(a) Compliance accounts. Upon 

receipt of a complete certificate of 

representation under § 97.716, the 

Administrator will establish a 

compliance account for the TR SO2

Group 2 source for which the certificate 

of representation was submitted, unless 

the source already has a compliance 

account. The designated representative 

and any alternate designated 

representative of the source shall be the 

authorized account representative and 

the alternate authorized account 

representative respectively of the 

compliance account. 

(b) Assurance accounts. The 

Administrator will establish assurance 

accounts for certain owners and 

operators and States in accordance with 

§ 97.725(b)(3). 

(c) General accounts. (1) Application 

for general account. (i) Any person may 

apply to open a general account, for the 

purpose of holding and transferring TR 

SO2 Group 2 allowances, by submitting 

to the Administrator a complete 

application for a general account. Such 

application shall designate one and only 

one authorized account representative 

and may designate one and only one 

alternate authorized account 

representative who may act on behalf of 

the authorized account representative. 

(A) The authorized account 

representative and alternate authorized 

account representative shall be selected 

by an agreement binding on the persons 

who have an ownership interest with 

respect to TR SO2 Group 2 allowances 

held in the general account. 

(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 


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facsimile transmission number (if any) 

of the authorized account representative 

and any alternate authorized account 

representative; 

(B) An identifying name for the 

general account; 

(C) A list of all persons subject to a 

binding agreement for the authorized 

account representative and any alternate 

authorized account representative to 

represent their ownership interest with 

respect to the TR SO2 Group 2 

allowances held in the general account; 

(D) The following certification 

statement by the authorized account 

representative and any alternate 

authorized account representative: ‘‘I 

certify that I was selected as the 

authorized account representative or the 

alternate authorized account 

representative, as applicable, by an 

agreement that is binding on all persons 

who have an ownership interest with 

respect to TR SO2 Group 2 allowances 

held in the general account. I certify that 

I have all the necessary authority to 

carry out my duties and responsibilities 

under the TR SO2 Group 2 Trading 

Program on behalf of such persons and 

that each such person shall be fully 

bound by my representations, actions, 

inactions, or submissions and by any 

decision or order issued to me by the 

Administrator regarding the general 

account.’’ 

(E) The signature of the authorized 

account representative and any alternate 

authorized account representative and 

the dates signed. 

(iii) Unless otherwise required by the 

Administrator, documents of agreement 

referred to in the application for a 

general account shall not be submitted 

to the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

(2) Authorization of authorized 

account representative and alternate 

authorized account representative. (i) 

Upon receipt by the Administrator of a 

complete application for a general 

account under paragraph (b)(1) of this 

section, the Administrator will establish 

a general account for the person or 

persons for whom the application is 

submitted, and upon and after such 

receipt by the Administrator: 

(A) The authorized account 

representative of the general account 

shall be authorized and shall represent 

and, by his or her representations, 

actions, inactions, or submissions, 

legally bind each person who has an 

ownership interest with respect to TR 

SO2 Group 2 allowances held in the 

general account in all matters pertaining 

to the TR SO2 Group 2 Trading Program, 

notwithstanding any agreement between 

the authorized account representative 

and such person. 

(B) Any alternate authorized account 

representative shall be authorized, and 

any representation, action, inaction, or 

submission by any alternate authorized 

account representative shall be deemed 

to be a representation, action, inaction, 

or submission by the authorized account 

representative. 

(C) Each person who has an 

ownership interest with respect to TR 

SO2 Group 2 allowances held in the 

general account shall be bound by any 

decision or order issued to the 

authorized account representative or 

alternate authorized account 

representative by the Administrator 

regarding the general account. 

(ii) Except as provided in paragraph 

(c)(5) of this section concerning 

delegation of authority to make 

submissions, each submission 

concerning the general account shall be 

made, signed, and certified by the 

authorized account representative or 

any alternate authorized account 

representative for the persons having an 

ownership interest with respect to TR 

SO2 Group 2 allowances held in the 

general account. Each such submission 

shall include the following certification 

statement by the authorized account 

representative or any alternate 

authorized account representative: ‘‘I 

am authorized to make this submission 

on behalf of the persons having an 

ownership interest with respect to the 

TR SO2 Group 2 allowances held in the 

general account. I certify under penalty 

of law that I have personally examined, 

and am familiar with, the statements 

and information submitted in this 

document and all its attachments. Based 

on my inquiry of those individuals with 

primary responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(iii) Except in this section, whenever 

the term ‘‘authorized account 

representative’’ is used in this subpart, 

the term shall be construed to include 

the authorized account representative or 

any alternate authorized account 

representative. 

(3) Changing authorized account 

representative and alternate authorized 

account representative; changes in 

persons with ownership interest. (i) The 

authorized account representative of a 

general account may be changed at any 

time upon receipt by the Administrator 

of a superseding complete application 

for a general account under paragraph 

(c)(1) of this section. Notwithstanding 

any such change, all representations, 

actions, inactions, and submissions by 

the previous authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

authorized account representative and 

the persons with an ownership interest 

with respect to the TR SO2 Group 2 

allowances in the general account. 

(ii) The alternate authorized account 

representative of a general account may 

be changed at any time upon receipt by 

the Administrator of a superseding 

complete application for a general 

account under paragraph (c)(1) of this 

section. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous alternate authorized account 

representative before the time and date 

when the Administrator receives the 

superseding application for a general 

account shall be binding on the new 

alternate authorized account 

representative, the authorized account 

representative, and the persons with an 

ownership interest with respect to the 

TR SO2 Group 2 allowances in the 

general account. 

(iii)(A) In the event a person having 

an ownership interest with respect to 

TR SO2 Group 2 allowances in the 

general account is not included in the 

list of such persons in the application 

for a general account, such person shall 

be deemed to be subject to and bound 

by the application for a general account, 

the representation, actions, inactions, 

and submissions of the authorized 

account representative and any alternate 

authorized account representative of the 

account, and the decisions and orders of 

the Administrator, as if the person were 

included in such list. 

(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 


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received, the Administrator will rely on 

the application unless and until a 

superseding complete application for a 

general account under paragraph (b)(1) 

of this section is received by the 

Administrator. 

(ii) Except as provided in paragraph 

(c)(4)(i) of this section, no objection or 

other communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission of the 

authorized account representative or 

any alternate authorized account 

representative of a general account shall 

affect any representation, action, 

inaction, or submission of the 

authorized account representative or 

any alternate authorized account 

representative or the finality of any 

decision or order by the Administrator 

under the TR SO2 Group 2 Trading 

Program. 

(iii) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of the authorized account 

representative or any alternate 

authorized account representative of a 

general account, including private legal 

disputes concerning the proceeds of TR 

SO2 Group 2 allowance transfers. 

(5) Delegation by authorized account 

representative and alternate authorized 

account representative. (i) An 

authorized account representative of a 

general account may delegate, to one or 

more natural persons, his or her 

authority to make an electronic 

submission to the Administrator 

provided for or required under this 

subpart. 

(ii) An alternate authorized account 

representative of a general account may 

delegate, to one or more natural persons, 

his or her authority to make an 

electronic submission to the 

Administrator provided for or required 

under this subpart. 

(iii) In order to delegate authority to 

a natural person to make an electronic 

submission to the Administrator in 

accordance with paragraph (c)(5)(i) or 

(ii) of this section, the authorized 

account representative or alternate 

authorized account representative, as 

appropriate, must submit to the 

Administrator a notice of delegation, in 

a format prescribed by the 

Administrator, that includes the 

following elements: 

(A) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of such authorized account 

representative or alternate authorized 

account representative; 

(B) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of each such natural person (referred to 

in this section as an ‘‘agent’’); 

(C) For each such natural person, a 

list of the type or types of electronic 

submissions under paragraph (c)(5)(i) or 

(ii) of this section for which authority is 

delegated to him or her; 

(D) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘I agree that any 

electronic submission to the 

Administrator that is made by an agent 

identified in this notice of delegation 

and of a type listed for such agent in 

this notice of delegation and that is 

made when I am an authorized account 

representative or alternate authorized 

representative, as appropriate, and 

before this notice of delegation is 

superseded by another notice of 

delegation under 40 CFR 97.720(c)(5)(iv) 

shall be deemed to be an electronic 

submission by me.’’; and 

(E) The following certification 

statement by such authorized account 

representative or alternate authorized 

account representative: ‘‘Until this 

notice of delegation is superseded by 

another notice of 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. 

(v) Any electronic submission covered 

by the certification in paragraph 

(c)(5)(iii)(D) of this section and made in 

accordance with a notice of delegation 

effective under paragraph (c)(5)(iv) of 

this section shall be deemed to be an 

electronic submission by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

(6) Closing a general account. (i) The 

authorized account representative or 

alternate authorized account 

representative of a general account may 

submit to the Administrator a request to 

close the account. Such request shall 

include a correctly submitted TR SO2

Group 2 allowance transfer under 

§ 97.722 for any TR SO2 Group 2 

allowances in the account to one or 

more other Allowance Management 

System accounts. 

(ii) If a general account has no TR SO2

Group 2 allowance transfers to or from 

the account for a 12-month period or 

longer and does not contain any TR SO2

Group 2 allowances, the Administrator 

may notify the authorized account 

representative for the account that the 

account will be closed after 30 days 

after the notice is sent. The account will 

be closed after the 30-day period unless, 

before the end of the 30-day period, the 

Administrator receives a correctly 

submitted TR SO2 Group 2 allowance 

transfer under § 97.722 to the account or 

a statement submitted by the authorized 

account representative or alternate 

authorized account representative 

demonstrating to the satisfaction of the 

Administrator good cause as to why the 

account should not be closed. 

(d) Account identification. The 

Administrator will assign a unique 

identifying number to each account 

established under paragraph (a), (b), or 

(c) of this section. 

(e) Responsibilities of authorized 

account representative and alternate 

authorized account representative. After 

the establishment of a compliance 

account or general account, the 

Administrator will accept or act on a 

submission pertaining to the account, 

including, 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 November 7, 2011, the 

Administrator will record in each TR 

SO2 Group 2 source’s compliance 

account the TR SO2 Group 2 allowances 

allocated to the TR SO2 Group 2 units 

at the source in accordance with 

§ 97.711(a) for the control period in 

2012. 

(b) By November 7, 2011, 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 


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Administrator in writing by October 17, 

2011 of the State’s intent to submit to 

the Administrator a complete SIP 

revision by April 1, 2012 meeting the 

requirements of § 52.39(g)(1) through (4) 

of this chapter. 

(1) If, by April 1, 2012, the State does 

not submit to the Administrator such 

complete SIP revision, the 

Administrator will record by April 15, 

2012 in each TR SO2 Group 2 source’s 

compliance account the TR SO2 Group 

2 allowances allocated to the TR SO2

Group 2 units at the source in 

accordance with § 97.711(a) for the 

control period in 2013. 

(2) If the State submits to the 

Administrator by April 1, 2012, and the 

Administrator approves by October 1, 

2012, such complete SIP revision, the 

Administrator will record by October 1, 

2012 in each TR SO2 Group 2 source’s 

compliance account the TR SO2 Group 

2 allowances allocated to the TR SO2

Group 2 units at the source as provided 

in such approved, complete SIP revision 

for the control period in 2013. 

(3) If the State submits to the 

Administrator by April 1, 2012, and the 

Administrator does not approve by 

October 1, 2012, such complete SIP 

revision, the Administrator will record 

by October 1, 2012 in each TR SO2

Group 2 source’s compliance account 

the TR SO2 Group 2 allowances 

allocated to the TR SO2 Group 2 units 

at the source in accordance with 

§ 97.711(a) for the control period in 

2013. 

(c) By July 1, 2013, the Administrator 

will record in each TR SO2 Group 2 

source’s compliance account the TR SO2

Group 2 allowances allocated to the TR 

SO2 Group 2 units at the source, or in 

each appropriate Allowance 

Management System account the TR 

SO2 Group 2 allowances auctioned to 

TR SO2 Group 2 units, in accordance 

with § 97.711(a), or with a SIP revision 

approved under § 52.39(h) or (i) of this 

chapter, for the control period in 2014 

and 2015. 

(d) By July 1, 2014, the Administrator 

will record in each TR SO2 Group 2 

source’s compliance account the TR SO2

Group 2 allowances allocated to the TR 

SO2 Group 2 units at the source, or in 

each appropriate Allowance 

Management System account the TR 

SO2 Group 2 allowances auctioned to 

TR SO2 Group 2 units, in accordance 

with § 97.711(a), or with a SIP revision 

approved under § 52.39(h) or (i) of this 

chapter, for the control period in 2016 

and 2017. 

(e) By July 1, 2015, the Administrator 

will record in each TR SO2 Group 2 

source’s compliance account the TR SO2

Group 2 allowances allocated to the TR 

SO2 Group 2 units at the source, or in 

each appropriate Allowance 

Management System account the TR 

SO2 Group 2 allowances auctioned to 

TR SO2 Group 2 units, in accordance 

with § 97.711(a), or with a SIP revision 

approved under § 52.39(h) or (i) of this 

chapter, for the control period in 2018 

and 2019. 

(f) By July 1, 2016 and July 1 of each 

year thereafter, the Administrator will 

record in each TR SO2 Group 2 source’s 

compliance account the TR SO2 Group 

2 allowances allocated to the TR SO2

Group 2 units at the source, or in each 

appropriate Allowance Management 

System account the TR SO2 Group 2 

allowances auctioned to TR SO2 Group 

2 units, in accordance with § 97.711(a), 

or with a SIP revision approved under 

§ 52.39(h) and (i) of this chapter, for the 

control period in the fourth year after 

the year of the applicable recordation 

deadline under this paragraph. 

(g) By August 1, 2012 and August 1 

of each year thereafter, the 

Administrator will record in each TR 

SO2 Group 2 source’s compliance 

account the TR SO2 Group 2 allowances 

allocated to the TR SO2 Group 2 units 

at the source, or in each appropriate 

Allowance Management System account 

the TR SO2 Group 2 allowances 

auctioned to TR SO2 Group 2 units, in 

accordance with § 97.712(a)(2) through 

(8) and (12), or with a SIP revision 

approved under § 52.39(h) and (i) of this 

chapter, for the control period in the 

year of the applicable recordation 

deadline under this paragraph. 

(h) By August 1, 2012 and August 1 

of each year thereafter, the 

Administrator will record in each TR 

SO2 Group 2 source’s compliance 

account the TR SO2 Group 2 allowances 

allocated to the TR SO2 Group 2 units 

at the source in accordance with 

§ 97.712(b)(2) through (8) and (12) for 

the control period in the year of the 

applicable recordation deadline under 

this paragraph. 

(i) By February 15, 2013 and February 

15 of each year thereafter, the 

Administrator will record in each TR 

SO2 Group 2 source’s compliance 

account the TR SO2 Group 2 allowances 

allocated to the TR SO2 Group 2 units 

at the source in accordance with 

§ 97.712(a)(9) through (12), for the 

control period in the year before the 

year of the applicable recordation 

deadline under this paragraph. 

(j) By the date on which any 

allocation or auction results, other than 

an allocation or auction results, 

described in paragraphs (a) through (i) 

of this section, of TR SO2 Group 2 

allowances to a recipient is made by or 

are submitted to the Administrator in 

accordance with § 97.711 or § 97.712 or 

with a SIP revision approved under 

§ 52.39(h) or (i) of this chapter, the 

Administrator will record such 

allocation or auction results in the 

appropriate Allowance Management 

System account. 

(k) When recording the allocation or 

auction of TR SO2 Group 2 allowances 

to a TR SO2 Group 2 unit or other entity 

in an Allowance Management System 

account, the Administrator will assign 

each TR SO2 Group 2 allowance a 

unique identification number that will 

include digits identifying the year of the 

control period for which the TR SO2

Group 2 allowance is allocated or 

auctioned. 

§ 97.722 Submission of TR SO2 Group 2 

allowance transfers. 

(a) An authorized account 

representative seeking recordation of a 

TR SO2 Group 2 allowance transfer shall 

submit the transfer to the Administrator. 

(b) A TR SO2 Group 2 allowance 

transfer shall be correctly submitted if: 

(1) The transfer includes the following 

elements, in a format prescribed by the 

Administrator: 

(i) The account numbers established 

by the Administrator for both the 

transferor and transferee accounts; 

(ii) The serial number of each TR SO2

Group 2 allowance that is in the 

transferor account and is to be 

transferred; and 

(iii) The name and signature of the 

authorized account representative of the 

transferor account and the date signed; 

and 

(2) When the Administrator attempts 

to record the transfer, the transferor 

account includes each TR SO2 Group 2 

allowance identified by serial number in 

the transfer. 

§ 97.723 Recordation of TR SO2 Group 2 

allowance transfers. 

(a) Within 5 business days (except as 

provided in paragraph (b) of this 

section) of receiving a TR SO2 Group 2 

allowance transfer that is correctly 

submitted under § 97.722, the 

Administrator will record a TR SO2

Group 2 allowance transfer by moving 

each TR SO2 Group 2 allowance from 

the transferor account to the transferee 

account as specified in the transfer. 

(b) A TR SO2 Group 2 allowance 

transfer to or from a compliance account 

that is submitted for recordation after 

the allowance transfer deadline for a 

control period and that includes any TR 

SO2 Group 2 allowances allocated for 

any control period before such 

allowance transfer deadline will not be 

recorded until after the Administrator 

completes the deductions from such 


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compliance account under § 97.724 for 

the control period immediately before 

such allowance transfer deadline. 

(c) Where a TR SO2 Group 2 

allowance transfer is not correctly 

submitted under § 97.722, the 

Administrator will not record such 

transfer. 

(d) Within 5 business days of 

recordation of a TR SO2 Group 2 

allowance transfer under paragraphs (a) 

and (b) of the section, the Administrator 

will notify the authorized account 

representatives of both the transferor 

and transferee accounts. 

(e) Within 10 business days of receipt 

of a TR SO2 Group 2 allowance transfer 

that is not correctly submitted under 

§ 97.722, the Administrator will notify 

the authorized account representatives 

of both accounts subject to the transfer 

of: 

(1) A decision not to record the 

transfer, and 

(2) The reasons for such nonrecordation. 

§ 97.724 Compliance with TR SO2 Group 2 

emissions limitation. 

(a) Availability for deduction for 

compliance. TR SO2 Group 2 allowances 

are available to be deducted for 

compliance with a source’s TR SO2

Group 2 emissions limitation for a 

control period in a given year only if the 

TR SO2 Group 2 allowances: 

(1) Were allocated for such control 

period or a control period in a prior 

year; and 

(2) Are held in the source’s 

compliance account as of the allowance 

transfer deadline for such control 

period. 

(b) Deductions for compliance. After 

the recordation, in accordance with 

§ 97.723, of TR SO2 Group 2 allowance 

transfers submitted by the allowance 

transfer deadline for a control period in 

a given year, the Administrator will 

deduct from each source’s compliance 

account TR SO2 Group 2 allowances 

available under paragraph (a) of this 

section in order to determine whether 

the source meets the TR SO2 Group 2 

emissions limitation for such control 

period, as follows: 

(1) Until the amount of TR SO2 Group 

2 allowances deducted equals the 

number of tons of total SO2 emissions 

from all TR SO2 Group 2 units at the 

source for such control period; or 

(2) If there are insufficient TR SO2

Group 2 allowances to complete the 

deductions in paragraph (b)(1) of this 

section, until no more TR SO2 Group 2 

allowances available under paragraph 

(a) of this section remain in the 

compliance account. 

(c)(1) Identification of TR SO2 Group 

2 allowances by serial number. The 

authorized account representative for a 

source’s compliance account may 

request that specific TR SO2 Group 2 

allowances, identified by serial number, 

in the compliance account be deducted 

for emissions or excess emissions for a 

control period in a given year in 

accordance with paragraph (b) or (d) of 

this section. In order to be complete, 

such request shall be submitted to the 

Administrator by the allowance transfer 

deadline for such control period and 

include, in a format prescribed by the 

Administrator, the identification of the 

TR SO2 Group 2 source and the 

appropriate serial numbers. 

(2) First-in, first-out. The 

Administrator will deduct TR SO2

Group 2 allowances under paragraph (b) 

or (d) of this section from the source’s 

compliance account in accordance with 

a complete request under paragraph 

(c)(1) of this section or, in the absence 

of such request or in the case of 

identification of an insufficient amount 

of TR SO2 Group 2 allowances in such 

request, on a first-in, first-out 

accounting basis in the following order: 

(i) Any TR SO2 Group 2 allowances 

that were allocated to the units at the 

source and not transferred out of the 

compliance account, in the order of 

recordation; and then 

(ii) Any TR SO2 Group 2 allowances 

that were allocated to any unit and 

transferred to and recorded in the 

compliance account pursuant to this 

subpart, in the order of recordation. 

(d) Deductions for excess emissions. 

After making the deductions for 

compliance under paragraph (b) of this 

section for a control period in a year in 

which the TR SO2 Group 2 source has 

excess emissions, the Administrator will 

deduct from the source’s compliance 

account an amount of TR SO2 Group 2 

allowances, allocated for a control 

period in a prior year or the control 

period in the year of the excess 

emissions or in the immediately 

following year, equal to two times the 

number of tons of the source’s excess 

emissions. 

(e) Recordation of deductions. The 

Administrator will record in the 

appropriate compliance account all 

deductions from such an account under 

paragraphs (b) and (d) of this section. 

§ 97.725 Compliance with TR SO2 Group 2 

assurance provisions. 

(a) Availability for deduction. TR SO2

Group 2 allowances are available to be 

deducted for compliance with the TR 

SO2 Group 2 assurance provisions for a 

control period in a given year by the 

owners and operators of a group of one 

or more TR SO2 Group 2 sources and 

units in a State (and Indian country 

within the borders of such State) only if 

the TR SO2 Group 2 allowances: 

(1) Were allocated for a control period 

in a prior year or the control period in 

the given year or in the immediately 

following year; and 

(2) Are held in the assurance account, 

established by the Administrator for 

such owners and operators of such 

group of TR SO2 Group 2 sources and 

units in such State (and Indian country 

within the borders of such State) under 

paragraph (b)(3) of this section, as of the 

deadline established in paragraph (b)(4) 

of this section. 

(b) Deductions for compliance. The 

Administrator will deduct TR SO2

Group 2 allowances available under 

paragraph (a) of this section for 

compliance with the TR SO2 Group 2 

assurance provisions for a State for a 

control period in a given year in 

accordance with the following 

procedures: 

(1) By June 1, 2013 and June 1 of each 

year thereafter, the Administrator will: 

(i) Calculate, for each State (and 

Indian country within the borders of 

such State), the total SO2 emissions 

from all TR SO2 Group 2 units at TR SO2

Group 2 sources in the State (and Indian 

country within the borders of such 

State) during the control period in the 

year before the year of this calculation 

deadline and the amount, if any, by 

which such total SO2 emissions exceed 

the State assurance level as described in 

§ 97.706(c)(2)(iii); and 

(ii) Promulgate a notice of data 

availability of the results of the 

calculations required in paragraph 

(b)(1)(i) of this section, including 

separate calculations of the SO2

emissions from each TR SO2 Group 2 

source. 

(2) For each notice of data availability 

required in paragraph (b)(1)(ii) of this 

section and for any State (and Indian 

country within the borders of such 

State) identified in such notice as 

having TR SO2 Group 2 units with total 

SO2 emissions exceeding the State 

assurance level for a control period in 

a given year, as described in 

§ 97.706(c)(2)(iii): 

(i) By July 1 immediately after the 

promulgation of such notice, the 

designated representative of each TR 

SO2 Group 2 source in each such State 

(and Indian country within the borders 

of such State) shall submit a statement, 

in a format prescribed by the 

Administrator, providing for each TR 

SO2 Group 2 unit (if any) at the source 

that operates during, but is not allocated 

an amount of TR SO2 Group 2 

allowances for, such control period, the 

unit’s allowable SO2 emission rate for 

such control period and, if such rate is 


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expressed in lb per mmBtu, the unit’s 

heat rate. 

(ii) By August 1 immediately after the 

promulgation of such notice, the 

Administrator will calculate, for each 

such State (and Indian country within 

the borders of such State) and such 

control period and each common 

designated representative for such 

control period for a group of one or 

more TR SO2 Group 2 sources and units 

in the State (and Indian country within 

the borders of such State), the common 

designated representative’s share of the 

total SO2 emissions from all TR SO2

Group 2 units at TR SO2 Group 2 

sources in the State (and Indian country 

within the borders of such State), the 

common designated representative’s 

assurance level, and the amount (if any) 

of TR SO2 Group 2 allowances that the 

owners and operators of such group of 

sources and units must hold in 

accordance with the calculation formula 

in § 97.706(c)(2)(i) and will promulgate 

a notice of data availability of the results 

of these calculations. 

(iii) The Administrator will provide 

an opportunity for submission of 

objections to the calculations referenced 

by the notice of data availability 

required in paragraph (b)(2)(ii) of this 

section and the calculations referenced 

by the relevant notice of data 

availability required in paragraph 

(b)(1)(i) of this section. 

(A) Objections shall be submitted by 

the deadline specified in such notice 

and shall be limited to addressing 

whether the calculations referenced in 

the relevant notice required under 

paragraph (b)(1)(ii) of this section and 

referenced in the notice required under 

paragraph (b)(2)(ii) of this section are in 

accordance with § 97.706(c)(2)(iii), 

§§ 97.706(b) and 97.730 through 97.735, 

the definitions of ‘‘common designated 

representative’’, ‘‘common designated 

representative’s assurance level’’, and 

‘‘common designated representative’s 

share’’ in § 97.702, and the calculation 

formula in § 97.706(c)(2)(i). 

(B) The Administrator will adjust the 

calculations to the extent necessary to 

ensure that they are in accordance with 

the provisions referenced in paragraph 

(b)(2)(iii)(A) of this section. By October 

1 immediately after the promulgation of 

such notice, the Administrator will 

promulgate a notice of data availability 

of any adjustments that the 

Administrator determines to be 

necessary and the reasons for accepting 

or rejecting any objections submitted in 

accordance with paragraph (b)(2)(iii)(A) 

of this section. 

(3) For any State (and Indian country 

within the borders of such State) 

referenced in each notice of data 

availability required in paragraph 

(b)(2)(iii)(B) of this section as having TR 

SO2 Group 2 units with total SO2

emissions exceeding the State assurance 

level for a control period in a given year, 

the Administrator will establish one 

assurance account for each set of owners 

and operators referenced, in the notice 

of data availability required under 

paragraph (b)(2)(iii)(B) of this section, as 

all of the owners and operators of a 

group of TR SO2 Group 2 sources and 

units in the State (and Indian country 

within the borders of such State) having 

a common designated representative for 

such control period and as being 

required to hold TR SO2 Group 2 

allowances. 

(4)(i) As of midnight of November 1 

immediately after the promulgation of 

each notice of data availability required 

in paragraph (b)(2)(iii)(B) of this section, 

the owners and operators described in 

paragraph (b)(3) of this section shall 

hold in the assurance account 

established for them and for the 

appropriate TR SO2 Group 2 sources, TR 

SO2 Group 2 units, and State (and 

Indian country within the borders of 

such State) under paragraph (b)(3) of 

this section a total amount of TR SO2

Group 2 allowances, available for 

deduction under paragraph (a) of this 

section, equal to the amount such 

owners and operators are required to 

hold with regard to such sources, units 

and State (and Indian country within 

the borders of such State) as calculated 

by the Administrator and referenced in 

such notice. 

(ii) Notwithstanding the allowanceholding deadline specified in paragraph 

(b)(4)(i) of this section, if November 1 is 

not a business day, then such 

allowance-holding deadline shall be 

midnight of the first business day 

thereafter. 

(5) After November 1 (or the date 

described in paragraph (b)(4)(ii) of this 

section) immediately after the 

promulgation of each notice of data 

availability required in paragraph 

(b)(2)(iii)(B) of this section and after the 

recordation, in accordance with 

§ 97.723, of TR SO2 Group 2 allowance 

transfers submitted by midnight of such 

date, the Administrator will determine 

whether the owners and operators 

described in paragraph (b)(3) of this 

section hold, in the assurance account 

for the appropriate TR SO2 Group 2 

sources, TR SO2 Group 2 units, and 

State (and Indian country within the 

borders of such State) established under 

paragraph (b)(3) of this section, the 

amount of TR SO2 Group 2 allowances 

available under paragraph (a) of this 

section that the owners and operators 

are required to hold with regard to such 

sources, units, and State (and Indian 

country within the borders of such 

State) as calculated by the 

Administrator and referenced in the 

notice required in paragraph 

(b)(2)(iii)(B) of this section. 

(6) Notwithstanding any other 

provision of this subpart and any 

revision, made by or submitted to the 

Administrator after the promulgation of 

the notice of data availability required 

in paragraph (b)(2)(iii)(B) of this section 

for a control period in a given year, of 

any data used in making the 

calculations referenced in such notice, 

the amounts of TR SO2 Group 2 

allowances that the owners and 

operators are required to hold in 

accordance with § 97.706(c)(2)(i) for 

such control period shall continue to be 

such amounts as calculated by the 

Administrator and referenced in such 

notice required in paragraph 

(b)(2)(iii)(B) of this section, except as 

follows: 

(i) If any such data are revised by the 

Administrator as a result of a decision 

in or settlement of litigation concerning 

such data on appeal under part 78 of 

this chapter of such notice, or on appeal 

under section 307 of the Clean Air Act 

of a decision rendered under part 78 of 

this chapter on appeal of such notice, 

then the Administrator will use the data 

as so revised to recalculate the amounts 

of TR SO2 Group 2 allowances that 

owners and operators are required to 

hold in accordance with the calculation 

formula in § 97.706(c)(2)(i) for such 

control period with regard to the TR SO2

Group 2 sources, TR SO2 Group 2 units, 

and State (and Indian country within 

the borders of such State) involved, 

provided that such litigation under part 

78 of this chapter, or the proceeding 

under part 78 of this chapter that 

resulted in the decision appealed in 

such litigation under section 307 of the 

Clean Air Act, was initiated no later 

than 30 days after promulgation of such 

notice required in paragraph 

(b)(2)(iii)(B) of this section. 

(ii) If any such data are revised by the 

owners and operators of a TR SO2 Group 

2 source and TR SO2 Group 2 unit 

whose designated representative 

submitted such data under paragraph 

(b)(2)(i) of this section, as a result of a 

decision in or settlement of litigation 

concerning such submission, then the 

Administrator will use the data as so 

revised to recalculate the amounts of TR 

SO2 Group 2 allowances that owners 

and operators are required to hold in 

accordance with the calculation formula 

in § 97.706(c)(2)(i) for such control 

period with regard to the TR SO2 Group 

2 sources, TR SO2 Group 2 units, and 

State (and Indian country within the 


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borders of such State) involved, 

provided that such litigation was 

initiated no later than 30 days after 

promulgation of such notice required in 

paragraph (b)(2)(iii)(B) of this section. 

(iii) If the revised data are used to 

recalculate, in accordance with 

paragraphs (b)(6)(i) and (ii) of this 

section, the amount of TR SO2 Group 2 

allowances that the owners and 

operators are required to hold for such 

control period with regard to the TR SO2

Group 2 sources, TR SO2 Group 2 units, 

and State (and Indian country within 

the borders of such State) involved— 

(A) Where the amount of TR SO2

Group 2 allowances that the owners and 

operators are required to hold increases 

as a result of the use of all such revised 

data, the Administrator will establish a 

new, reasonable deadline on which the 

owners and operators shall hold the 

additional amount of TR SO2 Group 2 

allowances in the assurance account 

established by the Administrator for the 

appropriate TR SO2 Group 2 sources, TR 

SO2 Group 2 units, and State (and 

Indian country within the borders of 

such State) under paragraph (b)(3) of 

this section. The owners’ and operators’ 

failure to hold such additional amount, 

as required, before the new deadline 

shall not be a violation of the Clean Air 

Act. The owners’ and operators’ failure 

to hold such additional amount, as 

required, as of the new deadline shall be 

a violation of the Clean Air Act. Each 

TR SO2 Group 2 allowance that the 

owners and operators fail to hold as 

required as of the new deadline, and 

each day in such control period, shall be 

a separate violation of the Clean Air Act. 

(B) For the owners and operators for 

which the amount of TR SO2 Group 2 

allowances required to be held 

decreases as a result of the use of all 

such revised data, the Administrator 

will record, in all accounts from which 

TR SO2 Group 2 allowances were 

transferred by such owners and 

operators for such control period to the 

assurance account established by the 

Administrator for the appropriate at TR 

SO2 Group 2 sources, TR SO2 Group 2 

units, and State (and Indian country 

within the borders of such State) under 

paragraph (b)(3) of this section, a total 

amount of the TR SO2 Group 2 

allowances held in such assurance 

account equal to the amount of the 

decrease. If TR SO2 Group 2 allowances 

were transferred to such assurance 

account from more than one account, 

the amount of TR SO2 Group 2 

allowances recorded in each such 

transferor account will be in proportion 

to the percentage of the total amount of 

TR SO2 Group 2 allowances transferred 

to such assurance account for such 

control period from such transferor 

account. 

(C) Each TR SO2 Group 2 allowance 

held under paragraph (b)(6)(iii)(A) of 

this section as a result of recalculation 

of requirements under the TR SO2

Group 2 assurance provisions for such 

control period must be a TR SO2 Group 

2 allowance allocated for a control 

period in a year before or the year 

immediately following, or in the same 

year as, the year of such control period. 

§ 97.726 Banking. 

(a) A TR SO2 Group 2 allowance may 

be banked for future use or transfer in 

a compliance account or a general 

account in accordance with paragraph 

(b) of this section. 

(b) Any TR SO2 Group 2 allowance 

that is held in a compliance account or 

a general account will remain in such 

account unless and until the TR SO2

Group 2 allowance is deducted or 

transferred under § 97.711(c), § 97.723, 

§ 97.724, § 97.725, § 97.727, or § 97.728. 

§ 97.727 Account error. 

The Administrator may, at his or her 

sole discretion and on his or her own 

motion, correct any error in any 

Allowance Management System 

account. Within 10 business days of 

making such correction, the 

Administrator will notify the authorized 

account representative for the account. 

§ 97.728 Administrator’s action on 

submissions. 

(a) The Administrator may review and 

conduct independent audits concerning 

any submission under the TR SO2

Group 2 Trading Program and make 

appropriate adjustments of the 

information in the submission. 

(b) The Administrator may deduct TR 

SO2 Group 2 allowances from or transfer 

TR SO2 Group 2 allowances to a 

compliance account or an assurance 

account, based on the information in a 

submission, as adjusted under 

paragraph (a)(1) of this section, and 

record such deductions and transfers. 

§ 97.729 [Reserved] 

§ 97.730 General monitoring, 

recordkeeping, and reporting requirements. 

The owners and operators, and to the 

extent applicable, the designated 

representative, of a TR SO2 Group 2 

unit, shall comply with the monitoring, 

recordkeeping, and reporting 

requirements as provided in this subpart 

and subparts F and G of part 75 of this 

chapter. For purposes of applying such 

requirements, the definitions in § 97.702 

and in § 72.2 of this chapter shall apply, 

the terms ‘‘affected unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) in part 75 of this chapter shall 

be deemed to refer to the terms ‘‘TR SO2

Group 2 unit,’’ ‘‘designated 

representative,’’ and ‘‘continuous 

emission monitoring system’’ (or 

‘‘CEMS’’) respectively as defined in 

§ 97.702, and the term ‘‘newly affected 

unit’’ shall be deemed to mean ‘‘newly 

affected TR SO2 Group 2 unit’’. The 

owner or operator of a unit that is not 

a TR SO2 Group 2 unit but that is 

monitored under § 75.16(b)(2) of this 

chapter shall comply with the same 

monitoring, recordkeeping, and 

reporting requirements as a TR SO2

Group 2 unit. 

(a) Requirements for installation, 

certification, and data accounting. The 

owner or operator of each TR SO2 Group 

2 unit shall: 

(1) Install all monitoring systems 

required under this subpart for 

monitoring SO2 mass emissions and 

individual unit heat input (including all 

systems required to monitor SO2

concentration, stack gas moisture 

content, stack gas flow rate, CO2 or O2

concentration, and fuel flow rate, as 

applicable, in accordance with §§ 75.11 

and 75.16 of this chapter); 

(2) Successfully complete all 

certification tests required under 

§ 97.731 and meet all other 

requirements of this subpart and part 75 

of this chapter applicable to the 

monitoring systems under paragraph 

(a)(1) of this section; and 

(3) Record, report, and quality-assure 

the data from the monitoring systems 

under paragraph (a)(1) of this section. 

(b) Compliance deadlines. Except as 

provided in paragraph (e) of this 

section, the owner or operator shall 

meet the monitoring system certification 

and other requirements of paragraphs 

(a)(1) and (2) of this section on or before 

the following dates and shall record, 

report, and quality-assure the data from 

the monitoring systems under paragraph 

(a)(1) of this section on and after the 

following dates. 

(1) For the owner or operator of a TR 

SO2 Group 2 unit that commences 

commercial operation before July 1, 

2011, January 1, 2012. 

(2) For the owner or operator of a TR 

SO2 Group 2 unit that commences 

commercial operation on or after July 1, 

2011, by the later of the following: 

(i) January 1, 2012; or 

(ii) 180 calendar days after the date on 

which the unit commences commercial 

operation. 

(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 

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under paragraph (b)(1) or (2) of this 

section shall meet the requirements of 

§§ 75.4(e)(1) through (e)(4) of this 

chapter, except that: 

(i) Such requirements shall apply to 

the monitoring systems required under 

§ 97.730 through § 97.735, rather than 

the monitoring systems required under 

part 75 of this chapter; 

(ii) SO2 concentration, stack gas 

moisture content, stack gas volumetric 

flow rate, and O2 or CO2 concentration 

data shall be determined and reported, 

rather than the data listed in § 75.4(e)(2) 

of this chapter; and 

(iii) Any petition for another 

procedure under § 75.4(e)(2) of this 

chapter shall be submitted under 

§ 97.735, rather than § 75.66. 

(c) Reporting data. The owner or 

operator of a TR SO2 Group 2 unit that 

does not meet the applicable 

compliance date set forth in paragraph 

(b) of this section for any monitoring 

system under paragraph (a)(1) of this 

section shall, for each such monitoring 

system, determine, record, and report 

maximum potential (or, as appropriate, 

minimum potential) values for SO2

concentration, stack gas flow rate, stack 

gas moisture content, fuel flow rate, and 

any other parameters required to 

determine SO2 mass emissions and heat 

input in accordance with § 75.31(b)(2) 

or (c)(3) of this chapter or section 2.4 of 

appendix D to part 75 of this chapter, as 

applicable. 

(d) Prohibitions. (1) No owner or 

operator of a TR SO2 Group 2 unit shall 

use any alternative monitoring system, 

alternative reference method, or any 

other alternative to any requirement of 

this subpart without having obtained 

prior written approval in accordance 

with § 97.735. 

(2) No owner or operator of a TR SO2

Group 2 unit shall operate the unit so 

as to discharge, or allow to be 

discharged, SO2 to the atmosphere 

without accounting for all such SO2 in 

accordance with the applicable 

provisions of this subpart and part 75 of 

this chapter. 

(3) No owner or operator of a TR SO2

Group 2 unit shall disrupt the 

continuous emission monitoring system, 

any portion thereof, or any other 

approved emission monitoring method, 

and thereby avoid monitoring and 

recording SO2 mass discharged into the 

atmosphere or heat input, except for 

periods of recertification or periods 

when calibration, quality assurance 

testing, or maintenance is performed in 

accordance with the applicable 

provisions of this subpart and part 75 of 

this chapter. 

(4) No owner or operator of a TR SO2

Group 2 unit shall retire or permanently 

discontinue use of the continuous 

emission monitoring system, any 

component thereof, or any other 

approved monitoring system under this 

subpart, except under any one of the 

following circumstances: 

(i) During the period that the unit is 

covered by an exemption under § 97.705 

that is in effect; 

(ii) The owner or operator is 

monitoring emissions from the unit with 

another certified monitoring system 

approved, in accordance with the 

applicable provisions of this subpart 

and part 75 of this chapter, by the 

Administrator for use at that unit that 

provides emission data for the same 

pollutant or parameter as the retired or 

discontinued monitoring system; or 

(iii) The designated representative 

submits notification of the date of 

certification testing of a replacement 

monitoring system for the retired or 

discontinued monitoring system in 

accordance with § 97.731(d)(3)(i). 

(e) Long-term cold storage. The owner 

or operator of a TR SO2 Group 2 unit is 

subject to the applicable provisions of 

§ 75.4(d) of this chapter concerning 

units in long-term cold storage. 

§ 97.731 Initial monitoring system 

certification and recertification procedures. 

(a) The owner or operator of a TR SO2

Group 2 unit shall be exempt from the 

initial certification requirements of this 

section for a monitoring system under 

§ 97.730(a)(1) if the following conditions 

are met: 

(1) The monitoring system has been 

previously certified in accordance with 

part 75 of this chapter; and 

(2) The applicable quality-assurance 

and quality-control requirements of 

§ 75.21 of this chapter and appendices 

B and D to part 75 of this chapter are 

fully met for the certified monitoring 

system described in paragraph (a)(1) of 

this section. 

(b) The recertification provisions of 

this section shall apply to a monitoring 

system under § 97.730(a)(1) that is 

exempt from initial certification 

requirements under paragraph (a) of this 

section. 

(c) [Reserved] 

(d) Except as provided in paragraph 

(a) of this section, the owner or operator 

of a TR SO2 Group 2 unit shall comply 

with the following initial certification 

and recertification procedures, for a 

continuous monitoring system (i.e., a 

continuous emission monitoring system 

and an excepted monitoring system 

under appendix D to part 75 of this 

chapter) under § 97.730(a)(1). The 

owner or operator of a unit that qualifies 

to use the low mass emissions excepted 

monitoring methodology under § 75.19 

of this chapter or that qualifies to use an 

alternative monitoring system under 

subpart E of part 75 of this chapter shall 

comply with the procedures in 

paragraph (e) or (f) of this section 

respectively. 

(1) Requirements for initial 

certification. The owner or operator 

shall ensure that each continuous 

monitoring system under § 97.730(a)(1) 

(including the automated data 

acquisition and handling system) 

successfully completes all of the initial 

certification testing required under 

§ 75.20 of this chapter by the applicable 

deadline in § 97.730(b). In addition, 

whenever the owner or operator installs 

a monitoring system to meet the 

requirements of this subpart in a 

location where no such monitoring 

system was previously installed, initial 

certification in accordance with § 75.20 

of this chapter is required. 

(2) Requirements for recertification. 

Whenever the owner or operator makes 

a replacement, modification, or change 

in any certified continuous emission 

monitoring system under § 97.730(a)(1) 

that may significantly affect the ability 

of the system to accurately measure or 

record SO2 mass emissions or heat input 

rate or to meet the quality-assurance and 

quality-control requirements of § 75.21 

of this chapter or appendix B to part 75 

of this chapter, the owner or operator 

shall recertify the monitoring system in 

accordance with § 75.20(b) of this 

chapter. Furthermore, whenever the 

owner or operator makes a replacement, 

modification, or change to the flue gas 

handling system or the unit’s operation 

that may significantly change the stack 

flow or concentration profile, the owner 

or operator shall recertify each 

continuous emission monitoring system 

whose accuracy is potentially affected 

by the change, in accordance with 

§ 75.20(b) of this chapter. Examples of 

changes to a continuous emission 

monitoring system that require 

recertification include: Replacement of 

the analyzer, complete replacement of 

an existing continuous emission 

monitoring system, or change in 

location or orientation of the sampling 

probe or site. Any fuel flowmeter system 

under § 97.730(a)(1) is subject to the 

recertification requirements in 

§ 75.20(g)(6) of this chapter. 

(3) Approval process for initial 

certification and recertification. For 

initial certification of a continuous 

monitoring system under § 97.730(a)(1), 

paragraphs (d)(3)(i) through (v) of this 

section apply. For recertifications of 

such monitoring systems, paragraphs 

(d)(3)(i) through (iv) of this section and 

the procedures in §§ 75.20(b)(5) and 

(g)(7) of this chapter (in lieu of the 


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procedures in paragraph (d)(3)(v) of this 

section) apply, provided that in 

applying paragraphs (d)(3)(i) through 

(iv) of this section, the words 

‘‘certification’’ and ‘‘initial certification’’ 

are replaced by the word 

‘‘recertification’’ and the word 

‘‘certified’’ is replaced by with the word 

‘‘recertified’’. 

(i) Notification of certification. The 

designated representative shall submit 

to the appropriate EPA Regional Office 

and the Administrator written notice of 

the dates of certification testing, in 

accordance with § 97.733. 

(ii) Certification application. The 

designated representative shall submit 

to the Administrator a certification 

application for each monitoring system. 

A complete certification application 

shall include the information specified 

in § 75.63 of this chapter. 

(iii) Provisional certification date. The 

provisional certification date for a 

monitoring system shall be determined 

in accordance with § 75.20(a)(3) of this 

chapter. A provisionally certified 

monitoring system may be used under 

the TR SO2 Group 2 Trading Program for 

a period not to exceed 120 days after 

receipt by the Administrator of the 

complete certification application for 

the monitoring system under paragraph 

(d)(3)(ii) of this section. Data measured 

and recorded by the provisionally 

certified monitoring system, in 

accordance with the requirements of 

part 75 of this chapter, will be 

considered valid quality-assured data 

(retroactive to the date and time of 

provisional certification), provided that 

the Administrator does not invalidate 

the provisional certification by issuing a 

notice of disapproval within 120 days of 

the date of receipt of the complete 

certification application by the 

Administrator. 

(iv) Certification application approval 

process. The Administrator will issue a 

written notice of approval or 

disapproval of the certification 

application to the owner or operator 

within 120 days of receipt of the 

complete certification application under 

paragraph (d)(3)(ii) of this section. In the 

event the Administrator does not issue 

such a notice within such 120-day 

period, each monitoring system that 

meets the applicable performance 

requirements of part 75 of this chapter 

and is included in the certification 

application will be deemed certified for 

use under the TR SO2 Group 2 Trading 

Program. 

(A) Approval notice. If the 

certification application is complete and 

shows that each monitoring system 

meets the applicable performance 

requirements of part 75 of this chapter, 

then the Administrator will issue a 

written notice of approval of the 

certification application within 120 

days of receipt. 

(B) Incomplete application notice. If 

the certification application is not 

complete, then the Administrator will 

issue a written notice of incompleteness 

that sets a reasonable date by which the 

designated representative must submit 

the additional information required to 

complete the certification application. If 

the designated representative does not 

comply with the notice of 

incompleteness by the specified date, 

then the Administrator may issue a 

notice of disapproval under paragraph 

(d)(3)(iv)(C) of this section. 

(C) Disapproval notice. If the 

certification application shows that any 

monitoring system does not meet the 

performance requirements of part 75 of 

this chapter or if the certification 

application is incomplete and the 

requirement for disapproval under 

paragraph (d)(3)(iv)(B) of this section is 

met, then the Administrator will issue a 

written notice of disapproval of the 

certification application. Upon issuance 

of such notice of disapproval, the 

provisional certification is invalidated 

by the Administrator and the data 

measured and recorded by each 

uncertified monitoring system shall not 

be considered valid quality-assured data 

beginning with the date and hour of 

provisional certification (as defined 

under § 75.20(a)(3) of this chapter). 

(D) Audit decertification. The 

Administrator may issue a notice of 

disapproval of the certification status of 

a monitor in accordance with 

§ 97.732(b). 

(v) Procedures for loss of certification. 

If the Administrator issues a notice of 

disapproval of a certification 

application under paragraph 

(d)(3)(iv)(C) of this section or a notice of 

disapproval of certification status under 

paragraph (d)(3)(iv)(D) of this section, 

then: 

(A) The owner or operator shall 

substitute the following values, for each 

disapproved monitoring system, for 

each hour of unit operation during the 

period of invalid data specified under 

§ 75.20(a)(4)(iii), § 75.20(g)(7), or 

§ 75.21(e) of this chapter and continuing 

until the applicable date and hour 

specified under § 75.20(a)(5)(i) or (g)(7) 

of this chapter: 

(1) For a disapproved SO2 pollutant 

concentration monitor and disapproved 

flow monitor, respectively, the 

maximum potential concentration of 

SO2 and the maximum potential flow 

rate, as defined in sections 2.1.1.1 and 

2.1.4.1 of appendix A to part 75 of this 

chapter. 

(2) For a disapproved moisture 

monitoring system and disapproved 

diluent gas monitoring system, 

respectively, the minimum potential 

moisture percentage and either the 

maximum potential CO2 concentration 

or the minimum potential O2

concentration (as applicable), as defined 

in sections 2.1.5, 2.1.3.1, and 2.1.3.2 of 

appendix A to part 75 of this chapter. 

(3) For a disapproved fuel flowmeter 

system, the maximum potential fuel 

flow rate, as defined in section 2.4.2.1 

of appendix D to part 75 of this chapter. 

(B) The designated representative 

shall submit a notification of 

certification retest dates and a new 

certification application in accordance 

with paragraphs (d)(3)(i) and (ii) of this 

section. 

(C) The owner or operator shall repeat 

all certification tests or other 

requirements that were failed by the 

monitoring system, as indicated in the 

Administrator’s notice of disapproval, 

no later than 30 unit operating days 

after the date of issuance of the notice 

of disapproval. 

(e) The owner or operator of a unit 

qualified to use the low mass emissions 

(LME) excepted methodology under 

§ 75.19 of this chapter shall meet the 

applicable certification and 

recertification requirements in 

§§ 75.19(a)(2) and 75.20(h) of this 

chapter. If the owner or operator of such 

a unit elects to certify a fuel flowmeter 

system for heat input determination, the 

owner or operator shall also meet the 

certification and recertification 

requirements in § 75.20(g) of this 

chapter. 

(f) The designated representative of 

each unit for which the owner or 

operator intends to use an alternative 

monitoring system approved by the 

Administrator under subpart E of part 

75 of this chapter shall comply with the 

applicable notification and application 

procedures of § 75.20(f) of this chapter. 

§ 97.732 Monitoring system out-of-control 

periods. 

(a) General provisions. Whenever any 

monitoring system fails to meet the 

quality-assurance and quality-control 

requirements or data validation 

requirements of part 75 of this chapter, 

data shall be substituted using the 

applicable missing data procedures in 

subpart D or appendix D to part 75 of 

this chapter. 

(b) Audit decertification. Whenever 

both an audit of a monitoring system 

and a review of the initial certification 

or recertification application reveal that 

any monitoring system should not have 

been certified or recertified because it 

did not meet a particular performance 


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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. 

§ 97.734 Recordkeeping and reporting. 

(a) General provisions. The designated 

representative shall comply with all 

recordkeeping and reporting 

requirements in paragraphs (b) through 

(e) of this section, the applicable 

recordkeeping and reporting 

requirements in subparts F and G of part 

75 of this chapter, and the requirements 

of § 97.714(a). 

(b) Monitoring plans. The owner or 

operator of a TR SO2 Group 2 unit shall 

comply with requirements of § 75.62 of 

this chapter. 

(c) Certification applications. The 

designated representative shall submit 

an application to the Administrator 

within 45 days after completing all 

initial certification or recertification 

tests required under § 97.731, including 

the information required under § 75.63 

of this chapter. 

(d) Quarterly reports. The designated 

representative shall submit quarterly 

reports, as follows: 

(1) The designated representative 

shall report the SO2 mass emissions data 

and heat input data for the TR SO2

Group 2 unit, in an electronic quarterly 

report in a format prescribed by the 

Administrator, for each calendar quarter 

beginning with: 

(i) For a unit that commences 

commercial operation before July 1, 

2011, the calendar quarter covering 

January 1, 2012 through March 31, 2012; 

or 

(ii) For a unit that commences 

commercial operation on or after July 1, 

2011, the calendar quarter 

corresponding to the earlier of the date 

of provisional certification or the 

applicable deadline for initial 

certification under § 97.730(b), unless 

that quarter is the third or fourth quarter 

of 2011, in which case reporting shall 

commence in the quarter covering 

January 1, 2012 through March 31, 2012. 

(2) The designated representative 

shall submit each quarterly report to the 

Administrator within 30 days after the 

end of the calendar quarter covered by 

the report. Quarterly reports shall be 

submitted in the manner specified in 

§ 75.64 of this chapter. 

(3) For TR SO2 Group 2 units that are 

also subject to the Acid Rain Program, 

TR NOX Annual Trading Program, or TR 

NOX Ozone Season Trading Program, 

quarterly reports shall include the 

applicable data and information 

required by subparts F through H of part 

75 of this chapter as applicable, in 

addition to the SO2 mass emission data, 

heat input data, and other information 

required by this subpart. 

(4) The Administrator may review and 

conduct independent audits of any 

quarterly report in order to determine 

whether the quarterly report meets the 

requirements of this subpart and part 75 

of this chapter, including the 

requirement to use substitute data. 

(i) The Administrator will notify the 

designated representative of any 

determination that the quarterly report 

fails to meet any such requirements and 

specify in such notification any 

corrections that the Administrator 

believes are necessary to make through 

resubmission of the quarterly report and 

a reasonable time period within which 

the designated representative must 

respond. Upon request by the 

designated representative, the 

Administrator may specify reasonable 

extensions of such time period. Within 

the time period (including any such 

extensions) specified by the 

Administrator, the designated 

representative shall resubmit the 

quarterly report with the corrections 

specified by the Administrator, except 

to the extent the designated 

representative provides information 

demonstrating that a specified 

correction is not necessary because the 

quarterly report already meets the 

requirements of this subpart and part 75 

of this chapter that are relevant to the 

specified correction. 

(ii) Any resubmission of a quarterly 

report shall meet the requirements 

applicable to the submission of a 

quarterly report under this subpart and 

part 75 of this chapter, except for the 

deadline set forth in paragraph (d)(2) of 

this section. 

(e) Compliance certification. The 

designated representative shall submit 

to the Administrator a compliance 

certification (in a format prescribed by 

the Administrator) in support of each 

quarterly report based on reasonable 

inquiry of those persons with primary 

responsibility for ensuring that all of the 

unit’s emissions are correctly and fully 

monitored. The certification shall state 

that: 

(1) The monitoring data submitted 

were recorded in accordance with the 

applicable requirements of this subpart 

and part 75 of this chapter, including 

the quality assurance procedures and 

specifications; and 

(2) For a unit with add-on SO2

emission controls and for all hours 

where SO2 data are substituted in 

accordance with § 75.34(a)(1) of this 

chapter, the add-on emission controls 

were operating within the range of 

parameters listed in the quality 

assurance/quality control program 

under appendix B to part 75 of this 

chapter and the substitute data values 

do not systematically underestimate SO2

emissions. 

§ 97.735 Petitions for alternatives to 

monitoring, recordkeeping, or reporting 

requirements. 

(a) The designated representative of a 

TR SO2 Group 2 unit may submit a 

petition under § 75.66 of this chapter to 

the Administrator, requesting approval 

to apply an alternative to any 

requirement of §§ 97.730 through 

97.734. 

(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 


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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. 

[FR Doc. 2011–17600 Filed 8–5–11; 8:45 am] 

BILLING CODE 6560–50–P 


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