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6560-50

EO 12866_CPP 2060 AR33 Final_2015052920150801

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 60 

[EPA-HQ-OAR-2013-0602; FRL-XXXX-XX-OAR]

RIN 2060-AR33 

Carbon Pollution Emission Guidelines for Existing Stationary 

Sources: Electric Utility Generating Units 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final rule. 

SUMMARY: In this action, the Environmental Protection Agency 

(EPA) is establishing final emission guidelines for states, U.S. 

territories, and tribes to follow in developing plans to reduce 

greenhouse gas (GHG) emissions from existing fossil fuel-fired 

electric generating units (EGUs). Specifically, the EPA is 

establishing: 1) carbon dioxide (CO2) emission performance rates 

representing the best system of emission reduction (BSER) for 

two source categoriessubcategories of existing fossil fuel-fired 

EGUs, – fossil fuel-fired electric utility steam generating 

units and stationary combustion turbines, and 22) state-specific 

CO2 goals reflecting the CO2 emission performance rates, and 3) 

guidelines for the development, submittal and implementation of 

state plans that establish emission standards or other measures 

to implement the CO2 emission performance rates, which may be 
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accomplished by meeting the state goals. This final rule will 

continue progress already underway in the U.S. to reduce CO2

emissions from the utility power sector. 

DATES: The final rule is effective on [INSERT THE DATE OF60 DAYS 

AFTER PUBLICATION IN THE FEDERAL REGISTER].

ADDRESSES: 

Docket. The EPA has established a docket for this action under 

Docket No. EPA–HQ–OAR–2013-0602. All documents in the docket are 

listed in the http://www.regulations.gov index. Although listed 

in the index, some information is not publicly available (e.g., 

confidential business information (CBI) or other information for 

which disclosure is restricted by statute). Certain other 

material, such as copyrighted material, will be publicly 

available only in hard copy. Publicly available docket materials 

are available either electronically in 

http://www.regulations.gov or in hard copy at the EPA Docket 

Center, EPA WJC West Building, Room 3334, 1301 Constitution 

Ave., NW, Washington, DC. The Public Reading Room is open from 

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

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 additional information about the EPA’s 
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public docket, visit the EPA Docket Center homepage at 

http://wwwwww2.epa.gov/epahome/dockets.htm.

World Wide Web. In addition to being available in the 

docket, an electronic copy of this final rule will be available 

on the World Wide Web (WWW). Following signature, a copy of this 

final rule will be posted at the following address: 

http://www.epa.gov/cleanpowerplan/. A number of documents 

relevant to this rulemaking, including technical support 

documents, (TSDs), a legal memorandum, and the regulatory impact 

analysis, (RIA), are also available at 

http://www.epa.gov/cleanpowerplan/. These and other related 

documents are also available for inspection and copying in the 

EPA docket for this rulemaking. 

FOR FURTHER INFORMATION CONTACT: Ms. Amy Vasu, Sector Policies 

and Programs Division (D205-01), U.S. EPA, Research Triangle 

Park, NC 27711; telephone number (919) 541-0107, facsimile 

number (919) 541-4991; email address: vasu.amy@epa.gov or Mr. 

Colin Boswell, Measurements Policy Group (D243-05), Sector 

Policies and Programs Division, U.S. EPA, Research Triangle 

Park, NC 27711; telephone number (919) 541-2034, facsimile 

number (919) 541-4991; email address: boswell.colin@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Acronyms. A number of acronyms and chemical symbols are 
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used in this preamble. While this may not be an exhaustive list, 

to ease the reading of this preamble and for reference purposes, 

the following terms and acronyms are defined as follows: 

ACEEE American Council for an Energy -Efficient Economy 

AEO Annual Energy Outlook 

AFL-CIO American Federation of Labor and Congress of 

Industrial Organizations 

ASTM American Society for Testing ofand Materials 

BSER Best System of Emission Reduction 

Btu/kWh British Thermal Units per Kilowatt-hour 

CAA Clean Air Act 

CBI Confidential Business Information 

CCS Carbon Capture and Storage (or Sequestration) 

CEMS Continuous Emissions Monitoring System 

CHP Combined Heat and Power 

CO2 Carbon Dioxide 

DOE U.S. Department of Energy 

ECMPS Emissions Collection and Monitoring Plan System 

EE Energy Efficiency 

EERS Energy Efficiency Resource Standard 

EGU Electric Generating Unit 

EIA Energy Information Administration 

EM&V Evaluation, Measurement and Verification 

EO Executive Order 

EPA Environmental Protection Agency 

FERC Federal Energy Regulatory Commission 

ERC Emission Rate Credit 

FR Federal Register 

GHG Greenhouse Gas 

GW Gigawatt 

HAP Hazardous Air Pollutant 

HRSG Heat Recovery Steam Generator 

IGCC Integrated Gasification Combined Cycle 

IPCC Intergovernmental Panel on Climate Change 

IPM Integrated Planning Model 

IRP Integrated Resource Plan 

ISO Independent System Operator 

kW Kilowatt

kWh Kilowatt-hour 

lb CO2/MWh Pounds of CO2 per Megawatt-hour 

LBNL Lawrence Berkeley National Laboratory 

MMBtu Million British Thermal Units 
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MW Megawatt 

MWh Megawatt-hour 

NAAQS National Ambient Air Quality Standards 

NAICS North American Industry Classification System 

Commissioners

NAS National Academy of Sciences 

NGCC Natural Gas Combined Cycle 

NOx Nitrogen Oxides 

NRC National Research Council 

NSPS New Source Performance Standard 

NSR New Source Review 

NTTAA National Technology Transfer and Advancement Act 

OMB Office of Management and Budget 

PM Particulate Matter 

PM2.5 Fine Particulate Matter 

PRA Paperwork Reduction Act 

PSB Public Service Board 

PUC Public Utilities Commission 

RE Renewable Energy 

REC Renewable Energy Credit 

RES Renewable Energy Standard 

RFA Regulatory Flexibility Act 

RGGI Regional Greenhouse Gas Initiative 

RIA Regulatory Impact Analysis 

RPS Renewable Portfolio Standard 

RTO Regional Transmission OperatorOrganization

SBA Small Business Administration 

SBC System Benefits Charge 

SCC Social Cost of Carbon 

SIP State Implementation Plan 

SO2 Sulfur Dioxide 

Tg Teragram (one trillion (1012) grams) 

TSD Technical Support Document 

TTN Technology Transfer Network 

UMRA Unfunded Mandates Reform Act of 1995 

UNFCCC United Nations Framework Convention on Climate 

Change 

USGCRP U.S. Global Change Research Program 

VCS Voluntary Consensus Standard 

Organization of This Document. The information presented in 

this preamble is organized as follows: 

I. General Information 
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A. Executive Summary 

B. Organization and Approach for this Final Rule 

II. Background 

A. Climate Change Impacts from GHG Emissions 

B. GHG Emissions from Fossil Fuel-Fired EGUs 

C. The Utility Power Sector 

D. Congress’ Awareness of Climatic ChangeChallenges in Controlling Carbon 

Dioxide Emissions

EE. Clean Air Act Regulations for Power Plants 

F. Congressional Awareness of Climate Change 

G. International Agreements and Actions 

F. Statutory and Regulatory Requirements 

GH. Legislative and Regulatory Background for CAA Section 111

HI. Statutory and Regulatory Requirements 

J. Clean Power Plan Proposal and Supplemental Proposal 

IK. Stakeholder Outreach and Consultations 

JL. Comments on the Proposal 

III. Rule Requirements and Legal Basis

A. Summary of Rule Requirements 

B. Summary of Legal Basis 

IV. Authority for this Rulemaking, Definition of Affected 

Sources, and Treatment of Categories

A. EPA’s Authority under CAA Section 111(d)

B. CAA Section 112 Exclusion to CAA Section 111(d) Authority 

C. Authority to Regulate EGUs 

D. Definition of Affected Sources 

E. Combined Categories and Codification in the Code of Federal 

Regulations 

V. The Best System of Emission Reduction and Associated Building 

Blocks 

A. The Best System of Emission Reduction (BSER) 

B. Legal Discussion of Certain Aspects of the BSER 

C. Building Block 1—Efficiency Improvements at Affected Coal- 

 Fired Steam EGUs 

D. Building Block 2—Generation Shifts Among Affected EGUs 

E. Building Block 3—Renewable Generating Capacity 

VI. Source CategorySubcategory-Specific CO2 Emission Performance 

Rates 

A. Overview 

B. Emission Performance Rate Requirements 

C. Form of the Emission Performance Rates

D. Emission Performance Rate-Setting Equation and Computation 

Procedure 

VII. Statewide CO2 Goals 

A. Overview 
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B. Translating Source Category-Specific Emission Performance 

Rates toReconstituting Statewide Rate-based CO2 Emission 

Performance Goals from the Subcategory-specific Emission 

Performance Rates 

C. Quantifying Mass-based CO2 Emission Performance Goals from the 

Statewide Rate-based CO2 Emission Performance Goals 

D. Addressing Potential Leakage in Determining the Equivalence 

of Statewide CO2 Emission Performance Goals 

E. State Plan Adjustments of State Goals 

F. Geographically Isolated States and Territories with Affected 

EGUs 

VIII. State Plans 

A. Overview 

B. Timeline for State Plan Performance Periodsand Provisions to 

Encourage Early Action

C. State Plan Approaches 

D. State Plan Components and Approvability Criteria 

E. State Plan Submittal and Approval Process and Timing 

F. State Plan Performance Demonstrations 

G. Additional Considerations for Incorporating CO2 Emission 

ReductionState Plans

 Measures in State Plans 

H. Additional Considerations for State Plans 

IH. Resources for States to Consider in Developing Plans 

I. Considerations for CO2 Emission Reduction 

 Measures that Occur at Affected EGUs 

J. Additional Considerations and Requirements for Mass-Based 

State Plans 

K. Additional Considerations and Requirements for Rate-Based 

State Plans 

L. Treatment of Interstate Effects 

IX. Community and Environmental Justice Considerations 

A. Proximity Analysis 

B. Title VI 

C.B. Community Engagement in State Plan Development 

C. Providing Communities with Access to Additional Resources 

D. Federal Programs and Resources Available to Communities 

D.E. Multi-pollutant Planning and Co-pollutants 

F. Assessing Impacts of State Plan Implementation 

E.G. EPA Continued Engagement 

F. Key Changes from Proposal 

X. Interactions with Other EPA Programs and Rules 

A. Implications for the NSR Program 

B. Implications for the Title V Program 

C. Interactions with Other EPA Rules 
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XI. Impacts of this Action 

A. What are the air impacts? 

B. Endangered Species Act 

C. What are the energy impacts? 

D. What are the compliance costs? 

E. What are the economic and employment impacts? 

F. What are the benefits of the proposed action? 

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 (PRA)

C. Regulatory Flexibility Act (RFA)

D. Unfunded Mandates Reform Act of 1995(UMRA) 

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 Risks and Safety Risks 

H. Executive Order 13211, Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use 

I. National Technology Transfer and Advancement Act (NTTAA)

J. Executive Order 12898, Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

K. Congressional Review Act (CRA) 

XIII. Statutory Authority 

I. General Information 

A. Executive Summary 

1. Introduction 

This final rule is a significant step forward in reducing 

greenhouse gas (GHG) emissions in the U.S. In this action, the 

EPA is establishing for the first time GHG emission guidelines 

for existing power plants. These final emission guidelines, 

which rely in large part on already clearly emerging growth in 
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clean energy innovation, development and Purposedeployment, will 

lead to significant carbon dioxide (CO2) emission reductions from 

the utility power sector that will help protect human health and 

the environment from the impacts of the Regulatory Actionclimate 

change. This rule establishes, at the same time, the foundation 

for longer term GHG emission reduction strategies necessary to 

address climate change and, in so doing, confirms the 

international leadership of the U.S. in the global effort to 

address climate change. In this final rule, we have taken care 

to ensure that achievement of the required emission reductions 

will not compromise the reliability of our electric system, or 

the affordability of electricity for consumers. This final rule 

is the result of unprecedented outreach and engagement with 

states, tribes, utilities, and other stakeholders, with 

stakeholders providing more than 4.3 million comments on the 

proposed rule. In this final rule, we have addressed the 

comments and concerns of states and other stakeholders while 

staying consistent with the law. As a result, we have followed 

through on our commitment to issue a plan that is fair, flexible 

and relies on the accelerating transition to cleaner power 

generation that is already well underway in the utility power 

sector.
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Under the authority of Clean Air Act (CAA) section 111(d), 

the EPA is establishing CO2 emission guidelines for existing 

fossil fuel-fired electric generating units (EGUs) – the Clean 

Power Plan. As in the proposal, theseThese final guidelines, 

when fully implemented, will achieve significant reductions in 

CO2 emissions by 2030. At the same time, the guidelines offer, 

while offering states and utilities substantial flexibility and 

latitude in achieving these reductions. In this final rule, the 

EPA has establishedis establishing a CO2 emission performance 

rate for each of two subcategories of fossil fuel-fired EGUs -- 

fossil fuel-fired electric steam generating units and stationary 

combustion turbines. The performance rates reflect – that 

expresses the “best system of emission reductions emissions 

reduction... adequately demonstrated” (BSER) for CO2 emissions from 

the EGU source categorypower sector.1 The EPA is also 

 

1 Under CAA section 111(d), pursuant to 40 CFR 60. 22(b)(5), 

states must establish, in their state plans, emission standards 

that reflect the degree of emission limitation achievable 

through the application of the “best system of emission 

reduction” that, taking into account the cost of achieving such 

reduction and any non-air quality health and environmental 

impacts and energy requirements, the Administrator determines 

has been adequately demonstrated (i.e., the BSER). Under CAA 

section 111(a)(1) and (d), the EPA is authorized to determine 

the BSER and to calculate the amount of emission reduction 

achievable through applying the BSER. The state is authorized to 

identify the emission standard or standards that reflect that 

amount of emission reduction. 
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establishing state-specific rate-based and mass-based goals that 

reflect the subcategory-specific CO2 emission performance rates 

and each state’s mix of affected EGUs. The guidelines also 

provide for the development, submittal and implementation of 

state plans that implement the BSER – again, expressed as CO2 

emission performance rates, – either directly by means of 

source-specific emission standards or other requirements, or 

through measures that achieve equivalent CO2 reductions from the 

same group of EGUs.2 

States, U.S. territories, and tribes3 with one or more 

affected EGUs will be required to develop and implement plans 

tothat set emission standards for affected EGUs. The CAA section 

111(d) emission guidelines that the EPA is promulgating in this 

 

2 A state plan must be developed by a state, the District of 

Columbia, a U.S. territory, and any Indian tribe that has been 

approved by the EPA pursuant to 40 CFR 49.9 as eligible to 

develop and implement a CAA section 111(d) plan if it has one or 

more affected EGUs in its jurisdiction. 

3

 In the case of a tribe that has one or more affected EGUs in 

its area of Indian country, the tribe has the opportunity, but 

not the obligation, to establish a CO2 emission performance 

standard and a CAA section 111(d) plan for its area of Indian 

country. If the EPA determines that such a plan is necessary or 

appropriate, it has the responsibility to establish CAA section 

111(d) plans for areas of Indian country where affected sources 

are located unless a tribe on whose lands an affected source (or 

sources) is located seeks and obtains authority from the EPA to 

develop and implement a CAA section 111(d) plan, pursuant to the 

40 CFR 49.9
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action apply to only the 48 contiguous states and any Indian 

tribe that has been approved by the EPA pursuant to 40 CFR 49.9 

as eligible to develop and implement a CAA section 111(d) plan.4

Because Vermont and the District of Columbia do not have 

affected EGUs, they will not be required to submit a state plan. 

Because the EPA does not possess all of the information or 

analytical tools needed to quantify the BSER for the two noncontiguous states with otherwise affected EGUs (Alaska and 

Hawaii) and the two U.S. territories with otherwise affected 

EGUs (Guam and Puerto Rico), these emission guidelines do not 

apply to those areas, and those areas will not be required to 

submit state plans on the schedule required by this final 

action. 

The emission standards in a state’s plan may incorporate 

the subcategory-specific CO2 emission performance rates set by 

 

4 In the case of a tribe that has one or more affected EGUs in 

its area of Indian country, the tribe has the opportunity, but 

not the obligation, to establish a CO2 emission standard for each 

affected EGU located in its area of Indian country and a CAA 

section 111(d) plan for its area of Indian country. If the tribe 

chooses to establish its own plan, it must seek and obtain 

authority from the EPA to do so pursuant to 40 CFR 49.9. If it 

chooses not to seek this authority, the EPA has the 

responsibility to determine whether it is necessary or 

appropriate, in order to protect air quality, to establish a CAA 

section 111(d) plan for an area of Indian country where affected 

EGUs are located. 
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the EPA or, in the alternative, may be set at levels that ensure 

that theirthe state’s affected EGUs, individually, in aggregate, 

or in combination with other measures undertaken by the state,5

achieve the equivalent of the interim and final CO2 emission 

performance rates between 2022 and 2029 and by 2030., 

respectively. State plans must also: 1) ensure that the period 

for emission reductions from the affected EGUs begin no later 

than 2022 and, 2) show how goals for the interim and final 

periods will be met, 3) ensure that, during the period from 2022 

to 2029, affected EGUs in the state collectively meet the 

equivalent of the interim CO2 emission performance 

ratessubcategory-specific CO2 emission performance rates, and 4) 

provide for periodic state-level demonstrations prior to and 

during the 2022-2029 period that will ensure required CO2

emission reductions are being accomplished and no increases in 

emissions relative to each state’s planned emission reduction 

trajectory are occurring. A Clean Energy Incentive Program 

(CEIP) will provide opportunities for investments in renewable 

 

5 The CAA section 111(d) emission guidelines apply to the 50 

states, the District of Columbia, U.S. territories, and any 

Indian tribe that has been approved by the EPA pursuant to 40 

CFR 49.9 as eligible to develop and implement a CAA section 

111(d) plan. In this preamble, in instances where these 

governments are not specifically listed, the term “state” is 

used to represent them. 
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energy (RE) and demand-side energy efficiency (EE) that deliver 

results in 2020 and/or 2021. The plans must be submitted to the 

EPA in 2016, though an extension to 2018 is available to allow 

for the completion of stakeholder and administrative processes. 

The EPA has translated the source categoryis 

promulgating: 1) subcategory-specific CO2 emission 

performance rates into equivalent , 2) state-level ratebased goals, and 3) state mass-based CO2 goals in order to 

maximizethat represent the rangeequivalent of each state’s 

rate-based goal. This will facilitate states’ choices, 

including application of in developing their plans, 

particularly for those seeking to adopt mass-based 

allowance trading programs or other statewide policy 

measures as well as, or instead of, source-specific 

requirements, that . The EPA received significant comment 

to the effect that mass-based allowance trading was not 

only highly familiar to states will have in developing 

their plans. and EGUs, but that it could be more readily 

applied than rate-based trading for achieving emission 

reductions in ways that optimize affordability and electric 

system reliability.

In this summary, we discuss the purpose of thethis rule, 

key changes from the proposal, the context for the rulemaking, 
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the major provisions of the final rule, the context for the 

rulemaking, key changes from the proposal, the estimated CO2

emission reductions, and the costs and benefits expected to 

result from full implementation of this final action. Greater 

detail is provided in the body of this preamble, the regulatory 

impacts analysis (RIA),, the response to comments (RTC) 

documents, and various technical support documentsTSDs and 

memoranda addressing specific topics. 

2. Purpose of this rule 

The purpose of this CAA section 111(d) rule is to 

addressprotect human health and the environment by reducing CO2

emissions from fossil fuel-fired power plants in the U.S. 

because theyThese plants are by far the largest domestic 

stationary source of emissions of carbon dioxide (CO2),, the most 

prevalent of the group of air pollutant greenhouse gases 

(GHG)GHGs that the EPA has determined endangers public health 

and welfare through its contribution to climate change. This 

rule establishes for the first time emission guidelines for 

existing power plants that. These guidelines will lead to 

significant reductions in CO2 emissions. At the same time, these 

emission guidelines will , result in cleaner generation from the 

existing power plant fleet, and will support continued 

investments by the industry in cleaner power generation to 
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ensure reliable, affordable electricity now and into the future. 

Concurrent with this action, the EPA is also issuing a 

final rule that establishes CO2 emission standards of performance 

for new, modified, and reconstructed power plants. Together, 

these rules will reduce CO2 emissions by a substantial amount 

while ensuring that the utility power sector in the U.S. can 

continue to supply reliable and affordable electricity to all 

Americans using a diverse fuel supply. As with past EPA rules 

addressing air pollution from the utility power sector, these 

guidelines have been designed with a clear recognition of the 

unique features of this sector. LikeSpecifically, the agency 

recognizes that utilities provide an essential public service 

and are regulated and managed in ways unlike any other 

industrial activity. In providing assurances that the emission 

reductions required by this rule can be achieved without 

compromising continued reliable, affordable electricity, this 

final rule fully accounts for the critical service utilities 

provide. 

As with past rules under CAA section 111, this rule relies 

on proven technologies and approachesmeasures to set achievable 

standardsemission performance rates that will lead to costeffective pollutant emission reductions, in this case CO2

emission reductions at power plants, across the country. In 
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fact, the emission guidelines reflect strategies, technologies 

and approaches already in widespread use by utilitiespower 

companies and states. The vast preponderance of the input we 

received from stakeholders is supportive of this conclusion. 

States will play a key role in ensuring that emission 

reductions are achieved at a reasonable cost. The experience of 

states in this regard is especially important because CAA 

section 111(d) itself relies on athe well-established state-EPA 

partnership to accomplish the required emission reductions.CO2

emission reductions. States will have the flexibility to choose 

from a range of plan approaches and measures, including numerous 

measures beyond those considered in setting the CO2 emission 

performance rates, and this final rule allows and encourages 

states to adopt the most effective set of solutions for their 

circumstances, taking account of cost and other considerations.

This rulemaking, which will be implemented through thatthe 

state-EPA partnership, is a significant step that will reduce 

air pollution, in this case GHG emissions, in the U.S. At the 

same time, the final rule greatly facilitates flexibility for 

EGUs by establishing a basis for states to set trading-based 

emission standards and compliance strategies. The rule 

establishes this basis by including both uniform emission 

performance rates for the two subcategories of sources and also 
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state-specific rate- and mass-based goals.

This final rule is also a significant step forward in 

implementing the President’s Climate Action Plan.6 To address the 

far-reaching harmful consequences and real economic costs of 

climate change, the President’s Climate Action Plan details a 

broad array of actions to reduce GHG emissions that contribute 

to climate change and its harmful impacts on public health and 

the environment. Climate change is already occurring in this 

country, affecting the health, economic well-being and quality 

of life of Americans across the country, and especially those in 

the most vulnerable communities. This CAA section 111(d) 

rulemaking to reduce GHG emissions from existing power plants, 

and the concurrent CAA section 111(b) rulemaking to reduce GHG 

emissions from new, modified, and reconstructed power plants, 

implement one of the strategies of the Climate Action Plan. 

Nationwide, by 2030, this final CAA section 111(d) existing 

source rule will achieve CO2 emission reductions from the utility 

power sector of approximately [X]32 percent from CO2 emission 

levels in 2005. 

The EPA projects that these reductions, along with 

 

6 The President’s Climate Action Plan, June 2013. 

http://www.whitehouse.gov/sites/default/files/image/president27s

climateactionplan.pdf.
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reductions in other air pollutants, to which resulting directly 

from this rule will lead, will result in net climate and health 

benefits of $[X]$25 billion to $[X]$45 billion in 2030. At the 

same time, coal and natural gas will remain the two leading 

sources of electricity generation in the U.S., with coal 

providing about [X]27 percent of the projected generation and 

natural gas providing about [X]33 percent of the projected 

generation. 

3. Summary of major provisions 

a. Overview. The fundamental goal of this rule is to reduce 

harmful emissions of CO2 from fossil fuel-fired EGUs in 

accordance with the requirements of the CAA. The June 2014 

proposal for this rule was designed to meet this overarching 

goal while accommodating two important objectives. The first was 

to establish guidelines that reflect both the unique 

interconnected and interdependent manner in which the power 

system operates and the actions, strategies, and policies states 

and utilities have already been undertaking that are resulting 

in CO2 emission reductions. The second objective was to provide 

states and utilities with broad flexibility and choice in 

meeting those requirements in order to minimize costs to 

ratepayers and to ensure the reliability of electricity supply. 

In this final rule, the EPA has focused on changes that, in 
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addition to being responsive to the critical concerns and 

priorities of stakeholders, more fully accomplish these 

objectives. 

While our consideration of public input and additional 

information has led to notable revisions from the emission 

guidelines we proposed in June 2014, the proposed guidelines 

remain the foundation of this final rule. These final guidelines 

build on the progress already underway to reduce the carbon 

intensity of power generation in the U.S., especially through 

the lowest carbon-intensive technologies, while reflecting the 

unique interconnected and interdependent system within which 

EGUs operate. Thus, the BSER, as determined in these guidelines, 

incorporates a range of CO2-reducing actions, while at the same 

time adhering to the fundamental approach the EPA has relied on 

for decades in implementing section 111 of the CAA. 

Specifically, in making its BSER determination, the EPA examined 

not only actions, technologies and measures already in use by 

EGUs and states, but also deliberately incorporated in its 

identification of the BSER the unique way in which affected EGUs 

actually operate in providing electricity services. This latter 

feature of the BSER mirrors Congress’ approach to regulating air 

pollution in this sector, as exemplified by Title IV of the CAA. 

There, Congress established a pollution reduction program 
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specifically for fossil fuel-fired EGUs and designed the sulfur 

dioxide (SO2) portion of that program with express recognition of 

the utility power sector’s ability to shift generation among 

various EGUs, which enabled pollution reduction by increasing 

reliance on RE and even on demand-side EE. The result of our 

following Congress’ recognition of the interdependent operation 

of EGUs within an interconnected grid is the incorporation in 

the BSER of measures, such as shifting generation to loweremitting NGCC units and increased use of RE, that rely on the 

current interdependent operation of EGUs. As we noted in the 

proposal and note here as well, the EPA undertook an 

unprecedented and sustained process of engagement with the 

public and stakeholders. It is, in many ways, as a direct result 

of public discussion and input that the EPA came to recognize 

the substantial extent to which the BSER needed to account for 

the unique interconnected and interdependent operations of EGUs 

if it was to meet the criteria on which the EPA has long relied 

in making BSER determinations. 

Equally important, these guidelines offer states and owners 

and operators of EGUs broad flexibility and latitude in 

complying with their obligations. Because affordability and 

electricity system reliability are of paramount importance, the 

rule provides states and utilities with time for planning and 
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investment, which is instrumental to ensuring both manageable 

costs and system reliability, as well as to facilitating clean 

energy innovation. The final rule continues to express the CO2

emission reduction requirements in terms of state goals, as well 

as in terms of emission performance rates for the two 

subcategories of affected EGUs, reflecting the particular mix of 

power generation in each state, and it continues to provide 

until 2030, fifteen years from the date of this final rule, for 

states and sources to achieve the CO2 reductions. Numerous 

commenters, including most sources, states and energy agencies, 

indicated that this was a reasonable timeframe. The final 

guidelines also continue to provide an option where programs 

beyond those directly limiting power plant emission rates can be 

used for compliance (i.e., policies, programs and other 

measures). The final rule also continues to allow, but not 

require, multi-state approaches. Finally, EPA took care to 

ensure that states could craft their own emissions reduction 

trajectories in meeting the interim goals included in this final 

rule. 

b. Opportunities for states. As stated above, the final 

guidelines are designed to build on and reinforce progress by 

states, cities and towns, and companies on a growing variety of 

sustainable strategies to reduce power sector CO2 emissions. 
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States, in their CAA section 111(d) plans, will be able to rely 

on, and extend, programs they may already have created to 

address emissions of air pollutants, and in particular CO2, from 

the utility power sector or to address the sector from an 

overall perspective. Those states committed to Integrated 

Resource Planning (IRP) will be able to establish their CO2

reduction plans within that framework, while states with a more 

deregulated power sector system will be able to develop CO2

reduction plans within that specific framework. Each state will 

have the opportunity to take advantage of a wide variety of 

strategies for reducing CO2 emissions from affected EGUs, 

including demand-side energy efficiency programs and mass-based 

trading, which some suggested in their comments. The EPA and 

other federal entities, including the U.S. Department of Energy 

(DOE), the Federal Energy Regulatory Commission (FERC) and the 

U.S. Department of Agriculture (USDA), among others, are 

committed to sharing expertise with interested states as they 

develop and implement their plans. 

States will be able to address the economic interests of 

their utilities and ratepayers by using the flexibilities in 

this final action to reduce costs to consumers, minimize 

stranded assets, and spur private investments in RE and EE 

technologies and businesses. They may also, if they choose, work 
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with other states on multi-state approaches that reflect the 

regional structure of electricity operating systems that exists 

in most parts of the country and is critical to ensuring a 

reliable supply of affordable energy. The final rule gives 

states the flexibility to implement a broad range of approaches 

that recognize that the utility power sector is made up of a 

diverse range of companies of various sizes that own and operate 

fossil fuel-fired EGUs, including vertically integrated 

companies in regulated markets, independent power producers, 

rural cooperatives and municipally-owned utilities, some of 

which are likely to have more direct access than others to 

certain types of GHG emission reduction opportunities, but all 

of which have a wide range of opportunities to achieve 

reductions or acquire clean generation. 

Again, with features that facilitate mass-based and/or 

interstate trading, the final guidelines also empower affected 

EGUs to pursue a broad range of choices for compliance and for 

integrating compliance action with the full range of their 

investments and operations. 

c. Main elements. This final rule comprises three main elements: 

1) two subcategory-specific CO2 emission performance rates 

resulting from application of the BSER to the two subcategories 

of affected EGUs; 2) state-specific CO2 goals, expressed as both 
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emission rates and as mass, that reflect the subcategoryspecific CO2 emission performance rates and each state’s mix of 

affected EGUsthe two performance rates; and 3) guidelines for 

the development, submittal and implementation of state plans 

that implement those BSER emission performance rates either 

through emission standards for affected EGUs, or through 

measures that achieve the equivalent, in aggregate, of those 

rates as defined and expressed in the form of the state goals. 

In this final action, the EPA is setting emission 

performance rates, phased in over the period from 2022 

through 2030, for two subcategories of affected fossil 

fuel-fired EGUs – fossil fuel-fired electric utility steamgenerating units and stationary combustion turbines. These 

rates, applied to each state’s particular mix of fossil 

fuel-fired EGUs, generate the state’s carbon intensity goal 

for 2030 (and interim rates for the period 2022-2029). Each 

state will determine whether to apply these to each 

affected EGU or to take an alternative approach and meet 

either an equivalent statewide rate-based goal or statewide 

mass-based goal. The EPA does not prescribe how a state 

must meet the emission guidelines, but, if a state chooses 

to take the path of meeting a state goal, these final 

guidelines identify the methods that a state can or, in 
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some cases, must use to demonstrate that the combination of 

measures and standards that the state adopts meets its 

state-level CO2 goals. While the EPA accomplishes the phasein of the interim goal by way of annual emission 

performance rates, states and EGUs may meet their 

respective emission reduction obligations “on average” over 

that period following whatever emission reduction 

trajectory they determine to pursue over that period. 

CAA section 111(d) creates a partnership between the 

EPA and the states under which the EPA establishes emission 

guidelines and the states take the lead on implementing 

them by establishing emission standards or creating plans 

that are consistent with the EPA emission guidelines. The 

EPA recognizes that each state has differing policy 

considerations – including varying regional emission 

reduction opportunities and existing state programs and 

measures – and that the characteristics of the electricity 

system in each state (e.g., utility regulatory structure 

and generation mix) also differ. Therefore, as in the 

proposal, each state will have the latitude to design a 

program to meet source-category specific emission 

performance rates or the equivalent statewide rate- or 

mass-based goal in a manner that reflects its particular 
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circumstances and energy and environmental policy 

objectives. Each state can do so on its own, or a state can 

collaborate with other states and/or tribal governments on 

multi-state plans, or states can include in their plans the 

trading tools that EGUs can use to realize additional 

opportunities for cost savings while continuing to operate 

across the interstate system through which electricity is 

produced. A state would also have the option of adopting 

the model rules for either a rate- or a mass-based program 

that the EPA is proposing concurrently with this action.7

To facilitate the state planning process, this final 

rule establishes guidelines for the development, submittal, 

and implementation of state plans. The final rule describes 

the components of a state plan, the additional latitude 

states have in developing strategies to meet the emission 

guidelines, and the options they have in the timing of 

submittal of their plans. This final rule also gives states 

considerable flexibility with respect to the timeframes for 

plan development and implementation, as well as the choice 

of emission reduction measures. The final rule provides up 

 

7 The EPA’s proposed CAA section 111(d) federal plan and model 

rules for existing fossil fuel-fired EGUs are being published 

concurrently with this final rule. 
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to fifteen years for full implementation of all emission 

reduction measures, with incremental steps for planning and 

then for demonstration of CO2 reductions that will ensure 

that progress is being made in achieving CO2 emission 

reductions. States will be able to choose from a wide range 

of emission reduction measures, including measures that are 

not part of the BSER, as discussed in detail in section 

VIII.G of this preamble. 

d. Determining the BSER. In issuing this final rulemaking, the 

EPA is implementing statutory provisions that have been in place 

since Congress first enacted the CAA in 1970 and that have been 

implemented pursuant to regulations promulgated in 1975 and 

followed in numerous subsequent CAA section 111 rulemakings. 

These requirements call on the EPA to develop emission 

guidelines that reflect the EPA’s determination of the “best 

system of emission reduction... adequately demonstrated”for 

states to follow in formulating plans to establish emission 

standards to implement the BSER. 

As the EPA has done in making BSER determinations in 

previous CAA section 111 rulemakings, for this final BSER 

determination, the agency considered the types of strategies 

that states and owners and operators of EGUs are already 
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employing to reduce the covered pollutant (in this case, CO2) 

from affected sources (in this case, fossil fuel-fired EGUs).8 

In so doing, as has always been the case, our 

considerations were not limited solely to specific technologies 

or equipment in hypothetical operation; rather, our analysis 

encompassed the full range of operational practices, 

limitations, constraints and opportunities that bear upon EGUs’ 

emission performance, and which reflect the unique 

interconnected and interdependent operations of EGUs and the 

overall electricity grid. 

In this final action, the agency has determined that the 

BSER comprises the first three of the four proposed “building 

blocks,” with certain refinements to the three building blocks. 

The three building blocks are: 

1. Improving heat rate at affected coal-fired steam 

EGUs. 

 

8 The final emission guidelines for landfill gas emissions from 

municipal solid waste landfills, published on March 12, 1996, 

and amended on June 16, 1998 (61 FR 9905 and 63 FR 32743, 

respectively), provide an example, as the guidelines allow 

either of two approaches for controlling landfill gas – by 

recovering the gas as a fuel, for sale, and removing from the 

premises, or by destroying the organic content of the gas on the 

premises using a control device. Recovering the gas as a fuel 

source was a practice already being used by some affected 

sources prior to promulgation of the rulemaking. 
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2. Substituting increased generation from loweremitting existing natural gas combined cycle units 

for reduced generation from higher-emitting affected 

steam generating units. 

3. Substituting increased generation from new zeroemitting renewable energy generating capacity for 

reduced generation from affected fossil fuel-fired 

generating units. 

These three building blocks are approaches that are 

available to all affected EGUs, either through direct 

investment or operational shifts or through emissions 

trading where states, which must establish emission 

standards for affected EGUs, do so by incorporating 

emissions trading.9 At the same time, and as we noted in the 

proposal, there are numerous other measures available to 

reduce CO2 emissions from affected EGUs, and our 

determination of the BSER does not necessitate the use of 

the three building blocks to their maximum extent, or even 

 

9 The EPA notes that, in quantifying the emission reductions that 

are achievable through application of the BSER, some building 

blocks will apply to some, but not all, affected EGUs. 

Specifically, building block 1 will apply to affected coal-fired 

steam EGUs, building block 2 will apply to all affected steam 

EGUs (both coal-fired and oil/gas-fired), and building block 3 

will apply to all affected EGUs. 
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at all. The building blocks and the BSER determination are 

described in detail in section V of this preamble. 

e. CO2 state-level goals and subcategory-specific emission 

performance rates. 

(1) Final CO2 goals and emission performance rates. 

In this action, the EPA is establishing CO2 emission 

performance rates for two subcategories of affected EGUs -- 

fossil fuel-fired electric utility steam generating units and 

stationary combustion turbines. For fossil fuel-fired steam 

generating units, we are finalizing an emission performance rate 

of 1,305 lb CO2/MWh. For stationary combustion turbines, we are 

finalizing an emission performance rate of 771 lb CO2/MWh. As we 

did at proposal, for each state, we are also promulgating ratebased CO2 goals that are the weighted aggregate of the emission 

performance rates for the state’s EGUs. To ensure that states 

and sources can choose additional alternatives in meeting their 

obligations, the EPA is also promulgating each state’s goal 

expressed as a CO2 mass goal. The inclusion of mass-based goals, 

along with information provided in the proposed federal plan and 

model rules that are being issued concurrently with this rule, 

paves the way for states to implement mass-based trading, as 

some states have requested, reflecting their view that mass-
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based trading provides significant advantages over rate-based 

trading. 

Affected EGUs, individually, in aggregate, or in 

combination with other measures undertaken by the state, 

must achieve the equivalent of the CO2 emission performance 

rates, expressed via the state-specific rate- and massbased goals, by 2030. 

(2) Interim CO2 emission performance rates and statespecific goals. 

The best system of emission reduction includes both the 

measures for reducing CO2 emissions and the timeframe over which 

they can be implemented. In this final action, the EPA is 

establishing an eight-year interim period, beginning in 2022 

instead of 2020, over which to achieve the full required 

reductions to meet the CO2 performance rates, a commencement date 

more than six years from [INSERT THE DATE OF PUBLICATION IN THE 

FEDERAL REGISTER], the date of this rulemaking. This eight-year 

interim period from 2022 through 2029 is separated into three 

steps, 2022-2024, 2025-2027, and 2028-2029, each associated with 

its own interim CO2 emission performance rates. The interim steps 

are presented both in terms of emission performance rates for 

the two subcategories of affected EGUs and in terms of state 

goals, expressed both as a rate and as a mass. A state may adopt 
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emission standards for its sources that are identical to these 

interim emission performance rates or, alternatively, adapt 

these steps to accommodate the timing of expected reductions, as 

long as the state’s interim goal is met over the eight-year 

period. 

f. State plans.10 

In this action, the EPA is establishing final 

guidelines for states to follow in developing, submitting 

and implementing their plans. In developing plans, states 

will need to choose the type of plan they will develop. 

They will also need to include required plan components in 

their plan submittals, meet plan submittal deadlines, 

achieve the required CO2 emission reductions over time, and 

provide for monitoring and periodic reporting of progress.

 

10 The CAA section 111(d) emission guidelines apply to the 50 

states, the District of Columbia, U.S. territories, and any 

Indian tribe that has been approved by the EPA pursuant to 40 

CFR 49.9 as eligible to develop and implement a CAA section 

111(d) plan. In this preamble, in instances where these 

governments are not specifically listed, the term “state” is 

used to represent them. Because Vermont and the District of 

Columbia do not have affected EGUs, they will not be required to 

submit a state plan. Because the EPA lacks appropriate 

information to quantify the BSER for the two non-contiguous 

states with affected EGUs (Alaska and Hawaii) and the two U.S. 

territories with affected EGUs (Guam and Puerto Rico), we are 

not finalizing emission performance rates in those areas at this 

time, and those areas will not be required to submit state plans 

until we do. 
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As with the BSER determination, stakeholder comments have 

provided both data and recommendations to which these final 

guidelines are responsive. 

(1) Plan approaches. 

To comply with these emission guidelines, a state will have 

to ensure, through its plan, that the emission standards it 

establishes for its sources individually, in aggregate, or in 

combination with other measures undertaken by the state, 

represent the equivalent of the subcategory-specific CO2 emission 

performance rates. This final rule includes several options for 

state plans, as discussed in the proposal and in many of the 

comments we received. 

First, in the final rule, states may establish emission 

standards for their affected EGUs that mirror the uniform 

emission performance rates for the two subcategories of sources 

included in this final rule. They may also pursue alternative 

approaches that adopt emission standards that meet the uniform 

emission performance rates, or emission standards that meet 

either the rate-based goal promulgated for the state or the 

alternative mass-based goal promulgated for the state. It is for 

the purpose of providing states with these choices that the EPA 

is providing state-specific rate-based and mass-based goals 

equivalent to the emission performance rates that the EPA is 
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establishing for the two subcategories of fossil fuel-fired 

EGUs. A detailed explanation of rate- and mass-based goals is 

provided in section VII of this preamble and in a TSD.11 In 

developing its plan, each state and eligible tribe electing to 

submit a plan will need to choose whether its plan will result 

in the achievement of the CO2 emission performance rates, 

statewide rate-based goals, or statewide mass-based goals by the 

affected EGUs. 

The second major set of options provided in the final rule 

includes the types of measures states may rely on through the 

state plans. A state will be able to choose to establish 

emission standards for its affected EGUs sufficient to meet the 

requisite performance rates or state goal, thus placing all of 

the requirements directly on its affected EGUs, which we refer 

to as the “emission standards approach.” Alternatively, a state 

can adopt a “state measures approach,” which would result in the 

affected EGUs meeting the statewide mass-based goal by allowing 

a state to rely upon state-enforceable measures on entities 

other than affected EGUs, in conjunction with any federally 

enforceable emission standards the state chooses to impose on 

affected EGUs. With a state measures approach, the plan must 

 

11 The CO2 Emission Performance Rate and Goal Computation TSD for 

the CPP Final Rule, available in the docket for this rulemaking. 
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also include a contingent backstop of federally enforceable 

emission standards for affected EGUs that fully meet the 

emission guidelines and that would be triggered if the plan 

failed to achieve the required emission reductions on schedule. 

A state would have the option of basing its backstop emission 

standards on the model rule, which focuses on the use of 

emissions trading as the core mechanism, that the EPA is 

proposing today. A state that adopts a state measures approach 

must use its mass CO2 emission goal as the metric for 

demonstrating plan performance. 

The final rule requires that the state plan submittal 

include a timeline with all of the programmatic milestone steps 

the state will take between the time of the state plan submittal 

and the year 2022 to ensure that the plan is effective as of 

2022. States must submit a report to the EPA in 2021 that 

demonstrates that the state has met the programmatic milestone 

steps that the state indicated it would take during the period 

from the submittal of the final plan through the end of 2020, 

and that the state is on track to implement the approved state 

plan as of January 1, 2022. 

The plan must also include a process for reporting on plan 

implementation, progress toward achieving CO2 emission 

reductions, and implementation of corrective actions, in the 
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event that the state fails to achieve required emission levels 

in a timely fashion. Beginning January 1, 2025, and then January 

1, 2028, January 1, 2030, and then every two calendar years 

thereafter, the state will be required to compare emission 

levels achieved by affected EGUs in the state with the emission 

levels projected in the state plan and report the results of 

that comparison to the EPA by July 1 of those calendar years. 

Existing state programs can be aligned with the 

various state plan options further described in Section 

VIII. A state plan that uses one of the finalized model 

rules, which the EPA is proposing concurrently with this 

action, could be presumptively approvable if the state plan 

meets all applicable requirements.12 The plan guidelines 

provide the states with the ability to achieve the full 

reductions over a multi-year period, through a variety of 

reduction strategies, using state-specific or multi-state 

approaches that can be achieved on either a rate or mass 

basis. They also address several key policy considerations 

that states can be expected to contemplate in developing 

their plans. 

 

12 The EPA would take action on such a state plan through 

independent notice and comment rulemaking. 
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State plan approaches and plan guidelines are explained 

further in section VIII of this preamble. 

(2) State plan components and approvability criteria. 

The EPA’s implementing regulations provide certain basic 

elements required for state plans submitted pursuant to CAA 

section 111(d).13 In the proposal, the EPA identified certain 

additional elements that should be contained in state plans. In 

this final action, in response to comments, the EPA is making 

several revisions to the components required in a state plan 

submittal and is also incorporating the approvability criteria 

into the final list of components required in a state plan 

submittal. In addition, we have organized the state plan 

components to reflect: 1) components required for all state plan 

submittals; 2) additional components required for the emission 

standards approach; and 3) additional components required for 

the state measures approach. 

All state plans must include the following components: 

 Description of the plan 

 Applicability of state plans to affected EGUs

 Demonstration that the plan submittal is projected to 

achieve the state’s CO2 emission performance rates or 

state CO2 goal14

 

13 40 CFR 60.23. 

14 A state that chooses to set emission standards that are 

identical to the emission performance rates for both the interim 

period and in 2030 and beyond need not identify interim state 
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 Monitoring, reporting and recordkeeping requirements 

for affected EGUs

 State recordkeeping and reporting requirements 

 Public participation and certification of hearing on 

state plan 

 Supporting documentation 

 

Also, in submitting state plans, states must provide 

documentation demonstrating that they have considered electric 

system reliability in developing their plans. 

Further, in this final rule, the EPA is requiring states to 

demonstrate how they are meaningfully engaging all stakeholders, 

including workers and low-income communities, communities of 

color, and indigenous populations living near power plants and 

otherwise potentially affected by the state’s plan. In their 

plan submittals, states must describe their engagement with 

their stakeholders, including their most vulnerable communities. 

The participation of these communities, along with that of 

ratepayers and the public, can be expected to help states ensure 

that state plans maintain the affordability of electricity for 

all and preserve and expand jobs and job opportunities as they 

move forward to develop and implement their plans. 

State plan submittals using the emission standards approach 

must also include: 

 Identification of each affected EGU; identification of 

 

goals nor include a separate demonstration that its plan will 

achieve the state goals. 
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federally enforceable emission standards for the affected 

EGUs; and monitoring, recordkeeping and reporting 

requirements. 

 Demonstrations that each emission standard will result in 

reductions that are quantifiable, non-duplicative, 

permanent, verifiable, and enforceable. 

State plan submittals using the state measures approach 

must also include: 

 Identification of each affected EGU; identification of 

federally enforceable emission standards for affected EGUs 

(if applicable); identification of backstop of federally 

enforceable emission standards; and monitoring, 

recordkeeping and reporting requirements. 

 Identification of each state measure and demonstration that 

each state measure will result in reductions that are 

quantifiable, non-duplicative, permanent, verifiable, and 

enforceable. 

In addition to these requirements, each state plan must follow 

the EPA implementing regulations at 40 CFR 60.23. 

(3) Timing and process for state plan submittal and review. 

Because of the compelling need for actions to begin the steps 

necessary to reduce GHG emissions from EGUs, the EPA proposed 

that states submit their plans within 13 months of the date of 

this final rule and that reductions begin in 2020. In light of 

the comments received and in order to provide maximum 

flexibility to states while still taking timely action to reduce 

CO2 emissions, in this final rule the EPA is allowing for a 2-

year extension until September 6, 2018, for both individual and 

multi-state plans, to provide a total of 3 years for states to 
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submit a final plan if an extension is received. Specifically, 

the final rule requires each state to submit a final plan by 

September 6, 2016. Since some states may need more than one year 

to complete all of the actions needed for their final state 

plans, including technical work, state legislative and 

rulemaking activities, a robust public participation process, 

coordination with third parties, coordination among states 

involved in multi-state plans, and consultation with reliability 

entities, the EPA is allowing an optional two-phased submittal 

process for state plans. If a state needs additional time to 

submit a final plan, then the state may request an extension by 

submitting an initial submittal by September 6, 2016. For the 

extension to be granted, the initial submittal must address 

three required components sufficiently to demonstrate that a 

state is able to undertake steps and processes necessary to 

timely submit a final plan by the extended date of September 6, 

2018. These components are: an identification of final plan 

approach or approaches under consideraton, including a 

description of progress made to date; an appropriate explanation 

for why the state needs additional time to submit a final plan 

beyond September 6, 2016; and a demonstration of how they have 

been engaging with the public, including vulnerable communities, 

and a description of how they intend to meaningfully engage with 
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community stakeholders during the additonal time (if an 

extension is granted) for development of the final plan, as 

described in section VIII.E of this preamble. As further 

described in section VIII.B of this preamble, the EPA is 

establishing a CEIP in order to promote early action. States’ 

participation in the CEIP is optional. In order for a state to 

participate in the program, it must include in its initial 

submittal, if applicable, a non-binding statement of intent to 

participate in the CEIP; if a state is submitting a final plan 

by September 6, 2016, it must include such a statement of intent 

as part of its supporting documentation for the plan. 

If the initial submittal includes those components and if 

the EPA does not notify the state that the initial submittal 

does not contain the required components, then, within 90 days 

of the submittal, the extension of time to submit a final plan 

will be deemed granted. A state will then have until no later 

than September 6, 2018, to submit a final plan. The EPA will 

also be working with states during the period after they make 

their initial submittals and provide states with any necessary 

information and assistance during the 90-day period. Further, 

states participating in a multi-state plan may submit a single 

joint plan on behalf of all of the participating states. 
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States and tribes that do not have any affected EGUs in 

their jurisdictional boundaries may provide emission rate 

credits (ERCs) to adjust CO2 emissions, provided they are 

connected to the contiguous U.S. grid and meet other 

requirements for eligibility. There are certain limitations and 

restrictions for generating ERCs, and these, as well as 

associated requirements, are explained in section VIII of this 

preamble. 

Following submission of final plans, the EPA will 

review plan submittals for approvability. Given a similar 

timeline accorded under section 110 of the CAA, and the 

diverse approaches states may take to meet the CO2 emission 

performance rates or equivalent statewide goals in the 

emission guidelines, the EPA is extending the period for 

EPA review and approval or disapproval of plans from the 

four-month period provided in the EPA implementing 

regulations to a twelve-month period. This timeline will 

provide adequate time for the EPA to review plans and 

follow notice-and-comment rulemaking procedures to ensure 

an opportunity for public comment. The EPA, especially 

through our regional offices, will be available to work 

with states as they develop their plans, in order to make 

review of submitted plans more straightforward and to 
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minimize the chances of unexpected issues that could slow 

down approval of state plans. 

(4) Timing for implementing the CO2 emission guidelines. 

 The EPA recognizes that the measures states and utilities 

have been and will be taking to reduce CO2 emissions from 

existing EGUs can take time to implement. We also recognize that 

investments in low-carbon intensity and renewable energy and in 

energy efficiency strategies are currently underway and in 

various stages of planning and implementation widely across the 

country. We carefully reviewed information submitted to us 

regarding the feasible timing of various measures and 

identifying concerns that the required CO2 emission reductions 

could not be achieved as early as 2020 without compromising 

electric system reliability, imposing unnecessary costs on 

ratepayers, and requiring investments in more carbon-intensive 

generation, while diverting investment in cleaner technologies. 

The record is compelling. To respond to these concerns and to 

reflect the period of time required for state plan development 

and submittal by states, review and approval by the EPA, and 

implementation of approved plans by states and affected EGUs, 

the EPA is determining in this final rule that affected EGUs 

will be required to begin to make reductions by 2022, instead of 

2020, as proposed, and meet the final CO2 emission performance 
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rates or equivalent statewide goals by no later than 2030. The 

EPA is establishing an 8-year interim period that begins in 2022 

and goes through 2029, and which is separated into three steps, 

2022-2024, 2025-2027, and 2028-2029, each associated with its 

own interim goal. Affected EGUs must meet each of the interim 

period step 1, 2, and 3 CO2 emission performance rates, or, 

following the emissions reduction trajectory designed by the 

state itself, must meet the equivalent statewide interim period 

goals, on average, that a state may establish over the 8-year 

period from 2022-2029. The CAA section 111(d) plan must include 

those specific requirements. Affected EGUs must also achieve the 

final CO2 performance rates or the equivalent statewide goal by 

2030 and maintain that level subsequently. This approach 

reflects adjustments to the timeframe over which reductions must 

be achieved that mirror the determination of the final BSER, 

which incorporates the phasing in of the BSER measures in 

keeping with the achievability of those measures. The agency 

believes that this approach to timing is reasonable and 

appropriate, is consistent with many of the comments we 

received, and will best support the optimization of overall CO2 

reductions, ratepayer affordability and electricity system 

reliability. 
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The EPA recognizes that successfully achieving reductions 

by 2022 will be facilitated by actions and investments that 

yield CO2 emission reductions prior to 2022. The final guidelines 

include provisions to encourage early actions. States will be 

able to take advantage of the impacts of early investments that 

occur prior to the beginning of a plan performance period. Under 

a mass-based plan, those impacts will be reflected in reductions 

in the reported CO2 emissions of affected EGUs during the plan 

performance period. Under a rate-based plan, states may 

recognize early actions implemented after 2012 by crediting MWh 

of electricity generation and savings that are achieved by those 

measures during the interim and final plan performance periods. 

This provision is discussed in section VIII.K of the preamble. 

 In addition, to encourage early investments in RE and 

demand-side EE, the EPA is establishing the CEIP. Through this 

program, detailed in section VIII.B of this preamble, states 

will have the opportunity to award allowances and ERCs to 

qualified providers that make early investments in RE, as well 

as in demand-side EE programs implemented in low-income 

communities. Those states that take advantage of this option 

will be eligible to receive from the EPA matching allowances or 

ERCs, up to a total for all states that represents the 

equivalent of 300 million short tons of CO2 emissions. 
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 The EPA will address design and implementation details of 

the CEIP in a subsequent action. Prior to doing so, the EPA will 

engage with states, utilities and other stakeholders to gather 

information regarding their interests and priorities with regard 

to implementation of the CEIP. 

 The CEIP can play an important role in supporting one of 

the critical policy benefits of this rule. The incentives and 

market signal generated by the CEIP can help sustain the 

momentum toward greater RE investment in the period between now 

and 2022 so as to offset any dampening effects that might be 

created by setting the period for mandatory reductions to begin 

to 2022, two years later than at proposal. 

(5) Community and environmental justice considerations. 

Climate change is an environmental justice issue. Lowincome communities and communities of color already overburdened 

by pollution are disproportionately affected by climate change 

and are less resilient than others to adapt to or recover from 

climate-change impacts. While this rule will provide broad 

benefits to communities across the nation by reducing GHG 

emissions, it will be particularly beneficial to populations 

that are disproportionately vulnerable to the impacts of climate 

change and air pollution. 
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Conventional pollutants emitted by power plants, such as 

particulate matter (PM), SO2, hazardous air pollutants (HAP), and 

nitrogen oxides (NOx), will also be reduced as the plants reduce 

their carbon emissions. These pollutants can have significant 

adverse local and regional health impacts. The EPA analyzed the 

communities in closest proximity to power plants and found that 

they include a higher percentage of communities of color and 

low-income communities than national averages. We thus expect an 

important co-benefit of this rule to be a reduction in the 

adverse health impacts of air pollution on these low-income 

communities and communities of color. We refer to these 

communities generally as “vulnerable” or “overburdened,” to 

denote those communities least resilient to the impacts of 

climate change and central to environmental justice 

considerations. 

While pollution will be cut from power plants overall, 

there may be some relatively small number of plants whose 

operation and corresponding emissions increase, as energy 

providers balance energy production across their fleets to 

comply with state plans. These plants are likely to be the 

highest-efficiency natural gas-fired units, which have 

correspondingly low carbon emissions and are also characterized 

by low emissions of the conventional pollutants that contribute 
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to adverse health effects in nearby communities and regionally. 

The EPA strongly encourages states to evaluate the effects of 

their plans on vulnerable communities and to take the steps 

necessary to ensure that all communities benefit from the 

implementation of this rule. In order to identify whether state 

plans are causing any adverse impacts on overburdened 

communities, mindful that substantial overall reductions, 

nevertheless, may be accompanied by potential localized 

increases, the EPA intends to perform an assessment of the 

implementation of this rule to determine whether it and other 

air quality rules are leading to improved air quality in all 

areas or whether there are localized impacts that need to be 

addressed. 

Effective engagement between states and affected 

communities is critical to the development of state plans. The 

EPA encourages states to identify communities that may be 

currently experiencing adverse, disproportionate impacts of 

climate change and air pollution, how state plan designs may 

affect them, and how to most effectively reach out to them. This 

final rule requires that states include in their initial 

submittals a description of how they engaged with vulnerable 

communities as they developed their initial submittals, as well 

as the means by which they intend to involve communities and 
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other stakeholders as they develop their final plans. The EPA 

will provide training and other resources for states and 

communities to facilitate meaningful engagement. 

In addition to the benefits for vulnerable communities from 

reducing climate change impacts and effects of conventional 

pollutant emissions, this rule will also help communities by 

moving the utility industry toward cleaner generation and 

greater energy efficiency. The federal government is committed 

to ensuring that all communities share in these benefits. 

The EPA also encourages states to consider how they may 

incorporate approaches already used by other states to help lowincome communities share in the investments in infrastructure, 

job creation, and other benefits that RE and demand-side 

EEprograms provide, have access to financial assistance 

programs, and minimize any adverse impacts that their plans 

could have on communities. To help support states in taking 

concrete actions that provide economic development, job and 

electricity bill-cutting benefits to low-income communities 

directly, the EPA has designed the CEIP specifically to target 

the incentives it creates on investments that benefit low-income 

communities. 

Community and environmental justice considerations are 

discussed further in section IX of this preamble. 
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(6) Addressing employment concerns. 

In addition, the EPA encourages states in designing their state 

plans to consider the effects of their plans on employment and 

overall economic development to assure that the opportunities 

for economic growth and jobs that the plans offer are realized. 

To the extent possible, states should try to assure that 

communities that can be expected to experience job losses can 

also take advantage of the opportunities for job growth or 

otherwise transition to healthy, sustainable economic growth. 

The President has proposed the POWER+ Plan to help communities 

impacted by power sector transition. The POWER+ planinvests in 

workers and jobs, addresses important legacy costs in coal 

country, and drives development of coal technology.15

Implementation of one key part of the POWER+ Plan, the 

Partnerships for Opportunity and Workforce and Economic 

Revitalization (POWER) initiative, has already begun. The POWER 

initiative specifically targets economic and workforce 

development assistance to communities affected by ongoing 

changes in the coal industry and the utility power sector.16

(7) Electric system reliability. 

 

15 https://www.whitehouse.gov/the-press-office/2015/03/27/factsheet-partnerships-opportunity-and-workforce-and-economicrevitaliz 

16 http://www.eda.gov/power/ 
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In no small part thanks to the comments we received and our 

extensive consultation with key agencies responsible for 

reliability, including FERC and DOE, among others, along with 

EPA’s longstanding principles in setting emission standards for 

the utility power sector, these guidelines reflect the paramount 

importance of ensuring electric system reliability. The input we 

received on this issue focused heavily on the extent of the 

reductions required at the beginning of the interim period, 

proposed as 2020. We are addressing these concerns in large part 

by moving the beginning of the period for mandatory reductions 

under the program from 2020 to 2022 and significantly adjusting 

the interim goals so that they provide a less abrupt initial 

reduction expectation. This, in turn, will provide states and 

utilities with a great deal more latitude in determining their 

emission reduction trajectories over the interim period. As a 

result, there will be more time for planning, consultation and 

decision making in the formulation of state plans and in EGUs’ 

choice of compliance strategies, all within the existing 

extensive structure of energy planning at the state and regional 

levels. These adjustments in the interim goals are supported by 

the information in the record concerning the time needed to 

develop and implement reductions under the BSER. In addition, 

the various forms of flexibility retained and enhanced in this 
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final rule, including opportunities for trading within and 

between states, and other multi-state compliance approaches, 

will further support electric system reliability. 

The final guidelines address electric system reliability in 

several additional important ways. Numerous commenters urged us 

to include, as part of the plan development or approval process, 

input from review by energy regulatory agencies and reliability 

entities. In the final rule, we are requiring that each state 

demonstrate in its final state plan submittal that it has 

considered reliability issues in developing its plan. Second, 

we recognize that issues may arise during the implementation of 

the guidelines that may warrant adjustments to a state’s plan in 

order to maintain electric system reliability. The final 

guidelines make clear that states have the ability to propose 

amendments to approved plans in the event that unanticipated and 

significant electric system reliability challenges arise and 

compel affected EGUs to generate at levels that conflict with 

their compliance obligations under those plans. 

As a final element of reliability assurance, the rule also 

provides for a reliability safety valve for individual sources 

where there is a conflict between the requirements the state 

plan imposes on a specific affected EGU and the maintenance of 

electric system reliability in the face of an extraordinary and 
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unanticipated event that presents substantial reliability 

concerns. 

We anticipate that these situations will be extremely rare 

because the states have the flexibility to craft requirements 

for their EGUs that will provide long averaging periods and/or 

compliance mechanisms, such as trading, whose inherent 

flexibility will make it unlikely that an individual unit will 

find itself in this kind of situation. As one example, under 

compliance regimes that allow individual EGUs to establish 

compliance through the acquisition and holding of allowances or 

ERCs equal to their emissions, an EGU’s need to continue to 

operate – and emit – for the purposes of ensuring system 

reliability will not put the EGU into non-compliance, provided, 

of course, it obtains the needed allowances or credits in a 

timely fashion. We, nevertheless, agree with many commenters 

that it is prudent to provide an electric system reliability 

safety valve as a precaution. 

Finally, the EPA, DOE and FERC have agreed to coordinate 

their efforts, at the federal level, to help ensure continued 

reliable electricity generation and transmission during the 

implementation of the final rule. The three agencies have set 

out a memorandum that reflects their joint understanding of how 

they will work together to monitor implementation, share 
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information, and to resolve any difficulties that may be 

encountered. 

As a result of the many features of this final rule that 

provide states and affected EGUs with meaningful time and 

decision making latitude, we believe that the comprehensive 

safeguards already in place in the U.S. to ensure electric 

system reliability will continue to operate effectively as 

affected EGUs reduce their CO2 emissions under this program. 

(8) Outreach and resources for stakeholders. 

 To provide states, U.S. territories, tribes, utilities, 

communities, and other interested stakeholders with 

understanding about the rule requirements, and to provide 

efficiencies where possible and reduce the cost and 

administrative burden, the EPA will continue to work with 

states, tribes, territories, and stakeholders to provide 

information and address questions about the final rule. Outreach 

will include opportunities for states and tribes to participate 

in briefings, teleconferences, and meetings about the final 

rule. The EPA’s ten regional offices will continue to be the 

entry point for states, tribes and territories to ask technical 

and policy questions. The agency will host (or partner with 

appropriate groups to co-host) a number of webinars about 

various components of the final rule; these webinars are planned 
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for the first two months after the final rule is issued. The EPA 

will also offer consultations with tribal governments. The EPA 

will continue outreach throughout the plan development and 

submittal process. The EPA will use information from this 

outreach process to inform the training and other tools that 

will be of most use to the state, tribes, and territories that 

are implementing the final rule. 

The EPA has worked with communities, states, tribes and 

relevant associations to develop an extensive training plan that 

will continue in the months after the Clean Power Plan is 

finalized. The EPA has assembled resources from a variety of 

sources to create a comprehensive training curriculum for those 

implementing this rule. Recorded presentations from the EPA, DOE 

and other federal entities will be available for communities, 

states, and others involved in composing and participating in 

the development of state plans. This curriculum is available 

online at EPA’s Air Pollution Training Institute. 

The EPA also expects to issue guidance on specific topics. 

As guidance documents, tools, templates and other resources 

become available, the EPA, in consultation with DOE and other 

federal agencies, will continue to make these resources 
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available via a dedicated website.17 

We intend to continue to work actively with states and 

tribes, as appropriate, to provide information and technical 

support that will be helpful to them in developing and 

implementing their plans. The EPA will engage in formal 

consultations with tribal governments and provide training 

tailored to the needs of tribes and tribal governments. 

Additional detail on aspects of the final rule is 

included in several technical support documents (TSDs) and 

memoranda that are available in the rulemaking docket. 

24. Key changes from proposal 

The a. Overview and highlights. As noted earlier in this 

overview, the June 2014 proposal for the rule was designed to 

meet the fundamental goal of reducing harmful emissions of CO2

from fossil fuel-fired EGUs in a manner consistent with the CAA 

requirements, while accommodating two important objectives. The 

first objective was to establish guidelines that reflect both 

the manner in which the power system operates and the actions 

and measures already underway across states and the utility 

power sector that are resulting in CO2 emission reductions. The 

second objective was to provide states and utilities maximum 

 

17 www.epa.gov/cleanpowerplantoolbox. 
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flexibility, control and choice in meeting their compliance 

obligations. In this final rule, the EPA has focused on changes 

that, in addition to being responsive to the critical concerns 

and priorities of stakeholders, more fully accomplish these two 

crucial objectives. 

To achieve these objectives, the June 2014 proposal 

featured several important elements: the building block approach 

for the BSER; state-specific, rather than source-specific,

goals; a 10-year interim goal that could be met “on average” 

over the 10-year period between 2020 and 2029; and a “portfolio” 

option for state plans. These features were intended either to 

capture, in the emission guidelines, emission reduction measures 

already in widespread use or to maximize the range of choices 

that states and utilities could select in order to achieve their 

emission limitations at low cost while ensuring electric system 

reliability. The state goals reflected an approach to the BSER 

that was intended to capture both the unique interconnected 

nature of the utility power sector and the set of actions, 

strategies and programs that are already under way at the state 

and utility level that have been resulting in CO2 emission 

reductions. They also reflected the fact thatIn this final rule, 

we are retaining the key design elements of the proposal and 

making certain adjustments to respond to a variety of very 
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constructive comments on ways that will implement the CAA 

section 111(d) requirements efficiently and effectively. 

The building block approach is a key feature of the 

proposal that we are retaining in the final rule, but have 

refined to include only the first three building blocks and to 

reflect implementation of the measures encompassed in the 

building blocks on a broad regional grid-level. In the proposal, 

we expressed the emission limitation requirements reflecting the 

BSER in terms of the state goals in order to provide states with 

maximum flexibility and latitude. We viewed this as an important 

feature because each state has its own energy profile and statespecific policies and needs relative to the production and use 

of electricity. The final guidelines continue to embrace this 

basic approach, but they also incorporate significant changes 

that respond directly to the comments, requests and concerns of 

states and other stakeholders, while better serving the critical 

objectives of the basic approach of the proposalIn the final 

rule, we extend that flexibility significantly in direct 

response to comments from states and utilities. The final rule 

establishes source-level emission performance rates for the 

source subcategories, while retaining state-level rate- and 

mass-based goals. One of the key messages conveyed by state and 

utility commenters was that the final rule should make it easier 
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for states to adopt mass-based programs and for utilities 

accustomed to operating across broad multi-state grids to be 

able to avail themselves of more “ready-made” emissions trading 

regimes. The inclusion of both of these new features – massbased state goals in addition to rate-based goals, and sourcelevel emission performance rates for the two subcategories of 

sources – is intended to make it easier for states and utilities 

to achieve these outcomes. In fact, these additions, together 

with the model rules and federal plan being proposed 

concurrently with this rule, should demonstrate the relative 

ease with which states can adopt mass-based trading programs, 

including interstate mass-based programs that lend themselves to 

the kind of interstate compliance strategies so well suited for 

integration with the current interstate operations of the 

overall utility grid. 

Together with the proposal, thisMany stakeholders conveyed 

to the EPA that the proposal’s interim goals for the 2020-2029 

period were designed in a way that defeated the EPA’s objective 

of allowing states and utilities to shape their emission 

reduction trajectories. They pointed out that, in many cases, 

the timing and stringency of the states’ interim goals could 

require actions that could result in high costs, threaten 

electric system reliability or hinder the deployment of 
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renewable technology. In response, the EPA has revised the 

interim goals in two critical ways. First, the period for 

mandatory reductions begin in 2022 rather than 2020; second, in 

keeping with the BSER, emission reduction requirements are 

phased in more gradually over the interim period. These changes 

will allow states and utilities to delineate their own emission 

reduction trajectories so as to minimize costs and foster 

broader deployment of RE technologies. The value of these 

changes is demonstrated by our analysis of the final rule, which 

shows lower program costs, especially in the early years of the 

interim period, and greater RE deployment, relative to the 

analysis of the proposed rule. At the same time, this re-design 

of the interim goals, together with refinements we have made to 

state plan requirements and the inclusion of a reliability 

safety valve, provide states, utilities and other entities with 

the ability to continue to guarantee system reliability. 

b. Outreach, engagement and comment record. This final rule is 

the product of one of the most extensive and long-running public 

engagement processes the EPA has ever conducted, starting in the 

summer of 2013, prior to proposal, and continuing through 

December 2014, when the public comment period ended, and 

resulting incontinuing beyond that with consultations and 

meetings with stakeholders. The result of this extensive 
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consultation was millions of comments from stakeholders, which 

we have carefully considered over the past several months. The 

EPA gained crucial insights from the more than 4 million 

comments that the agency received on the proposal and on notices 

leading to this final rulemaking, from. Comments were provided 

by stakeholders that include state environmental and energy 

officials, tribal officials, public utility commissioners, 

system operators, utility andowners and operators of every type 

of power generating facility, other industry representatives, 

labor leaders, public health leaders, public interest advocates, 

community and faith leaders, and members of the public. As a 

result, these 

The insights gained from public comments contributed to the 

development of final emission guidelines reflect changes from 

that build on the proposal that and the alternatives on which we 

sought comment. The modifications incorporated in the final 

guidelines are directly responsive to the comments we received 

from the many and diverse stakeholders. These finalThe improved

guidelines bear the stamp of thereflect information and input 

the EPA gleaned from its extensive outreach process and from the 

comment record. The guidelines reflect thinking and 

informationideas that states and utilities provided to us about 

both the best approach to establishing CO2 emission reduction 
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requirements for EGUs and the most effective ways to create true 

flexibility for states and utilities in meeting these 

requirements. These final rules also reflect the results of 

EPA’s robust and ongoing consultation with federal, state and 

regional energy agencies and authorities, to ensure that the 

actions sources will take to reduce GHG emissions will not 

compromise electric system reliability or affordability of the 

U.S. electricity supply. Input and assistance from FERC and DOE 

have been particularly important in shaping some provisions in 

these final guidelines. At the same time, input from faithbased, community-based and environmental justice organizations, 

who provided thoughtful comments about the potential impacts of 

this rule on pollution levels in overburdened communities and 

economic impacts, including utility rates in low-income 

communities, is also reflected in this rule. The final rule also 

reflects our response to concerns raised by labor leaders 

regarding the potential effects on workers and communities of 

the transition away from higher-emitting power generation to 

lower- and zero-emitting power generation.

At proposal, the EPA made it clear that our intent was twofold – first, to establish CO2 emission reduction requirements 

that relied both on the distinctive nature of the electricity 

system in which affected EGUs operate and on the actions, 
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strategies and policies states and utilities have already been 

undertaking, and, second, to provide states and utilities with 

broad flexibility and choice in meeting those requirements in 

order to minimize costs to ratepayers and to ensure the 

reliability of electricity supply. Thus, in our thorough 

examination of the comment record and of information received 

during the engagement process, we paid particular attention to 

information and suggestions that addressed ways to ensure that 

this final rule succeeds in fulfilling the dual objectives of 

the proposal. 

b.c. Key changes. The resultingmost significant changes in these 

final guidelines are highlighted by: 1) a new start date of 2022 

for the interim the period, 2) for mandatory emission reductions 

beginning in 2022 instead of 2020 and a gradual application of 

the BSER over the 2022-2029 interim period, such that a state 

has substantial latitude in selecting its own emission reduction 

trajectory or “glide path” over that period, 3) the2) a revised

BSER being derived fromdetermination that focuses on narrower

generation options only andthat do not frominclude demand-side 

energy efficiencies, 4) efficiency measures and that includes 

refinements to the building blocks, more complete incorporation 

in the BSER reflectingof the realities of electricity operations 

over the three regional Interconnections, as well as 
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interconnections, and up-to-date information about the cost and 

availability of clean generation options, including reflecting 

the fact that new NGCC is also a clean generation option, 5) a 

combination of provisions expressly designed to address electric 

system reliability, 6)3) establishment of source-specific CO2

emission performance rates that are uniform across the two 

fossil fuel-fired source categoriessubcategories covered in 

these guidelines, 7) additional, more flexible options for 

states and utilities to adopt multi-state compliance strategies, 

8) an extension of up to two years for all states to submit 

their final compliance plans following submittal of an initial 

plan in 2016 and 9as well as rate- and mass-based state goals, 

to facilitate emission trading, including interstate trading 

and, in particular, mass-based trading, 4) a variation on the 

proposal’s “portfolio” option for state plans – called here the 

“state measures” approach - that offers the same 

optionscontinues to provide states flexibility while ensuring 

that all state plans have federally enforceable measures as a 

backstop, 5) additional, more flexible options for states and 

utilities to adopt multi-state compliance strategies, 6) an 

extension of up to two years available to all states for 

submittal of their final compliance plans following making 

initial submittals in 2016, 7) provisions to encourage actions 
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that achieve early reductions, including a Clean Energy 

Incentive Program, 8) a combination of provisions expressly 

designed to ensure electric system reliability, 9) the addition 

of employment considerations for states but with a firmer legal 

foundation. in plan development, and 10) the expansion of 

considerations and programs for low-income and vulnerable 

communities. 

This suite of changes is the product of compelling 

information and analysis provided to the EPA via the comment 

record – and by the work of, and consultation with, other 

federal agencies, notably the Federal Energy Regulatory 

Commission (FERC) and the U.S. Department of Energy (DOE).We 

provide summary explanations in the following paragraphs and 

more detailed explanations of all of these changes in later 

sections of this preamble and associated documents. 

(1) Mandatory Reduction Period Beginning in 2022 and a 

Gradual Glide Path. 

The proposal’s mandatory emission reduction period 

beginning in 2020 and the trajectory of emission reduction 

requirements in the interim period were both the subjects of 

significant comment. Earlier this year, FERC conducted a series 

of technical conferences comprising one national session and 

three regional sessions. The information provided by workshop 
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participants echoed much of the material that had been submitted 

to the comment record for this rulemaking. On May 15, 2015, the 

FERC Commissioners, drawing upon information highlighted at the 

technical conferences, transmitted to the EPA some suggestions 

for the final rule. In addition, via comments, states, 

utilities, and reliability entities asked us to ensure adequate 

time for states, utilities, and grid operatorsthem to implement 

strategies to achieve CO2 reductions. They expressed concern 

that, in the proposal, at least some states werewould be

required to reduce emissions in 2020 to levels that would 

require abrupt shifts in generation in ways that raised concerns 

about impacts to electric system reliability, and ratepayer 

bills, and as well as about stranded assets. To many commenters, 

the proposal’s 2020 start daterequirement for achieving CO2

emission reductions beginning in 2020, together with the 

stringency of the interim CO2 goal, boreposed significant 

reliability implications, in particular. In this final rule, the 

agency is addressing these concerns, in part, by adjusting the 

compliance timeframe from a 10-year interim period that begins 

in 2020 to an 8-year interim period that begins in 2022, and by 

refining the approach for meeting interim CO2 emission 

performance rates (ato be a gradual glide path separated into 

three steps, 2022-2024, 2025-2027, and 2028-2029, andthat is
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also achievable “on average” over the 8-year interim period)..

In response to the concerns of commenters that the proposal’s 

10-year interim target failed to afford sufficient flexibility, 

the final guidelines’ approach will provide states with 

realistic options for customizing their emission reduction 

trajectories. Of equal importance, the approach provides more 

time for planning, consultation and decision making in the 

formulation of state plans and in EGUs’ choices of compliance 

strategies. Both FERC’s May 15, 2015 letter and the comment 

record, as well as other information sources, made it clear that 

providing sufficient time for planning and implementation was 

essential to ensuring electric system reliability. 

The final guidelines’ “step-down” approach to the interim 

emission performance rates is the result of the application of 

the measures constituting the BSER in a more gradual way, 

reflecting stakeholder comments and information about the 

appropriate period of time over which those measures can be 

deployed consistent with the BSER factors of cost and 

feasibility. In addition to facilitating reliability 

assurancereliable system operations, these changes provide 

states and utilities with the latitude to consider a broader 

range of options to achieve the required reductions while 

addressing concerns about ratepayer impacts and stranded assets.
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(2) Revised BSER determination. 

Commenters urged the EPA to confine its BSER determination 

to actions that involve what they characterized as more 

“traditional” generation. In response,While some stakeholders 

recognized demand-side EE as being an integral part of the 

electricity system, with many of the characteristics of more 

traditional generating resources, other stakeholders did not. As 

explained in section V.B.3.c.(8) below, our traditional 

interpretation and implementation of CAA section 111 has allowed 

regulated entities to produce as much of a particular good as 

they desire, provided that they do so through an appropriately 

clean (or low-emitting) process. While building blocks 1, 2, and 

3 fall squarely within this paradigm, the proposed building 

block 4 does not. In view of this, since the BSER must serve as 

the foundation of the emission guidelines, the EPA has not 

included demand-side EE as part of the final BSER determination. 

Thus, neither the final guidelines’ BSER determination does not 

take into account demand-side energy efficiency (EE), and nor 

the emission performance rates for each of the two source 

categories do not reflectsubcategories of affected EGUs take 

into account demand-side EE. However, many commenters also urged 

the EPA to allow states and sources to rely on demand-side EE as 

an element of their compliance strategies, as demand-side EE is 
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treated as functionally interchangeable with other forms of 

generation for planning and operational purposes, as energy 

efficiency measures are in widespread use across the country and 

provide energy savings that reduce emissions, lower electric 

bills, and lead to positive investments and job creation. We 

agree, and the final guidelines provide ample latitude for 

states and utilities to rely on demand-side EE in meeting 

emission reduction requirements. 

In response to stakeholder comments on the first three 

building blocks and considerable data in the record, the EPA has 

made refinements to the building blocks, and these are reflected 

in the final BSER. Refinements include adoption of a modified 

approach to quantification of the RE component, exclusion of the 

proposed nuclear generation components, and adoption of a 

consistent regionalized approach to quantification of all three 

building blocks. The agency also recognizes the important 

functional relationship between the period of time over which 

measures are deployed and the stringency of emission limitations 

those measures can achieve practically and at reasonable cost. 

Therefore, the final BSER also reflects adjustments to the 

stringency of the building blocks, after consideration of more 

and less stringent levels, and refinements to the timeframe over 

which reductions must be achieved. Since commentersSections V.C 
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through V.E of this preamble provide further information on the 

refinements made to the building blocks and the rationale for 

doing so. 

Commenters pointed out – and practical experience confirms 

– what is widely known: that the utility power sector operates 

over regional interconnections that are not constrained by state 

borders. Across a variety of issues raised in the proposal, many 

commenters urged that the EPA take that reality into account in 

developing this final rule. Consequently, the BSER 

determination itself (as well as a number of new compliance 

features included in this final rule) and the resulting source 

categorysubcategory-specific emission performance rates take 

into account that reality. the grid-level operations of the 

source category. 

The final guidelines’ BSER determination also takes into 

account recent reductions in the cost of clean energy 

technology, as well as projections of continuing cost 

reductions. With a revised start date for emission reductions of 

2022, instead of 2020, as proposed, the, and continuing 

increases in RE deployment. We also updated the underlying 

analysis with the most recent Energy Information Administration 

(EIA) projections that show lower growth in electricity demand 

between 2020 and 2030 than previously projected. In keeping with 
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these recent EIA projections, we expect the final guidelines 

will be more conducive to compliance, consistent with a strategy 

that allows for the cleanest power generation and greater CO2

reductions in 2030 than the proposal. With a date of 2022, 

instead of 2020, as proposed, for the mandatory CO2 emission 

reduction period to begin, the final guidelines reflect that the 

additional time aligns with the adoption of lower-cost clean 

technology and, thus, its incorporation in the BSER at higher 

levels. At the same time, the 2022-2029 interim period will more 

easily allow for companies to take advantage of improved clean 

energy technologies as potential least cost options. 

The EPA’s decision to exclude demand-side EE from its BSER 

determination responds to numerous stakeholders’ request that 

the agency not base the final emission guidelines on requiring 

that utilities produce less generation. After consideration of 

these comments and extensive comments on a range of topics 

related to the best system of emission reduction (BSER), the 

agency has revised its determination of the BSER. In this final 

action, the agency has determined that the BSER comprises the 

first three of the four proposed building blocks identified at 

proposal, with certain refinements to the three building blocks. 

(3) Commenters pointed outUniform Emission Performance 

Rates. 
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Some stakeholders commented that the proposal’s approach of 

expressing the BSER in terms of state-specific goals deviated 

from the requirements of CAA section 111 and from all previous 

new source performance standards (NSPS). The effect, they 

observedstated, was that the proposal’sproposal created de facto 

emission standards for the same sources were not uniform,all 

affected EGUs but that these de facto standards varied 

inappropriately from state to state,widely depending on what 

each state’s goal was. Manythe state in which a given EGU 

happened to be located. Instead, these and other commenters also 

pointed outstated, section 111 requires that the EPA must

establish the BSER specifically for affected sources, rather 

than by means of merely setting state-specific goals. In 

response to these and similar comments, the final guidelines 

express the BSER by establishing performance-based CO2 emission 

rates that are uniform across each of two source categories – 

fossil fuel-fired electric steam generating units and stationary 

combustion turbines – for the affected EGUs covered by the 

guidelines. We cannot emphasize enough that, while the final 

guidelines now take a source-specific approach in setting CO2

emission performance rates, this does not change the fact that 

each state’s goal is tailored to its particular sources, and it 

in no way alters or curtails the flexibility inherent in the 
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proposal’s state-specific goals approach, which the final 

guidelines retain (and, as discussed in Section VIII of this 

preamble, enhance in various ways). Thus, to maintain the 

proposal’s flexibility for states, the guidelines continue to 

define state planning and implementation obligations through 

state-level goals, which we have calculated by translating the 

source category-specific CO2 emission performance rates into 

equivalent statewide rate-based and mass-based CO2 goals, and 

that these standards be uniform. Still other commenters observed 

that the effect of the approach taken in the proposal of 

applying the BSER to each state’s fleet was to put a greater 

burden of reductions on lower-emitting or less carbon-intensive 

states and a lesser emission reduction burden on sources and 

states that were higher-emitting or more carbon-intensive. This, 

they argued, was both inequitable and at odds with the way in 

which NSPS have been applied in the past, where the higheremitting sources have made the greater and more cost-effective 

reductions, while lower-emitting sources, whose reduction 

opportunities tend to be less cost-effective, have been required 

to make fewer reductions to meet the applicable standard. 

ForAt the same time, state plan approaches included at 

proposal,and utility commenters expressed concern that relying 

on state-specific goals and state-by-state planning could 
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introduce complexity into the otherwise seamless integrated 

operation of affected EGUs across the multi-state grids on which 

system operators, states and utilities currently rely and intend 

to continue to rely. Accordingly, they recommended that the 

final guidelines facilitate emissions trading, in particular 

interstate trading, which would enable EGU operators to 

integrate compliance with CO2 emissions limitations with facility 

and grid-level operations. These sets of comments intersected at 

the point at which they focused on the fact that it is at the 

source level at which the standard is set for NSPS and at the 

source level at which compliance must be achieved. 

The EPA carefully considered these comments and while we 

believe that the approach we took at proposal was well-founded 

and reflected a number of important considerations, we have 

concluded that there is a way to address these concerns while 

expanding upon the advantages offered by the proposal. 

Accordingly, the final guidelines establish uniform rates for 

the two subcategories of sources – an approach that is valuable 

for creating greater equity between and among utilities and 

states with widely varying emission levels and for expanding the 

flexibility of the program, especially in ways that have been 

identified as important to utilities and states. Specifically, 

the final guidelines express the BSER by means of performance-
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based CO2 emission rates that are uniform across each of two 

subcategories – fossil fuel-fired electric steam generating 

units and stationary combustion turbines – for the affected EGUs 

covered by the guidelines. The rates are determined, in part, by 

applying the methodology identified in the Notice of Data 

Availability published on October 30, 2014, which was based on 

the proposal’s building block approach. The final guidelines 

also maintain the approach adopted in the proposal of 

establishing state-level goals; in the final rule, those goals 

are equal to the weighted aggregate of the two emission 

performance rates as applied to the EGUs in each state. 

This approach rectifies what would have been an 

inefficient, unintended outcome of putting the greater reduction 

burden on lower-emitting sources and states while exempting 

higher-emitting sources and states. Expressing the BSER by means 

of these rates also augments the range of options for both 

states and EGUs for securing needed flexibility. Inclusion of 

state goals creates latitude for states as to how they will meet 

the guidelines. States also may meet the guideline requirements 

by adopting the CO2 emission performance rates as emission 

standards that apply to the affected EGUs in their jurisdiction. 

Such an approach would lend itself to the ready establishment of 

intra-state and interstate trading, with the uniform rate-based 
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standards of performance established for each EGU as the basis 

for such trading. At the same time, as at proposal, each state 

also has the option of complying with these guidelines by 

adopting a plan that takes a different approach to setting 

standards of performance for its EGUs and/or by applying 

complementary or alternative measures to meet the state goal set 

by these guidelines – as either a rate or a mass total. 

During the outreach process and through comments, a number 

of state officials and other stakeholders expressed concern that 

the EPA’s approach at proposal necessitated or represented a 

significant intrusion into state-level energy policy-making, 

drawing the EPA well beyond the bounds of its CAA authority and 

expertise. In fact, these final guidelines are entirely 

respectful of the EPA’s responsibility and authority to regulate 

sources of air pollution. Instead, by establishing and operating 

through uniform performance rates for the two subcategories of 

sources that can be applied by states at the individual source 

level and that can readily be implemented through emission 

standards that incorporate emissions trading, these final 

guidelines align with the approach Congress and the EPA have 

consistently taken to regulating emissions from this and other 

industrial sectors, namely setting source-level, source 
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category-wide standards that individual sources can meet through 

a variety of technologies and measures. 

We emphasize, at the same time, that while the final 

guidelines express the BSER by means of source-level CO2 emission 

performance rates, as well as state-level goals, as at proposal, 

each state will have a goal reflecting its particular mix of 

sources, and the final guidelines retain the flexibility 

inherent in the proposal’s state-specific goals approach (and, 

as discussed in section VIII of this preamble, enhanced in 

various ways). Thus, in keeping with the proposal’s flexibility, 

states may choose to adopt either the emission performance rates 

as emission standards for their sources, set different but, in 

the aggregate, equivalent rates, or fulfill their obligations by 

meeting their respective individual state goals. 

(4) State Plan Approaches. 

Commenters expressed support for the objectives served by 

the “portfolio” option but alsoin the state plan approaches 

included at proposal, but many raised concerns about its 

legality, with respect, in particular, to the Clean Air Act’s 

enforceability requirements. Some of these commenters identified 

a “state commitment approach” with backstop measures as an 

option for state plansa variation of the “portfolio” approach

that would retain the benefits of the “portfolio” approach while 
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resolving legal and enforceability concerns. In this final rule, 

in response to stakeholder comments on the portfolio approach 

and alternative approaches, the EPA is finalizing two 

approaches, a source-based “emission standards” approach, and a 

“state measures” approach that requires the inclusion of. 

Through the latter, states may adopt a set of policies and 

programs, which would not be federally enforceable, except that 

any standards imposed on affected EGUs would be federally 

enforceable. In addition, states would be required to include 

federally enforceable backstop measures. As in the proposal, in 

order to comply with these guidelines, states will have to 

ensure that implementation of the emission standards established 

for their affected EGUs, either individually, in aggregate, or 

in combination with applicable to each affected EGU in the 

event that the measures included in the state plan failed to 

achieve the state plan’s emissions reduction trajectory. Under 

these guidelines, then, states can implement the BSER through 

standards of performance incorporating the uniform performance 

rates or alternative but in the aggregate equivalent rates, or 

they can adopt plans that achieve in aggregate the equivalent of 

the subcategory-specific CO2 emission performance rates by 

relying on other measures undertaken by the state, achieves the 

equivalent of the that complement source category-specific CO2
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emission performance ratesrequirements or, save for the 

contingent backstop requirement, supplant them entirely. This 

revision provides consistency in the treatment of sources while 

still tailoring required CO2 reductions to individual 

states.providing maximum flexibility for states to design their 

plans around reduction approaches that best suit their policy 

objectives.

(5) Emission Trading Programs. 

Many state and utility commenters supported the use of 

mass-based and rate-based emission trading programs in state 

plans, including interstate emission trading programs. The EPA 

also received a number of comments from states and stakeholders 

about the value of EPA support in developing and/or 

administering, and either pointed out obstacles to establishing 

such programs or suggested approaches that would enhance states’ 

and utilities’ ability to create and participate in such 

programs. 

Through a combination of features retained from the 

proposal and changes made to the proposal, these final 

guidelines provide states and utilities with a panoply of tools 

that greatly facilitate their putting in place and participating 

in emissions trading programs. These include: 1) expressing BSER 

in uniform emission performance rates that states may rely on in 
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setting emission standards for affected EGUs such that EGUs 

operating under such standards readily qualify to trade with 

affected EGUs in states that adopt the same approach, 2) 

promulgating state mass goals so that states can move quickly to 

establish mass-based programs such that their affected EGUs 

readily qualify to trade with affected EGUs in states that adopt 

the same approach, and 3) providing EPA resources and capacity 

to create a tracking systems to support state administration of 

rate-based and mass-based emission trading programs. In this 

final rule, as we proposed, states may use trading or other 

multi-unit compliance approaches and technologies or strategies 

that are not explicitly mentioned in any of the three building 

blocks as part of their overall plans, as long as they achieve 

the required emission reductions from affected fossil fuel-fired 

EUGs. In addition, in response to concerns from states and power 

companies that the need for up-front interstate cooperation in 

developing multi-state plans could inhibit the development of 

interstate programs that could lower cost, the final rule 

provides additional options to allow individual EGUs to use 

creditable out-of-state reductions to achieve required CO2

reductions, without the need for up-front interstate agreements. 

The EPA is committed to working with states to provide support 

for tracking of emissions and allowances or credits, to help 
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implement multi-state trading or other multi-unit compliance 

approaches.system to support state emissions trading programs. 

(6) Extension of Plan Submittal Date. 

Stakeholders, particularly states, provided compelling 

information establishing that it willcould take longer than the 

agency initially anticipated for the states to develop and 

submit their required plans. While the approach at proposal 

reflected the EPA’s conclusion that it was essential to the 

environmental and economic purposes of this rulemaking that 

utilities and states establish the path towards emissions 

reductions as early as possible, we fully recognize commenters’ 

concerns. To strike the proper balance, the EPA has developed a 

revised state plan submittal schedule. TheFor states that cannot 

submit a final plan by September 6, 2016, the EPA is requiring 

those states to submitmake an initial plan 13 months after 

signature (by August 31, 2016),submittal by that date to assure 

that states begin to address the urgent needs for reductions 

quickly, and is providing until August 31September 6, 2018, for 

states to submit a final plan, if an extension until that date 

is justified, to address the concern that a submitting state 

needs more time to develop comprehensive plans that reflect the 

full range of the state’s and its stakeholders’ interests. 

(7) Provisions to Encourage Early Action. 
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 Many commenters supported providing incentives for states 

and utilities to deploy CO2-reducing investments, such as RE and 

demand-side EE measures, as early as possible. We also received 

comments from stakeholders regarding the disproportionate 

burdens that some communities already bear, and stating that all 

communities should have equal access to the benefits of clean 

and affordable energy. The EPA recognizes the validity and 

importance of these perspectives, and as a result has determined 

to provide a program – called the Clean Energy Incentive Program 

(CEIP) – in which states may choose to participate. 

 The CEIP is designed to incentivize investment in certain 

RE and demand-side EE projects that commence construction, in 

the case of RE, or commence construction, in the case of demandside EE, following the submission of a final state plan to the 

EPA, or after September 6, 2018, for states that choose not to 

submit a final state plan by that date, and that generate MWh 

(RE) or reduce end-use energy demand (EE) during 2020 and/or 

2021. State participation in the program is optional. 

 Under the CEIP, a state may set aside allowances from the 

CO2 emission budget it establishes for the interim plan 

performance period or may generate early action emission rate 

credits (ERCs)(ERCs are discussed in more detail in section 

VIII.K.2), and allocate these allowances or ERCs to eligible 
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projects for the MWh those projects generate or the end-use 

energy savings they achieve in 2020 and/or 2021. For each early 

action allowance or ERC a state allocates to such projects, the 

EPA will provide the state with an appropriate number of 

matching allowances or ERCs for the state to allocate to the 

project. The EPA will match state-issued early action ERCs and 

allowances up to an amount that represents the equivalent of 300 

million short tons of CO2 emissions. 

 For a state to be eligible for a matching award of 

allowances or ERCs from the EPA, it must demonstrate that it 

will award allowances or ERCs only to “eligible” projects. These 

are projects that: 

 Are located in or benefit a state that has submitted a 

final state plan that includes requirements establishing 

its participation in the CEIP; 

 Are implemented following the submission of a final state 

plan to the EPA, or after September 6, 2018, for a state 

that chooses not to submit a complete state plan by that 

date; 

 For RE: Generate metered MWh from any type of wind or solar 

resources; 

 For EE: Result in quantified and verified electricity 

savings (MWh) through demand-side EE implemented in low-
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income communities; and 

 Generate or save MWh in 2020 and/or 2021. 

 The following provisions outline how a state may award 

early action ERCs and allowances to eligible projects, and how 

the EPA will provide matching ERCs or allowances to states. 

 For RE projects that generate metered MWh from any type of 

wind or solar resources: for every two MWh generated, the 

project will receive one early action ERC (or the 

equivalent number of allowances) from the state, and the 

EPA will provide one matching ERC (or the equivalent number 

of allowances) to the state to award to the project. 

 For EE projects implemented low-income communities: for 

every two MWh in end-use demand savings achieved, the 

project will receive two early action ERCs (or the 

equivalent number of allowances) from the state, and the 

EPA will provide two matching ERCs (or the equivalent 

number of allowances) to the state to award to the project. 

 Early action allowances or ERCs awarded by the state, and 

matching allowances or ERCs awarded by the EPA pursuant to the 

CEIP, may be used for compliance by an affected EGU with its 

emission standards and are fully transferrable prior to such 

use. 

 The EPA discusses the CEIP in the proposed federal plan 
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rule and will address design and implementation details of the 

CEIP in a subsequent action. Prior to doing so, the EPA will 

engage with states, utilities and other stakeholders to gather 

information regarding their interests and priorities with regard 

to implementation of the CEIP. 

(8) Provisions for Electric System Reliability. 

A number of commenters stressed the importance of final 

guidelines that addressed the need to ensure that the program 

would notEGUs could meet their emission reduction requirements 

without being compelled to take actions that would undermine 

electric system reliability. As noted above, the EPA has 

consulted extensively with federal, regional and state energy 

agencies, utilities and many others about reliability concerns 

and ways to address them. Many aspects of the final rule’s 

design are intended to support electric system reliability. In 

addition to not requiring reductions before 2022 and to allowing 

significant flexibility in how the CO2 emission performance rates 

or the statewide CO2 goals are met, we are requiring that states 

demonstrate that they have considered reliability in developing 

their state plans and have consulted with state utility agencies 

and/or regional planning authorities. These final guidelines 

further provide states with the option of proposing amendments 

to approvedThe final guidelines support electric system 
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reliability in a number of ways, some inherent in the 

improvements made in the program’s design and some through 

specific provisions we have included in the final rule. Most 

important are the two key changes we made to the interim goal: 

establishing 2022, instead of 2020, as the period for mandatory 

emission reductions begin and phasing in, over the eight-year 

period, emission performance rates such that the level of 

stringency of the emission performance rates in 2022-2024 is 

significantly less than that for the years 2028 and 2029. Since 

states and utilities need only to meet their interim goal “on 

average” over the 8-year period, these changes provide them with 

a great deal of latitude in determining for themselves their 

emission reduction trajectory – and they have additional time to 

do so. As a result, the final guidelines provide the ingredients 

that commenters, reliability entities and expert agencies told 

the EPA were essential to ensuring electric system reliability: 

time and flexibility sufficient to allow for planning, 

implementation and the integration of actions needed to address 

reliability while achieving the required emissions reductions. 

In addition, the final guidelines add a requirement, based 

on substantial input from experts in the energy field, for 

states to demonstrate that they have considered electric system 

reliability in developing their state plans. The final rule also 
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offers additional opportunities that support electric system 

reliability, including opportunities for trading within and 

between states. The final guidelines also make clear that states 

can adjust their plans in the event that reliability challenges 

arise that need to be remedied by amending the state plan. TheIn 

addition, the final rule also includes a reliability safety 

valve to address situations where, because of an unanticipated 

catastrophic event, there is a conflict between the requirements 

imposed on an affected unit and the maintenance of reliability. 

The final rule also retains flexibilities presented in the 

proposal and offers additional opportunities, including 

opportunities for trading within and between states, and other 

multi-state compliance approaches that will further support 

electric system reliability. 

Stakeholders requested(9) Approaches for Addressing 

Employment Concerns. 

Some commenters brought to our attention the concerns of 

workers, their families and communities, particularly in coalproducing regions and states, that the program not impose 

ongoing shift toward lower-carbon electricity generation that 

the final rule reflects will cause harm to communities that are 

dependent on coal. Others had concerns about whether new jobs 

created as a result of actions taken pursuant to the final rule 
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will allow for overall economic development. In the final rule, 

the EPA encourages states, in designing their state plans, to 

consider the effects of their plans on employment and overall 

economic development to assure that the opportunities for 

economic growth and jobs that the plans offer are manifest. We 

also identify federal programs, including the multi-agency 

Partnerships for Opportunity and Workforce and Economic 

Revitalization (POWER) Initiative.18 The POWER Initiative is 

competitively awarding planning assistance and implementation 

grants with funding from the Department of Commerce, Department 

of Labor (DOL), Small Business Administration, and the 

Appalachian Regional Commission,19 whose mission is to assist 

communities affected by changes in the coal industry and the 

utility power sector. 

(10) Community and Environmental Justice Considerations. 

Many community leaders, environmental justice advocates, 

faith-based organizations and others commented that the benefits 

of this rule must be shared broadly across society and that 

undue burdens should not be imposed on low-income ratepayers. We 

share this concern, and the final rule We agree. The federal 

 

18 http://www.eda.gov/power/.

19 https://www.whitehouse.gov/the-press-office/2015/03/27/factsheet-partnerships-opportunity-and-workforce-and-economicrevitaliz. 
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government is taking significant steps to help low-income 

families and individuals gain access to RE and demand-side EE 

through new initiatives involving, for example, increasing solar 

energy systems in federally subsidized homes and supporting 

solar systems for others with low incomes. The final rule 

ensures that bill-lowering measures such as demand-side EE 

continue to be a major compliance option. The Clean Energy 

Incentive Program (CEIP) will encourage early investment in 

these types of projects as well. In addition, to ensure 

opportunities for communities, particularly citizens who could 

be impacted by decisions, to continue to participate in decision 

making to carbon reduction benefits, we are taking steps to 

ensure that states are actively engaging with communities as 

part of their public participation process in the formulation of 

state plans. We note that, given the substantial reductions in a 

range of air pollutants, in addition to GHGs, that will occur 

along with the GHG reductions, this rule will result in expect 

significant near- and long-term public health benefits in 

communities in addition to the longer term benefits resulting 

from the reductions in GHGs.as conventional air pollutants are 

reduced along with GHGs. However, some stakeholders expressed 

concerns about the possibility of localized increases in 

emissions from some power plants as the utility industry 
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complies with state plans, in particular in communities already 

disproportionately affected by air pollution. This rule sets 

expectations for states to engage with vulnerable communities as 

they develop their plans, so that impacts on these communities 

are considered as plans are designed. The EPA also encourages 

states to engage with workers in the utility power and related 

sectors, as well as their worker representatives, so that 

impacts on their communities may be considered. The EPA commits, 

once implementation is under way, to assess the impacts of this 

rule. Likewise, we encourage states to evaluate the effects of 

their plans to ensure that there are no disproportionate adverse 

impacts on their communities. 

In their comments, many states identified the need for the 

EPA to maintain regular contact/forums with states throughout 

the implementation process and to provide guidance, including 

guidance on RE and EE emission measurement and verification 

(EM&V). To provide state and local governments and other 

stakeholders, including communities, with an understanding of 

the rule requirements, and to provide efficiencies where 

possible and reduce the cost and administrative burden, the EPA 

will continue outreach throughout the plan development and 

submittal process. Outreach will include opportunities for 

states to participate in briefings, teleconferences, and 
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meetings about the final rule. The EPA’s 10 regional offices 

will continue to be the entry point for states, tribes and 

territories to raise technical and policy questions. The agency 

will host or co-host a number of webinars about various 

components of the final rule currently planned for the first two 

months after the final rule is issued. The EPA will use 

information from this outreach process to inform the training 

and other tools that will be of most use to the states, tribes, 

and territories that are implementing the final rule, and also 

to inform the training for citizens, including members of 

communities that could be impacted, to support their 

participation in the state plan development process. The EPA 

also expects to issue guidance on specific topics. As guidance 

documents, tools, templates and other resources become 

available, the EPA, in consultation with the U.S. Department of 

Energy and other federal agencies, will continue to make these 

resources available via a dedicated website. 

3. Context for this rulemaking 

5. Additional context for this final rule 

a. Climate change impacts. This final rule is an important step 

toward achieving in an essential series of long-term actions 

that are achieving and must continue to achieve the GHG emission 

reductions needed to address the serious threat of climate 
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change, and constitutes a major commitment – and international 

leadership-by-doing – on the part of the U.S., one of the 

world’s largest GHG emitters. GHG pollution threatens the 

American public by leading to damaging and long-lasting changes 

in our climate that can have a range of severe negative effects 

on human health and the environment. CO2 is the primary GHG 

pollutant, accounting for nearly three-quarters of global GHG 

emissions20 and 3182 percent of U.S. GHG emissions.21 The May 2014 

report of the National Climate Assessment22 concluded that 

climate change impacts are already manifesting themselves and 

imposing losses and costs. The report documents increases in 

extreme weather and climate events in recent decades, with 

resulting damage and disruption to human well-being, 

infrastructure, ecosystems, and agriculture, and projects 

continued increases in impacts across a wide range of 

communities, sectors, and ecosystems. New scientific assessments 

 

20 Intergovernmental Panel on Climate Change (IPCC) report, 

“Contribution of Working Group I to the Fourth Assessment Report 

of the Intergovernmental Panel on Climate Change,” 

2007. Available at 

http://epa.gov/climatechange/ghgemissions/global.html 

21 From TablesTable ES-4 and 3-5 of2 “Inventory of U.S. 

Greenhouse Gas Emissions and Sinks: 1990 – 2013”, Report EPA 

430-R-15-004, United States Environmental Protection Agency, 

April 15, 2015. 

22 U.S. Global Change Research Program, Climate Change Impacts in 

the United States: The Third National Climate Assessment, May 

2014. Available at http://nca2014.globalchange.gov/. 
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since 2009, when the EPA determined that GHGs pose a threat to 

human health and the environment (the “Endangerment Finding”), 

highlight the urgency of addressing the rising concentration of 

CO2 in the atmosphere. Certain groups, including children, the 

elderly, and the poor, are most vulnerable to climate-related 

effects. Recent studies also find that certain communities, 

including low-income communities and some communities of color, 

(more specifically, populations defined jointly by ethnic/racial 

characteristics and geographic location), are disproportionately 

affected by certain climate change related impacts — including 

heat waves, degraded air quality, and extreme weather events – 

which are associated with increased deaths, illnesses, and 

economic challenges. Studies also find that climate change poses 

particular threats to the health, wellbeing, and ways of life of 

indigenous peoples in the United States. 

b. The utility power sector. One of the strategies of the 

President’s Climate Action Plan is to reduce CO2 emissions from 

power plants.23 This is because fossil fuel-fired EGUs are by far 

the largest emitters of GHGs, primarily in the form of CO2, 

among. Among stationary sources in the U.S. and, among fossil 

 

23 The President’s Climate Action Plan, June 2013. 

http://www.whitehouse.gov/sites/default/files/image/president27s

climateactionplan.pdf
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fuel-fired EGUs, coal-fired units are by far the largest 

emitters of GHGs. To accomplish thisthe goal, of reducing CO2

emissions from power plants,President Obama issued a 

Presidential Memorandum24 that recognized the importance of 

significant and prompt action. The Memorandum directed the EPA 

to complete carbon pollution standards, regulations or 

guidelines, as appropriate, for new, modified, reconstructed and 

existing power plants, and in doing so to build on state 

leadership in moving toward a cleaner power sector. In this 

action and the concurrent CAA section 111(b) rule, the EPA is 

finalizing regulations to reduce GHG emissions from fossil fuelfired EGUs. This CAA section 111(d) action builds on actions 

states and utilities are already taking to move toward cleaner 

generation of electric power. 

Unlike allThe utility power sector is unlike other 

industrial sectors, where. In other sectors, sources effectively 

operate independently and on a local-site scale, with control of 

their physical operations resting in the hands of their 

respective owners and operators. Pollution control standards, 

which focus on each source in a non-utility industrial source 

 

24 Presidential Memorandum – Power Sector Carbon Pollution 

Standards, June 25, 2013. http://www.whitehouse.gov/the-pressoffice/2013/06/25/presidential-memorandum-power-sector-carbonpollution-standards 
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category, have reflected the standalone character of individual 

source investment decision-making and operations. 

In stark contrast, the utility power sector comprises a 

unique system of electricity resources, including the EGUs 

affected under these guidelines, that operate in a complex and 

interconnected grid where electricity generally flows freely 

(e.g., portions of the system cannot be easily isolated through 

the use of switches or valves as can be done in a other 

networked systems like trains and pipeline systems). That grid 

is physically interconnected and operated on an integrated basis 

across large regions. In this interconnected system, 

electricitysystem operators, whose decisions, protocols, and 

actions, to a significant extent, dictate the operations of 

individual EGUs and large ensembles of EGUs, must reliably 

balance supply and demand are reliably balanced using available 

generation and demand-side resources, including energy 

efficiency, demand response and a wide range of low- and zeroemitting sources which. These resources are all managed to meet 

the system needs in a reliable and efficient manner. Each aspect 

of this interconnected system is highly regulated and 

coordinated, with supply and demand constantly being balanced to 

meet system needs. Each step of the process from the electric 

generator to the end user is highly regulated by multiple 
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entities working in coordination and considering overall system 

reliability. For example, in an ISO or RTO with a 

centralized, organized capacity market, electric generators are 

paid to be available to run when needed, must bid into energy 

markets, must respond to dispatch instructions, and must have 

permission to schedule maintenance. The ISO/RTO dispatches 

resources in a way that maintains electric system reliability. 

The approach we take in the final guidelines – both in the 

way we defined the BSER and established the resulting emission 

performance rates, and in the ranges of options we created for 

states and affected EGUs – is consistent with, and in some ways 

mirrors, the interconnected, interdependent and highly regulated 

nature of the utility power sector, the daily operation of 

affected EGUs within this framework, and the critical role of 

utilities in providing reliable, affordable electricity at all 

times and in all places within this complex, regulated system is 

largely. Thus, not only do these guidelines put a premium on 

providing as much flexibility and latitude as possible for 

states and utilities, they also recognize that a given EGU’s 

operations are determined by the availability and use of other 

generation resources to which it is physically connected and by 

the collective operating regime that integrates that individual 

EGU’s activity with other resources across the grid. 
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In this integrated, with system, numerous entities that 

have both the capability and the responsibility to maintain a 

reliable electric system. The Federal Energy Regulatory 

Commission (FERC), the U.S. Department of Energy (, DOE),, state 

public utility commissions, independent system operators (ISOs), 

regional transmission organizations (RTOs), other planning 

authorities, and the North American Electric Reliability 

Corporation (NERC), all contribute to ensuring the reliability 

of the electric system in the U.S. Critical to this function are 

dispatch tools, applied primarily by RTOs, ISOs, and balancing 

authorities, that operate such that actions taken or costs 

incurred at one source directly affect or cause actions to occur 

at other sources. Generation, outages, and transmission changes 

in one part of the synchronous grid can affect the entire 

interconnected grid.25 The interconnection is such that “[i]f a 

generator is lost in New York City, its effect is felt in 

Georgia, Florida, Minneapolis, St. Louis, and New Orleans.”26 The 

 

25 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 159 (2d ed. 2010). 26 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 160 (2d ed. 2010). 
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U.S. Supreme Court has similarlyexplicitly recognized the 

interconnected nature of the electricity grid.27 

The uniqueness of the utility power sector inevitably 

affects the way in which environmental regulations are designed. 

When the EPA promulgates environmental regulations that affect 

the utility power sector, as we have done numerous times over 

the past four decades, we do so with the awareness of the 

importance of the efficient and continuous, uninterrupted 

operation of the interconnected electricity system in which EGUs 

participate. We also keep in mind the unique product that this 

interconnected system provides – electricity services – and the 

 

27 Federal Power Comm’n v. Florida Power & Light Co., 404 U.S. 

453, at 460 (1972) (quoting a Federal Power Commission hearing 

examiner, "`If a housewife in Atlanta on the Georgia system 

turns on a light, every generator on Florida’s system almost 

instantly is caused to produce some quantity of additional 

electric energy which serves to maintain the balance in the 

interconnected system between generation and load.’”) (citation 

omitted). See also New York v. FERC, 535 U.S. 1, at 7-8 (2002) 

(stating that “any electricity that enters the grid immediately 

becomes a part of a vast pool of energy that is constantly 

moving in interstate commerce.”) (citation omitted). In Federal 

Power Comm’n v. Southern California Edison Co., 376 U.S. 205 

(1964), the Supreme Court found that a sale for resale of 

electricity from Southern California Edison to the City of 

Colton, which took place solely in California, was under Federal 

Power Commission jurisdiction because some of the electricity 

that Southern California Edison marketed came from out of state. 

The Supreme Court stated that, “`federal jurisdiction was to 

follow the flow of electric energy, an engineering and 

scientific, rather than a legalistic or governmental, test.’” 

Id. at 210, quoting Connecticut Light & Power Co. v. Federal 

Power Commission, 324 U.S. 515, 529 (1945) (emphasis omitted). 
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critical role of this sector to the U.S. economy and to the 

fundamental well-being of all Americans. 

In the context of environmental regulation, Congress, the 

EPA and the states all have recognized – as we do in these final 

guidelines – that electricity production takes place, at least 

to some extent, interchangeably between and among multiple 

generation facilities and different types of generation, as. 

This is evidenced in the enactment or promulgation of pollution 

reduction programs, such as Title IV of the CAA, the NOx SIP 

Call, the Cross-State Air Pollution Rule (CSAPR), and the 

Regional Greenhouse Gas Initiative (RGGI). As these actions 

show, both Congress and the EPA have consistently tailored 

legislation and regulations affecting the utility power sector 

to its unique characteristics. For example, in Title IV of the 

Clean Air Act Amendments of 1990, Congress established a 

pollution reduction program specifically for fossil fuel-fired 

EGUs and designed the SO2 portion of that program with express 

recognition of the sector’s ability to shift generation among 

various EGUs and to reduce, which enabled pollution reduction by 

increasing reliance on renewable energyRE and demand-side energy 

efficiencyEE. Similarly, in the NOX SIP Call, the Clean Air 

Interstate Rule (CAIR), and CSAPR, the EPA established pollution 

reduction programs focused on fossil fuel-fired EGUs and 
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designed those programs with express recognition of the sector’s 

ability to shift generation among various EGUs. In this action, 

we continue that approach. Both the source categorysubcategoryspecific emission performance rates, and the pathways offered to 

achieve them, reflect, and are tailored to, the unique 

characteristics of the utility power sector. 

When the EPA evaluated this sector for development of this 

rulemaking, we found that, across the nation, many states, 

cities and towns, and owners and operators of EGUs have shown 

leadership in creating and implementing policies and programs 

that reduce CO2 emissions from the utility power sector while 

achieving other economic, environmental and energy benefits. 

Some of these activities, such as market-based programs and GHG 

performance standards, directly require CO2 emission reductions 

from EGUs. Others reduce CO2 emissions by increasing the use of 

lower and zero CO2 emission alternatives, including both 

renewable generation and demand-side energy efficiency. For 

example, many states have adopted renewable portfolio standards 

(RPS) and energy efficiency resource standards (EERS). In other 

cases, utilities have chosen to construct renewable generation 

and/or implement demand-side energy efficiency programs, at 

least in part, to reduce CO2 emissions. These approaches take 

advantage of cost-effective opportunities for improving the 
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efficiency of fossil fuel-fired EGUs and using lower-emitting 

generation across the electricity system’s interconnecting grid 

to reduce emissions from fossil fuel-fired EGUs. 

The way that power is produced, distributed and used in the 

United States is already changing as a result of advancements in 

innovative power sector technologies and in the availability and 

cost of low-carbon fuel, renewable energyRE and energy efficient 

demand-side EE technologies, as well as economic conditions. 

These changes are taking place at a time when the average age of 

the coal-fired generating fleet is approaching that at which 

utilities and states undertake significant new investments to 

addressingaddress aging assets. In 2025, the average age of the 

coal-fired generating fleet is projected to be 49 years old, and 

20 percent of those units would be more than 60 years old if 

they remain in operation at that time. Therefore, even in the 

absence of additional environmental regulation, states and 

utilities can be expected to be, and already are, making plans 

for, and investing in, the next generation of power production, 

simply because theyof the need to take account of the age of 

current assets and infrastructure. OwnersHistorically, the 

industry has invested about $100 billion a year in capital 

improvements. These guidelines will help ensure that, as those 

necessary investments are being made, they are integrated with 
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the need to address GHG pollution from the sector. 

At the same time, owners/operators of affected EGUs are 

already pursuing the types of measures contemplated in this 

rule. Out of 417404 entities identified as owners or operators 

of affected EGUs, representing ownership of 8482 percent of the 

total capacity of the affected EGUs, 191178 already own RE 

generating capacity in addition to fossil fuel -fired generating 

capacity. In fact, these entities already own aggregate amounts 

of RE generating capacity equal to 2125 percent of the aggregate 

amounts of their affected EGU capacity.28 In addition, funding 

for utility energy efficiency programs has been growing rapidly, 

increasing from $1.6 billion in 2006 to $6.3 billion in 2013. 

The final guidelines are based on, and reinforce, the 

actions already being taken by states and utilities to upgrade 

aging electricity infrastructure with 21st century technologies. 

The guidelines will ensure that these trends continue in ways 

that are consistent with the long-term planning and investment 

processes already used in the utility power sector. This final 

rule provides flexibility for states to build upon their 

progress, and the progress of cities and towns, in addressing 

GHGs, and minimizes additional requirements for existing 

 

28 SNL Energy. Data used with permission. Accessed on June 9, 

2015. 
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programs where possible. It also allows states to pursue 

policies to reduce carbon pollution that: 1) continue to rely on 

a diverse set of energy resources; 2) ensure electric system 

reliability; 3) provide affordable electricity; 4) recognize 

investments that states and power companies are already making; 

and 5) tailor plans to meet their respective energy, 

environmental and economic needs and goals, and those of their 

local communities. Thus, the final guidelines will achieve 

meaningful CO2 emission reductions while maintaining the 

reliability and affordability of electricity in the U.S. 

c. CAA section 111(d) requirements. Concurrent with this CAA 

section 111(d) action, the EPA is finalizing “standards of 

performance” for CO2 emissions from new, modified, and 

reconstructed fossil fuel-fired EGUs under CAA section 111(b). 

When the EPA establishes CAA section 111(b) new source 

performance standards (NSPS), the EPA is also required, under 

CAA section 111(d)(1), to prescribe regulations for states to 

submit plans regulating existing sources in that source category 

for any air pollutant that is not regulated under the CAA 

section 109 requirements for the NAAQS or regulated under the 

CAA section 112 requirements for hazardous air pollutants (HAP). 

CO2 qualifies as such an air pollutant. Unlike the CAA section 

111(b) requirements that the EPA establishes and which apply 
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directly to new, modified, or reconstructed sources, under CAA 

section 111(d), states must develop and submit plans to the EPA 

in which the state establishes emission standards for the 

affected sources. 

Under CAA section 111(d),29 states must establish, in their 

state plans, emission standards that reflect the degree of 

emission limitation achievable through the application of the 

“best system of emission reduction” that, taking into account 

the cost of achieving such reduction and any non-air quality 

health and environmental impacts and energy requirements, the 

Administrator determines has been adequately demonstrated 

(BSER).30 Consistent with CAA section 111(d), the EPA is 

establishing CO2 emission performance rates for two categories of 

affected EGUs that reflect the EPA’s calculation of the emission 

limitation that each of the two categories can achieve through 

 

29 See also 40 CFR 60.22(b)(5). 

30 Under CAA section 111(a)(1) and (d), the EPA is authorized to 

determine the BSER and to calculate the amount of emission 

reduction achievable through applying the BSER. The state is 

authorized to identify the standard or standards of performance 

that reflects that amount of emission reduction. In addition, 

the state is required to include in its state plan the standards 

of performance and measures to implement and enforce those 

standards. The state must submit the plan to the EPA, and the 

EPA must approve the plan if the standards of performance and 

implementing and enforcing measures are satisfactory. This is 

discussed in more detail in Sections IV, VI, VII and VIII of 

this preamble, as well as in the Legal Memorandum. 
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the application of the BSER. This calculation reflects the 

degree of emission limitation that the state plan must achieve 

in aggregate in order to implement the BSER that the EPA has 

determined has been adequately demonstrated and that, in turn, 

will be required to be, and via the calculation, has been, 

applied for the two source categories of affected fossil fuelfired EGUs – fossil fuel-fired electric utility steam-generating 

units and stationary combustion turbines. 

To determine the BSER for reducing CO2 emissions at 

affected EGUs, the EPA considered numerous measures that 

are already being implemented and can be implemented more 

broadly to improve emission rates and to reduce overall CO2

emissions from fossil fuel-fired EGUs. Overall, the BSER is 

based on a range of measures that fall into three main 

categories, which comprise improving operations at EGUs, 

shifting generation to lower-emitting affected EGUs, and 

shifting generation to renewable energy generation. These 

measures have been amply demonstrated via their current 

widespread use by utilities and states. Consistent with CAA 

section 111(d), in this final rule, the EPA is establishing 

emission guidelines for states to follow in formulating 

their plans to establish and implement standards of 
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performance to achieve CO2 emission reductions from fossil 

fuel-fired EGUs that are consistent with the BSER. 

The final guidelines are structured so that states are 

not required to use each and every one of the measures that 

the EPA determines constitute the BSER or to apply any one 

of those measures to the same extent that the EPA 

determines is achievable at reasonable cost on a national 

basis. Instead, in developing its plan, each state will 

have the flexibility to select the measure or combination 

of measures it prefers in order to achieve the CO2 emission 

performance rates for its affected EGUs or meet the 

equivalent statewide rate- or mass-based CO2 goal. Thus, a 

state could choose to achieve more reductions from one 

measure encompassed by the BSER and less from another, or 

it could choose to include measures such as demand-side EE 

programs that are not part of the EPA’s BSER determination, 

as detailed in Section VIII of this preamble. Expressing 

the states’ obligation in terms of a state-level goal that 

can be met in aggregate, including through the adoption of 

CO2 emission reduction measures that are not identical to 

the components of the BSER or are not included in the BSER, 

rather than exclusively through source-specific emission 

performance rates, is entirely permissible precisely 
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because the approach mirrors the foundation of the BSER 

approach itself, namely the interconnected nature of the 

electricity system in which affected EGUs operate. 

We expect that affected EGUs in each state will be 

able to meet the CO2 emission performance rates because the 

emission performance rates represent the application of the 

BSER specific to the two categories of affected EGUs. 

4. Summary of the 6major provisions 

a. Overview. Though there are notable revisions – many of which 

have been identified above – from the emission guidelines we 

proposed in June 2014, the proposed guidelines serve as the 

foundation of this final rule. First, these final guidelines 

build on the progress already underway to reduce the carbon 

intensity of power generation in the United States (U.S.). 

Second, these guidelines reflect the unique interconnected 

system within which EGUs operate. Thus, the BSER, as determined 

in these guidelines, incorporates a range of CO2-reducing 

actions. Equally important, these guidelines offer states and 

owners and operators of EGUs broad flexibility and latitude in 

complying with their obligations. Because affordability and 

electricity system reliability are of paramount importance, the 

rule continues to provide states and utilities with time for 

planning and investment, which is instrumental to ensuring both 
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manageable costs and system reliability and to facilitating 

clean energy innovation. The final rule continues to express the 

CO2 emission reduction requirements in terms of a state-level 

goal that reflects the particular mix of power generation in 

each state, and it continues to provide until 2030, fifteen 

years from the date of this final rule, for states and sources 

to achieve the CO2 reductions, which numerous commenters, 

including most sources, states and energy agencies, indicated 

was a reasonable timeframe. 

b. Opportunities for states. Because, as stated above, the final 

guidelines are designed to build on and reinforce progress by 

states, cities and towns, and companies on a growing variety of 

sustainable strategies to reduce power sector CO2 emissions, 

states will be able to rely in their CAA section 111(d) plans 

on, and extend, programs they may already have created to 

address the power sector. Those states committed to Integrated 

Resource Planning (IRP) will be able to establish their CO2

reduction plans within that framework, while states with a more 

deregulated power sector system will be able to develop CO2

reduction plans within that specific framework. Each state will 

have the opportunity to take advantage of a wide variety of 

strategies for reducing CO2 emissions from affected EGUs. The EPA 

and other federal entities, including the U.S. Department of 
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Energy (DOE), the Federal Energy Regulatory Commission (FERC) 

and the U.S. Department of Agriculture, among others, are 

committed to sharing expertise with interested states as they 

develop and implement their plans. 

States will be able to address the economic interests of 

their utilities and ratepayers by using the flexibilities in 

this final action to: 1) reduce costs to consumers, minimize 

stranded assets, and spur private investments in renewable 

energy and energy efficiency technologies and businesses; and 2) 

if they choose, work with other states on multi-state approaches 

that reflect the regional structure of electricity operating 

systems that exists in most parts of the country and is critical 

to ensuring a reliable supply of affordable energy. The final 

rule gives states the flexibility to implement a broad range of 

approaches that recognize that the power sector is made up of a 

diverse range of companies of various sizes that own and operate 

fossil fuel-fired EGUs, including vertically integrated 

companies in regulated markets, independent power producers, 

rural cooperatives and municipally-owned utilities, some of 

which are likely to have more direct access than others to 

certain types of GHG emission reduction opportunities, but all 

of which have a wide range of opportunities to achieve 

reductions or acquire clean generation. 
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c. Main elements. This final rule has two main elements: 1) 

tailored state-level CO2 goals that are translated from the 

numerical source category-specific CO2 emission performance rates 

resulting from application of the BSER to the source categories 

of affected EGUs, and 2) guidelines for the development, 

submittal and implementation of state plans that implement those 

standards either directly or through measures that achieve the 

equivalent in aggregate of those rates.31 

In this final action, the EPA is setting performance 

rates for two categories of affected fossil fuel-fired EGUs 

– fossil fuel-fired electric utility steam-generating units 

and stationary combustion turbines. These rates, applied to 

each state’s particular mix of fossil fired EGUs, generate 

the state’s carbon intensity goal for 2030(and interim 

rates for the period 2022-2029). Each state will determine 

whether to apply these to each affected EGUs or to take an 

alternative approach and meet either an equivalent 

statewide rate-based goal or statewide mass-based goal. The 

EPA does not prescribe how a state must meet the emission 

 

31 A state plan must be developed by a state, the District of 

Columbia, a U.S. territory, and any Indian tribe that has been 

approved by the EPA pursuant to 40 CFR 49.9 as eligible to 

develop and implement a CAA section 111(d) plan if it has one or 

more affected EGUs in its jurisdiction. 
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guidelines, but these final guidelines do identify the 

methods which a state can or must use to demonstrate that 

the combination of measures and standards that the state 

does adopt meet its state-level CO2 goals. CAA section 

111(d) creates a partnership between the EPA and the states 

under which the EPA establishes emission guidelines and the 

states take the lead on meeting them by creating plans that 

are consistent with the EPA emission guidelines. The EPA 

recognizes that each state has differing policy 

considerations – including varying regional emission 

reduction opportunities and existing state programs and 

measures – and that the characteristics of the electricity 

system in each state (e.g., utility regulatory structure 

and generation mix) also differ. Therefore, as in the 

proposal, each state will have the latitude to design a 

program to meet source-category specific emission 

performance rates or the equivalent statewide rate- or 

mass-based goal in a manner that reflects its particular 

circumstances and energy and environmental policy 

objectives. Each state can do so on its own, or a state can 

collaborate with other states and/or tribal governments on 

multi-state plans – or states can include in their plans 

the trading tools that EGUs can use to realize additional 
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opportunities for cost savings while continuing to operate 

across the interstate system through which electricity is 

produced. 

To facilitate the state planning process, this final 

rule establishes guidelines for the development, submittal, 

and implementation of state plans. The final rule describes 

the components of a state plan, the additional latitude 

states have in developing strategies to meet the emission 

guidelines, and the options they have in the timing of 

submittal of their plans. This final rule also gives states 

considerable flexibility with respect to the timeframes for 

plan development and implementation, as well as the choice 

of emission reduction measures. The final rule provides up 

to fifteen years for full implementation of all emission 

reduction measures, with incremental steps for planning and 

then for demonstration of CO2 reductions that will ensure 

that progress is being made in achieving CO2 emission 

reductions. States will be able to choose from a wide range 

of emission reduction measures, including measures that are 

not part of the BSER, as discussed in detail in Section 

VIII.G of this preamble. 

d. Determination of the BSER. In issuing this final 

rulemaking, the EPA is implementing statutory provisions 
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that have been in place since Congress first enacted the 

CAA in 1970 and that have been implemented pursuant to 

regulations promulgated in 1975 and followed in numerous 

subsequent CAA section 111 rulemakings. These requirements 

call on the EPA to develop emission guidelines that reflect 

the EPA’s determination of the BSER for states to follow in 

formulating plans to implement standards of performance to 

achieve emission reductions consistent with the BSER. In 

following the provisions, the EPA is finalizing a BSER 

based on strategies currently being used by states and 

companies to reduce CO2 emissions from EGUs.

In this final action, the agency has determined that the 

BSER comprises the first three of the four proposed building 

blocks, with certain refinements to the three building blocks. 

The widely demonstrated availability of the trading of emission 

rate credits or mass allowances as a mechanism to facilitate 

achievement by any individual EGU or group of EGUs of the 

emission reductions available from each of the building blocks, 

as well as to reduce costs, supports this approach. Any affected 

EGU can achieve the equivalent of dispatch of NGCC units, per 

building block 2, or of RE generation, per building block 3, by 

using the acquisition of a credit or allowance as the medium for 
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investment in lower-emitting generation provided by NGCC units 

or RE facilities. 

The CAA, as interpreted by the courts, identifies several 

factors for the EPA to consider in a BSER determination. These 

include technical feasibility, costs, size of emission 

reductions and technology (e.g., whether the system promotes the 

implementation and further development of technology). In 

determining the BSER for this industrial sector, the EPA 

considered the reductions achievable through measures that 

reduce CO2 emissions from existing fossil fuel-fired EGUs either 

by (1) reducing the CO2 emission rate at those units or (2) 

reducing the units’ CO2 emission total to the extent that 

generation can be shifted from higher-emitting fossil fuel-fired 

EGUs to lower- or zero-emitting options. 

As the EPA has done in making BSER determinations in 

previous CAA section 111(d) rulemakings, the agency considered 

the types of strategies that states and owners and operators of 

EGUs are already employing to reduce the covered pollutant (in 

this case, CO2) from affected sources (in this case, fossil fuelfired EGUs).32 

 

32 The final emission guidelines for landfill gas emissions from 

municipal solid waste landfills, published on March 12, 1996 and 

amended on June 16, 1998 (61 FR 9905 and 63 FR 32743, 
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To determine the BSER for reducing CO2 emissions at 

affected EGUs and to establish the emission guidelines that 

reflect the BSER, the EPA considered numerous measures that 

can and are being implemented to improve emission rates and 

to reduce or limit mass CO2 emissions from fossil fuel-fired 

EGUs. These measures encompass two basic approaches: 1) 

reducing the carbon intensity of certain affected EGUs by 

improving the efficiency of their operations, and 2) 

addressing affected EGUs’ mass emissions by varying their 

utilization levels. For the second approach, we relied on 

the standard statutory and regulatory considerations that 

provide the basis for any BSER determination in examining, 

in this case, the extent to which that generation can be 

shifted from higher-emitting fossil fuel-fired EGUs to 

lower- or zero-emitting options. From these two approaches, 

we identified measures that fit into three main categories, 

or “building blocks.” The building blocks are: 

 

respectively r) are one example, as they allow either of two 

approaches for controlling landfill gas – by recovering the gas as 

a fuel, for sale, and removing from the premises, or by 

destroying the organic content of the gas on the premises using 

a control device. Recovering the gas as a fuel source was a 

practice already being used by some affected sources prior to 

promulgation of the rulemaking. 
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1. Reducing the carbon intensity of generation at 

individual affected coal-fired steam EGUs through heat 

rate improvements. 

2. Substituting increased generation from loweremitting existing natural gas combined cycle units 

for reduced generation from higher-emitting affected 

steam generating units. 

3. Substituting increased generation from new low- and 

zero-emitting generating units, including renewable 

energy and new natural gas combined cycle (NGCC) 

units, for reduced generation from affected fossil 

fuel-fired generating units. 

The building blocks are described in detail in Section 

V of this preamble. As explained in that section, the EPA 

evaluated each of the building blocks individually against 

the BSER factors. The EPA found that each of the building 

blocks independently merits consideration as part of the 

BSER because, at the identified level of stringency, it is 

achievable by individual sources and by the source 

category, it will result in meaningful emission reductions 

at reasonable cost, and it satisfies the other BSER 

factors. This includes considering the use of some 

increment of new NGCC generation as part of building block 
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3, since replacing higher-emitting existing steam 

generation with cleaner new NGCC generation has been 

occurring to some degree. (For reasons discussed in Section 

V.A.3 of this preamble, the EPA determined not to finalize 

the inclusion of demand-side EE, which was discussed as a 

fourth potential building block in the proposal, as a 

component of the BSER.) 

The EPA also evaluated combinations of the three 

building blocks against the BSER factors in making its 

determination. The EPA determined that the combination of 

all three building blocks is the BSER, taking into account 

the fact that the widely demonstrated availability of the 

trading of emission rate credits or mass allowances can 

enable any given EGU to achieve its emission reduction 

obligations (i.e., if an EGU should choose not to meet its 

obligations simply by limiting its own operations, it could 

rely on the interconnected function of the electricity 

system to effectuate replacement generation from new clean 

generation or from the re-dispatch of existing NGCC units). 

This combination best represents the BSER because, compared 

to combinations including fewer than all three building 

blocks, it achieves greater emission reductions at a lower 

cost, takes better advantage of the wide range of measures 
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that states, cities, towns and utilities are already using 

to reduce CO2 from EGUs, and reflects the integrated nature 

of the electricity system and the diversity of electricity 

generation technology. 

For the final rule, in response to stakeholder comments, 

the EPA has made refinements to the building blocks, and these 

are reflected in the final BSER. These include adoption of a 

modified approach to quantification of the renewable energy 

component, exclusion of the proposed nuclear generation 

components, and adoption of a consistent regionalized approach 

to quantification of all three building blocks. The BSER also 

includes an increment of emission reductions at affected EGUs 

that corresponds to the increment of generation at new NGCC 

units projected to be built in the future that can replace 

generation at affected EGUs (e.g., generation from new NGCC 

units beyond what is needed to meet load growth and that is, 

therefore, available to displace existing, higher-emitting 

generation). The agency also recognizes the important functional 

relationship between the period of time over which measures are 

deployed and the stringency of emission limitations those 

measures can achieve in a practical and reasonable cost way. 

Therefore, the final BSER also reflects adjustments to the 

stringency of the building blocks, after consideration of more 
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and less stringent levels, and refinements to the timeframe over 

which reductions must be achieved. Sections V.C through V.E 

provide further information on the refinements made to the 

building blocks and the rationale for doing so. 

As part of the BSER determination, the EPA considered 

the impacts that implementation of the emission reductions 

based on the combination of the blocks will have on the 

cost of electricity and electricity system reliability. As 

detailed in Section V of this preamble, the EPA believes 

that, both with respect to the overall BSER and with 

respect to the individual building blocks, the associated 

costs are reasonable. In summary, the EPA determined that 

the BSER for purposes of CAA section 111(d), as applied to 

existing fossil fuel-fired EGUs, is based on a combination 

of measures that reduce CO2 emissions and CO2 emission rates 

and encompasses three building blocks, together with 

emissions trading.33 

 

33 The EPA notes that under the BSER, some building blocks will 

apply to some, but not all, affected sources. Specifically, 

building block 1 will apply to affected coal-fired steam EGUs, 

building block 2 will apply to all affected steam EGUs (both 

coal-fired and oil/gas-fired), and building block 3 will apply 

to all affected EGUs. 
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In determining the BSER, we considered the ranges of 

reductions that can be achieved at reasonable cost by 

application of each building block, considering both 

stringency and time, and we have calculated CO2 emission 

performance rates for the categories of fossil fuel-fired 

electric utility steam generating units and stationary 

combustion turbines. Rather than the maximum possible 

degree of application, we have finalized what we believe 

reflects a reasonable degree of application of each 

building block consistent with the BSER criteria. Relying 

on the three building blocks to characterize the 

combination of measures that reduce CO2 emissions and CO2

emission rates at affected EGUs as the basis for the BSER 

is consistent with strategies, actions and measures that 

companies and states are already undertaking to reduce GHG 

emissions and with current trends in the utility power 

sector, driven by efforts to reduce GHGs as well as by 

other factors, such as advancements in technology. Reliance 

on all three building blocks in this way also supports the 

goals of achieving significant and technically feasible 

reductions of CO2 at a reasonable cost, while also promoting 

technology and approaches that are important for achieving 

further reductions. Finally, the EPA believes that the 
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diverse range of measures encompassed in the three building 

blocks, and the availability of emissions trading, allows 

states and sources to take full advantage of the inherent 

flexibility of the current regionally interconnected and 

integrated electricity system so as to achieve the CO2 goals 

while continuing to meet the demand for electricity 

services in a reliable and affordable manner. 

The EPA recognizes that states differ in important 

ways, including in their mix of existing EGUs, policy 

priorities, and regional resource development 

opportunities. Consequently, opportunities for reducing 

emissions, as reflected in each of the building blocks, 

vary across states. Each state will be able to design a 

program that uses the measures it selects, and these may 

include the combination of building blocks most relevant to 

its specific circumstances and policy preferences. States 

may also use technologies or strategies that are not 

explicitly mentioned in any of the three building blocks 

and may use those technologies or strategies as part of 

their overall plans (e.g., market-based trading programs; 

demand-side energy efficiency programs). Explanation of 

other technologies or strategies that a state may 

incorporate in its plan is provided in Section VIII of this 
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preamble. Additionally, the EPA’s approach allows multistate strategies, ranging from the formal types of 

interstate arrangements (joint plans) to flexibility for 

sources in “trading ready” states to interact with one 

another through trading. These issues are discussed in 

greater detail in Section VIII. 

e. CO2 source category-specific emission performance rates and 

state-level goals. 

(1) Final CO2 emission performance rates and goals. In this 

action, the EPA is establishing CO2 emission performance rates 

for two subcategories of affected EGUs-- fossil fuel-fired 

electric utility steam generating units and stationary 

combustion turbines -- that state plans must be designed to 

meet. For fossil fuel-fired steam generating units, we are 

finalizing an emission performance rate of 1,290 lb/MWh of CO2. 

For stationary combustion turbines, we are finalizing an 

emission performance rate of 780 lb/MWh of CO2. 

To continue to provide the flexibility inherent in the 

proposal’s state-specific goals approach, in this final 

rule, the EPA has translated the source category-specific 

CO2 emission performance rates into equivalent statewide 

rate-based and mass-based CO2 goals and is providing those 

in Section VII of this preamble. 
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Affected EGUs, individually, in aggregate, or in 

combination with other measures undertaken by the state, 

must achieve the equivalent of the CO2 emission performance 

rates by 2030. Importantly, by expressing the application 

of the final BSER as source category-specific CO2 emission 

performance rates, and by providing a translation of those 

performance rates to statewide rate- and mass-based CO2

goals, the rule allows states the flexibility to determine 

how to achieve the CO2 reductions (i.e., greater reductions 

from one building block and less from another, as well as 

the adoption of other measures that lower carbon 

intensity), and to adjust the timing in which reductions 

are achieved, in order to address key issues such as cost 

to consumers, electricity system reliability and the 

remaining useful life of existing generation assets. 

(2) Interim CO2 emission performance rates and state-level 

goals. The EPA recognizes that, with many measures, states can 

achieve CO2 emission reductions in the short-term, in certain 

circumstances, such as those for which instrumental 

infrastructure and/or programs are already in place. For other 

measures, such as the addition of renewable energy (RE) 

generating capacity, the full effects of implementation can take 

longer. We recognize that, under the Clean Air Act, the 
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determination of the BSER includes not only the types of 

measures that constitute the best system, but also the timeframe 

within which those measures can reasonably be implemented. In 

the proposal, we included an interim period – 2020 through 2029 

– reflecting that reductions could reasonably be achieved on a 

glide path toward meeting the final goals in 2030. For the final 

emission guidelines, in response to concerns that required CO2

emission reductions could not be achieved as early as 2020 – and 

to reflect the period of time required through the process of 

state plan development and submission to the EPA, the EPA review 

and approval and state and EGU implementation of approved plans 

- the EPA is establishing an eight-year interim period over 

which to achieve the full required reductions to meet the CO2

performance rates, and this begins in 2022, more than six years 

from [INSERT THE DATE OF PUBLICATION IN THE FEDERAL REGISTER], 

the date of this rulemaking. This eight-year interim period from 

2022 through 2029 is separated into three steps, 2022-2024, 

2025-2027, and 2028-2029, each associated with its own interim 

CO2 emission performance rates. These steps respond to many 

comments we received requesting a more graduated trajectory, but 

the rule also retains a state’s ability to adapt these steps as 

appropriate to accommodate the timing of expected reductions, as 

long as the interim goal is met over the eight year period. A 
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state can take advantage of this timing in the design of its 

program by using relevant combinations of building blocks, as 

well as averaging over the interim period, to achieve required 

CO2 reductions in a manner and on a schedule that provides for 

electricity system reliability, avoids the creation of stranded 

assets and bears a reasonable cost. In short, to use the 

parlance of numerous state and stakeholder discussions, states 

can determine their own respective emission reduction 

trajectories or “glide paths”.

We believe that this approach for achieving CO2

reductions over time responds both to the needs of an 

effectively implemented program and to the persuasive 

arguments presented by stakeholders regarding balancing the 

simultaneous need for both flexibility and certainty about 

what will constitute an approvable state plan. We likewise 

believe that this approach also represents a reasonable 

balance between two competing objectives grounded in CAA 

section 111(d) - a need for rigor and consistency in 

calculating emission reductions reflecting the BSER and a 

need to provide the states with flexibility in establishing 

and implementing the emission standards or measures that 

reflect those emission reductions. The importance of this 

balance is heightened by the fact that the operations of 
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the electricity system itself rely on the flexibility made 

available and achieved through shifting generation between 

and among multiple interconnected EGUs, demand management 

and demand-side energy efficiency. This approach recognizes 

that state plans for emission reductions can, and must, be 

consistent with a vibrant and growing economy and the ample 

supply of reliable, affordable electricity needed to 

support that economy. It further reflects the growing 

trend, as exemplified by many state and local clean energy 

policies and programs, to shift energy production away from 

carbon-intensive fuels to a modern, more sustainable system 

that puts greater reliance on renewable energy, energy 

efficiency and other low-carbon energy options. 

f. State plans.34 In this action, the EPA is also 

establishing final guidelines for states to follow in 

developing their plans. In developing plans, states will 

need to choose the type of plan they will develop. They 

will also need to include required plan components in their 

 

34

 A state plan must be developed by a state, the District of 

Columbia, a U.S. territory, and any Indian tribe that has been 

approved by the EPA pursuant to 40 CFR 49.9 as eligible to 

develop and implement a CAA section 111(d) plan if it has one or 

more affected EGUs in its jurisdiction. The District of Columbia 

does not have any affected EGUs and, therefore, will not be 

required to submit a plan. 
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plan submittals, meet plan submittal deadlines, achieve the 

required CO2 emission reductions over time, and provide for 

monitoring and periodic reporting of progress.

(1) Plan approaches. To comply with these emission 

guidelines, in its plan, each state will have to ensure that the 

emission standards it establishes for its sources individually, 

in aggregate, or in combination with other measures undertaken 

by the state, represent the equivalent of the source categoryspecific emission performance rates. This final rule includes 

several types of flexibilities for state plans, as discussed in 

the proposal and in many of the comments we received. 

First, under the final rule, states may adopt either a 

rate-based or mass-based goal. For this purpose, the EPA is 

providing statewide rate-based goals and mass-based goals 

equivalent to the emission performance rates that the EPA is 

establishing for the two subcategories of fossil fuel-fired 

EGUs. In developing its plan, each state, U.S. territory, and 

eligible tribe will need to choose whether it will include CO2

emission performance rates, statewide rate-based goals, or 

statewide mass-based goals. 

The second major flexibility provided in the final rule 

relates to the types of measures included in the state plans. A 

state will be able to choose to place all of the requirements 
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directly on its affected EGUs, which we refer to as the 

“emission standards approach.” Alternatively, a state can adopt 

a “state measures approach,” which would include stateenforceable measures that may apply to affected EGUs and other 

entities, with some or no federally enforceable emission 

standards for affected EGUs. With a state measures approach, the 

plan must also include a backstop of federally enforceable 

standards on affected EGUs that fully meet the emission 

guidelines and that would be triggered if the plan failed to 

achieve on schedule the required emission reductions. A state 

would have the option of basing its backstop emission standards 

on the federal plan, using the federal plan regulations as a 

model rule. 

The plan must also include a process for reporting on plan 

implementation, progress toward achieving CO2 emission 

reductions, and implementation of corrective actions, if 

applicable. Beginning January 1, 2025, and then January 1, 2027, 

followed by January 1, 2029, and then every two calendar years, 

the state will be required to compare emission levels achieved 

by affected EGUs in the state with the emission levels projected 

in the state plan and report the results of that comparison to 

the EPA by July 1 of those calendar years. 
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Plans for states with existing programs, such as those 

being implemented in California and the RGGI states, will 

be approvable provided that, when plans are submitted, they 

demonstrate that when the plans are fully implemented, 

affected EGUs achieve all of the emission reductions 

required in these guidelines for those states’ sources that 

are affected per these guidelines. The plan guidelines 

provide the states with the ability to achieve the full 

reductions over a multi-year period, through a variety of 

reduction strategies, using state-specific or multi-state 

approaches that can be achieved on either a rate or mass 

basis. They also address several key policy considerations 

that states can be expected to contemplate in developing 

their plans. 

State plan approaches and plan guidelines are explained 

further in Section VIII of this preamble. 

(2) State plan components and approvability criteria. The 

EPA’s implementing regulations provide certain basic elements 

required for state plans submitted pursuant to CAA section 

111(d). 40 CFR 60.23. In the proposal, the EPA identified 

certain additional elements that should be contained in state 

plans. In this final action, in response to comments, the EPA is 

making several revisions to the components required in a state 
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plan submittal and is also incorporating the approvability 

criteria into the list of components required in a state plan 

submittal. In addition, we have revised the state plan 

components to reflect: 1) components required for all state plan 

submittals; 2) additional components required for the emission 

standards approach; and 3) additional components required for 

the state measures approach. 

All state plans must include the following components: 

 Description of the plan 

 Identification of state CO2 interim period goal (for 

2022-2029), interim steps (interim step goal 1 for 

2022-2024; interim step goal 2 for 2025-2027; interim 

step goal 3 for 2028-2029) and final CO2 emission goal 

of 2030 and beyond 

 Demonstration that the plan submittal is projected to 

achieve the state’s CO2 emission goal 

• State recordkeeping and reporting requirements 

• Certification of hearing on state plan 

• Supporting documentation 

 

Also, in submitting state plans, states must provide 

documentation demonstrating that they have considered 

reliability in developing their plans. 

Further, because certain communities, including low-income 

communities and some communities of color, are 

disproportionately affected by climate change related impacts, 

the EPA is seeking to ensure that states are actively engaging 

with communities and is, therefore, requiring states to provide, 

in their initial plan submittal, a summary of how they have been 
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engaging with community stakeholders and how they intend to 

meaningfully engage with community stakeholders during the 

additional time (if an extension is granted) for development of 

the final plan. For the final plan submittal, states must have 

meaningful engagement with all members of the public, including 

affected communities, during the final plan development process, 

pursuant to the public participation requirements of the 

implementing regulations. This could include topics such as 

potential localized impacts and potential changes to electricity 

rates, among others. 

State plan submittals using the emission standards approach 

must also include: 

 Identification of each affected EGU; identification of 

federally enforceable emission standards for the affected 

EGUs; and monitoring, recordkeeping and reporting 

requirements. 

 Demonstrations that each emission standard will result in 

reductions that are quantifiable, non-duplicative, 

permanent, verifiable, and enforceable. 

State plan submittals using the state measures approach 

must also include: 

 Identification of each affected EGU; identification of 

federally enforceable emission standards for affected EGUs 

(if applicable); identification of backstop of federally 

enforceable emission standards; and monitoring, 

recordkeeping and reporting requirements. 

 Identification of each state measure and demonstration that 

each state measure will result in reductions that are 

quantifiable, non-duplicative, permanent, verifiable, and 

enforceable. 
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In addition to these requirements, each state plan must follow 

the EPA implementing regulations at 40 CFR 60.23. 

(3) Timing and process for state plan submittal and review. 

Because of the compelling need for actions to begin the steps 

necessary to reduce GHG emissions from EGUs, the EPA proposed 

that states submit their plans within 13 months of the date of 

this final rule and that reductions begin in 2020. Commenters 

have provided compelling information that it will take longer 

than the agency initially anticipated to adjust investments and 

achieve interim CO2 reductions. The EPA agrees with these 

comments, which we believe support extending the start date of 

the compliance period from 2020 to 2022 and retaining the 

requirement that initial plans be submitted without additional 

delay. Specifically, the final rule requires each state to 

submit a plan by August 31, 2016. Since some states may need 

more than one year to complete all of the actions needed for 

their final state plans, including technical work, state 

legislative and rulemaking activities, a robust public 

participation process, coordination with third parties, and 

coordination among states involved in multi-state plans, as well 

as consultation with reliability entities, the EPA is allowing 

an optional two-phased submittal process for state plans. Each 
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state will be required to submit a plan by August 31, 2016, that 

contains certain required components. If a state needs 

additional time to submit a final plan, then the state may 

submit an initial plan by August 31, 2016, that documents the 

reasons the state needs more time and includes commitments to 

concrete steps that will ensure that the state will submit a 

final plan by August 31, 2018. To be approvable, the EPA is 

finalizing that the initial plan submittal must address all 

components of a final plan submittal, including identifying 

which components are not complete. The initial plan must include 

specific components, including a justification for seeking an 

extension, a description of the plan approach, a commitment to 

maintain existing measures that limit CO2 emissions, progress to 

date in developing a final plan, a comprehensive roadmap of the 

path to completion including specific steps the state, sources 

or other entities will be implementing in order to meet the 

initial compliance requirements beginning in 2022, and 

demonstration of opportunity for public comment on the submittal 

and a summary of the state’s response to any significant public 

comment on the approvability of the initial plan, as described 

in Section VIII.E of this preamble. 

If the initial submittal includes those components and if 

the EPA does not notify the state that the initial submittal 
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does not contain the required components, the extension of time 

to submit a final plan will be deemed granted and a state will 

have until August 31, 2018, to submit a final plan. Further, 

states participating in a multi-state plan may submit a single 

joint plan on behalf of all of the participating states. States, 

U.S. territories, and tribes that do not have affected EGUs in 

their jurisdictional boundaries may participate in emission 

trading programs (e.g., as providers of emission rate credits, 

to adjust CO2 emission rates for affected EGUs). 

Following submission of final plans, the EPA will 

review plan submittals for approvability. Given the diverse 

approaches states may take to meet the CO2 emission 

performance rates or equivalent statewide goals in the 

emission guidelines, the EPA is extending the period for 

EPA review and approval or disapproval of plans from the 

four-month period provided in the EPA implementing 

regulations to a twelve-month period. 

(4) Timing for meeting the CO2 emission guidelines. The EPA 

recognizes that the measures states and utilities have been and 

will be taking to reduce CO2 emissions from existing EGUs can 

take time to implement. Based on a careful review of the 

comments and other material in the record, the EPA is 

determining in this final rule that affected EGUs will be 
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required to begin to make reductions by 2022, instead of 2020, 

as proposed, and meet the final CO2 performance rates or 

equivalent statewide goals by no later than 2030. The EPA is 

establishing an eight-year interim period that begins in 2022 

and goes through 2029, and which is separated into three steps, 

2022-2024, 2025-2027, and 2028-2029, each associated with its 

own interim goal. Affected EGUs must meet each of the interim 

period step 1, 2, and 3 CO2 performance rates, or must meet the 

equivalent statewide interim period goals, on average, that a 

state may establish over the 8-year period from 2022-2029, which 

the state must reflect in its CAA section 111(d) plan. Affected 

EGUs must also achieve the final CO2 performance rates or the 

equivalent statewide goal by 2030 and maintain that level 

subsequently. This approach reflects adjustments to the 

timeframe over which reductions must be achieved that mirror the 

determination of the final BSER. The agency believes that this 

approach for timing is reasonable and appropriate, is consistent 

with many of the comments we received, and will best support the 

optimization of overall CO2 reductions. 

Measures that a state takes prior to 2022, or programs 

already in place by 2022, that result in CO2 emission reductions 

during the 2022-2029 period will contribute toward meeting both 

the interim and final CO2 emission performance rates. Thus, 
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states with currently existing programs and policies, and states 

that put in place new programs and policies early, will be 

better positioned to achieve the goals. RE generating capacity 

and demand-side EE measures that are installed after 2012 will 

be eligible for use in adjusting a CO2 emission performance rate. 

Further discussion of timing is presented in Section VIII.G of 

this preamble. 

(5) Electric system reliability. These guidelines reflect 

the paramount importance of ensuring electric system 

reliability, in no small part thanks to the comments we 

received and our extensive consultation with key agencies 

responsible for reliability, including FERC and DOE, among 

others. We are addressing these concerns in large part by moving 

the start date of the program from 2020 to 2022 and 

significantly adjusting the interim goals so that they provide a 

less abrupt initial reduction expectation. These changes will 

provide more time for planning, consultation and decision making 

in the formulation of state plans and in EGUs’ choice of 

compliance strategies, all within the existing extensive 

structure of energy planning at the state and regional levels. 

In addition, the various forms of flexibility retained and 

enhanced in this final rule, including opportunities for trading 

within and between states, and other multi-state compliance 
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approaches, will further support electric system reliability. In 

addition, we are including in the final rule a requirement that 

each state demonstrate in its state plan submittal that it has 

considered reliability issues in developing its plan, which it 

can do, for example, by consulting with state utility agencies 

and/or regional planning authorities. 

We recognize that issues may arise during the 

implementation of the guidelines that may warrant adjustments to 

a state’s plan in order to maintain electric system reliability. 

The final guidelines further provide states with the option of 

proposing amendments to approved plans in the event that 

unanticipated and significant reliability challenges arise. 

And, as a final element of reliability assurance, the rule also 

provides for a reliability safety valve for individual sources 

where there is a conflict between the requirements the state 

plan imposes on a specific affected EGU and the maintenance of 

electric system reliability due to an extraordinary event. In 

addition, the EPA, DOE and FERC have agreed to coordinate 

efforts to help ensure continued reliable electricity generation 

and transmission during the implementation of the final 

rule. The three agencies have set out a memorandum that reflects 

their joint understanding of how they will work together to 
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monitor implementation, share information, and to resolve any 

difficulties that may be encountered. 

As a result of the many features of this final rule that 

provide states and affected EGUs with meaningful time and 

decision making latitude, we believe that the comprehensive 

safeguards already in place in the U.S. to ensure electric 

system reliability will continue to operate effectively as 

affected EGUs reduce their CO2 emissions under this program. 

Outreach and resources for stakeholders. To provide states, U.S. 

territories, tribes, utilities, communities, and other 

interested stakeholders with understanding about the rule 

requirements, and to provide efficiencies where possible and 

reduce the cost and administrative burden, the EPA will continue 

to work with states, tribes, and stakeholders to provide 

information and address questions about the final rule. Outreach 

will include opportunities for states and tribes to participate 

in briefings, teleconferences, and meetings about the final 

rule. The EPA’s 10 regional offices will continue to be the 

entry point for states, tribes and territories to ask technical 

and policy questions. The agency will host (or partner with 

appropriate groups to co-host) a number of webinars about 

various components of the final rule; these webinars are planned 

for the first two months after the final rule is issued. The EPA 
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will also offer consultations with tribal officials. The EPA 

will continue outreach throughout the plan development and 

submittal process. The EPA will use information from this 

outreach process to inform the training and other tools will be 

of most use to the state, tribes, and territories that are 

implementing the final rule. 

The EPA has worked with communities, states, tribes and 

relevant associations to develop an extensive training plan that 

will continue in the months after the Clean Power Plan is 

finalized. The EPA has assembled resources from a variety of 

sources to create a comprehensive training curriculum for those 

implementing the Clean Power Plan. Recorded presentations from 

the EPA, DOE and other federal entities will be available for 

communities, states, and others involved in composing and 

participating in the development of state plans. This curriculum 

is available online at EPA’s Air Pollution Training Institute. 

The EPA also expects to issue guidance on specific topics. 

As guidance documents, tools, templates and other resources 

become available, the EPA, in consultation with the U.S. 

Department of Energy and other federal agencies, will continue 

to make these resources available via a dedicated website.35 

 

35 www.epa.gov/cleanpowerplantoolbox. 
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We intend to continue to work actively with states, U.S. 

territories and tribes to provide information and technical 

support that will be helpful to them in developing and 

implementing their plans. 

Additional detail on aspects of the final rule is 

included in several technical support documents (TSDs) and 

memoranda that are available in the rulemaking docket. 

5. Projected national-level emission reductions 

Under the final guidelines, the EPA projects annual CO2

reductions of [X}22 to 23 percent below 2005 levels in 

2020, [X}28 to 29 percent below 2005 levels in 2025, and 

[X]32 percent below 2005 levels in 2030. These guidelines 

will also result in important reductions in emissions of 

criteria air pollutants, including sulfur dioxide (SO2), 

nitrogen oxides (NOX), and directly emitted fine particulate 

matter (PM2.5). A thorough discussion of the EPA’s analysis 

is presented in Section XI.A of this preamble and in 

Chapter 3 of the Regulatory Impact Analysis (RIA) included 

in the docket for this rulemaking. 

67. Costs and benefits 

Actions taken to comply with the final guidelines will 

reduce emissions of CO2 and other air pollutants, including 

SO2, NOX, and directly emitted PM2.5 from the utility power 
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sector. States will make the ultimate determination as to 

how the emission guidelines are implemented. Thus, all 

costs and benefits reported for this action are 

illustrative estimates. The illustrative costs and benefits 

are based upon compliance approaches that reflect a range 

of measures consisting of improved operations at EGUs, 

dispatching lower-emitting EGUs and zero-emitting energy 

sources, and increasing levels of end-use energy 

efficiency. 

The EPA estimates that, in 2020, Because of the final 

guidelinesrange of choices available to states and the lack 

of a priori knowledge about the specific choices states

will yield monetized make in response to the final goals, 

the RIA for this final action presents two scenarios 

designed to achieve these goals, which we term the “ratebased” illustrative plan approach and the “mass-based” 

illustrative plan approach. 

In summary, we estimate the total combined climate benefits 

of approximately $[X]and health co-benefits for the rate-based 

approach to be $3.5 to $4.6 billion (2011$) using a in 2020, $18 

to $28 billion in 2025, and $34 to $54 billion in 2030 (3 

percent discount rate (model average) relative to the , 2011$). 

Total combined climate benefits and health co-benefits for the 
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mass-based approach are estimated to be $5.3 to $8.1 billion in 

2020 base case (Table 1).36 The air pollution health co-benefits 

associated with reducing exposure to ambient PM2.5 and ozone 

through , $19 to $29 billion in 2025, and $32 to $48 billion in 

2030 (3 percent discount rate, 2011$). A summary of the emission 

reductions of precursor pollutants in 2025 relative to the 2020 

base case are estimated to be $[X] billion to $[X] billion using 

a 3 percent discount rate and $[X] billion to $[X] billion 

(2011$) using a 7 percentand monetized benefits estimated for 

this rule at all discount raterates is provided in Tables 15 

through 22 of this preamble. 

In 2025, the final guidelines will yield monetized climate 

benefits of approximately $[X] billion (2011$) using a 3 percent 

discount rate (model average) relative to the 2025 base case 

(Table 1). The air pollution health co-benefits in 2025 relative 

to the 2025 base case are estimated to be $[X] billion to $[X] 

 

36 The EPA has used social cost of carbon (SCC) estimates — i.e., 

the monetary value of impacts associated with a marginal change 

in CO2 emissions in a given year — to analyze the benefits from 

changes in CO2 emissions expected from this rulemaking. The four 

SCC estimates are associated with different discount rates 

(model average at 2.5 percent discount rate, 3 percent, and 5 

percent; 95th percentile at 3 percent), and each increases over 

time. In this summary, the EPA provides the estimate of climate 

benefits associated with the SCC value deemed to be central: the 

model average at 3 percent discount rate. 
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billion using a 3 percent discount rate and $[X] billion to $[X] 

billion (2011$) using a 7 percent discount rate. 

In 2030, the EPA estimates the final guidelines will yield 

monetized climate benefits of approximately $[X] billion (2011$) 

using a 3 percent discount rate (model average) relative to the 

2030. The air pollution health co-benefits in 2030 relative to 

the 2030 base case are estimated to be $[X] billion to $[X] 

billion using a 3 percent discount rate and $[X] billion to $[X] 

billion (2011$) using a 7 percent discount rate. 

The annual compliance costs are estimated using the 

Integrated Planning Model (IPM) and include demand-side energy 

efficiency program and participant costs as well as monitoring, 

reporting and recordkeeping costs. In 2020, total compliance 

costs of the final guidelines are approximately $[X]$2.5 billion 

(2011$).$) under the rate-based approach and $1.4 billion 

(2011$) under the mass-based approach. In 2025, total compliance 

costs of the final guidelines are approximately $[X] billion 

(2011$).$1.0 billion (2011$) under the rate-based approach and 

$3.0 billion (2011$) under the mass-based approach. In 2030, 

total compliance costs of the final guidelines are approximately 

$[X] billion (2011$). $8.4 billion (2011$) under the rate-based 

approach and $5.1 billion (2011$) under the mass-based approach.
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The quantified net benefits (the difference between monetized 

benefits and compliance costs) in 2020 are estimated to range 

from $[X]$1.0 billion to $[X]$2.1 billion (2011$) using a 3 

percent discount rate (model average).) under the rate-based 

approach and from $3.9 billion to $6.7 billion (2011$) using a 3 

percent discount rate (model average) under the mass-based 

approach. In 2025, the quantified net benefits (the difference 

between monetized benefits and compliance costs) in 2025 are 

estimated to range from $[X]$17 billion to $[X]$27 billion 

(2011$) using a 3 percent discount rate (model average).) under 

the rate-based approach and from $16 billion to $26 billion 

(2011$) using a 3 percent discount rate (model average) under 

the mass-based approach. In 2030, the quantified net benefits 

(the difference between monetized benefits and compliance costs) 

in 2030 are estimated to range from $[X]$26 billion to $[X]$45

billion (2011$) using a 3 percent discount rate (model 

average).) under the rate-based approach and from $26 billion to 

$43 billion (2011$) using a 3 percent discount rate (model 

average) under the mass-based approach.

Table 1. Summary of the Monetized Benefits, Compliance Costs, 

and Net Benefits for the Final Guidelines in 2020, 2025, and 
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2030a Under the Rate-Based Illustrative Plan Approach [Billions 

of 2011$] 

Final GuidelinesRate-based Approach, 2020 

 3% Discount Rate 7% Discount rate 

Climate benefits b $[X]$2.8

Air pollution health 

co-benefits c

$[X]$0.70 to 

$[X]$1.8

$[X]$0.64 to 

$[X]$1.7

Total Compliance 

Costs d $[X]$2.5 $[X]$2.5

Net Monetized 

Benefits e $[X]$1.0 to $[X]$2.1 $[X]$1.0 to $[X]$2.0

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and 

SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

Final Guidelines, 2025 

 3% Discount rate 7% Discount rate 

Climate benefits b $[X] 

Air pollution health 

co-benefits c $[X] to $[X] $[X] to $[X] 

Total Compliance 

Costs d $[X] $[X] 

Net Monetized 

Benefits e $[X] to $[X] $[X] to $[X] 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and 

SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

Rate-based Approach, 2025 
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 3% Discount rate 7% Discount rate 

Climate benefits b $10 

Air pollution health 

co-benefits c $7.4 to $18 $6.7 to $16 

Total Compliance 

Costs d $1.0 $1.0 

Net Monetized 

Benefits e $17 to $27 $16 to $25 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and 

SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

Final GuidelinesRate-based Approach, 2030 

Climate benefits b $[X]$20

Air pollution health 

co-benefits c $[X]$14 to $[X]$34 $[X]$13 to $[X]$31

Total Compliance 

Costs d $[X]$8.4 $[X]$8.4

Net Monetized 

Benefits e $[X]$26 to $[X]$45 $[X]$25 to $[X]$43

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 

and SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

a All are rounded to two significant figures, so figures may not 

sum. 

b The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to SC-CO2 than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 
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average SCC estimated for a 3% percent discount rate, however we 

emphasize the importance and value of considering the full range 

of SC-CO2 values. As shown in the RIA, climate benefits are also 

estimated using the other three SC-CO2 estimates (model average 

at 2.5 percent discount rate, 3 percent, and 5 percent; 95th

percentile at 3 percent). The SC-CO2 estimates are year-specific 

and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

final guidelines and a discount rate of approximately 5%. This 

estimate includes monitoring, recordkeeping, and reporting costs 

and demand -side energy efficiency program and participant 

costs. 

e The estimates of net benefits in this summary table are 

calculated using the global SC-CO2 at a 3 percent discount rate 

(model average). The RIA includes combined climate and health 

estimates based on additional discount rates. 

Table 2.There are additional important benefits that the EPA 

could not monetize. Due to current data and modeling 

limitations, our estimates of the benefits from reducing CO2

emissions do not include important impacts like ocean 

acidification or potential tipping points in natural or managed 

ecosystems. Summary of the Monetized Benefits, Compliance 

Costs, and Net Benefits for the Final Guidelines in 2020, 2025 

and 2030a
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Under the Mass-Based Illustrative Plan Approach [Billions of 

2011$] 

Mass-based Approach, 2020 

 3% Discount Rate 7% Discount rate 

Climate benefits b $3.3 

Air pollution health 

co-benefits c $2.0 to $4.8 $1.8 to $4.4 

Total Compliance 

Costs d $1.4 $1.4 

Net Monetized 

Benefits e $3.9 to $6.7 $3.7 to $6.3 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and 

SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

Mass-based Approach, 2025 

 3% Discount rate 7% Discount rate 

Climate benefits b $12 

Air pollution health 

co-benefits c $7.1 to $17 $6.5 to $16 

Total Compliance 

Costs d $3.0 $3.0 

Net Monetized 

Benefits e $16 to $26 $15 to $24 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and 

SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

Mass-based Approach, 2030 
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Climate benefits b $20 

Air pollution health 

co-benefits c $12 to $28 $11 to $26 

Total Compliance 

Costs d $5.1 $5.1 

Net Monetized 

Benefits e $26 to $43 $25 to $40 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 

and SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

a All are rounded to two significant figures, so figures may not 

sum. 

b The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to SC-CO2 than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SC-CO2 estimated for a 3 percent discount rate, however 

we emphasize the importance and value of considering the full 

range of SC-CO2 values. As shown in the RIA, climate benefits are 

also estimated using the other three SC-CO2 estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SC-CO2 estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 
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final guidelines and a discount rate of approximately 5 percent. 

This estimate includes monitoring, recordkeeping, and reporting 

costs and demand-side energy efficiency program and participant 

costs. 

e The estimates of net benefits in this summary table are 

calculated using the global SC-CO2 at a 3 percent discount rate 

(model average). The RIA includes combined climate and health 

estimates based on additional discount rates. 

There are additional important benefits that the EPA 

could not monetize. Due to current data and modeling 

limitations, our estimates of the benefits from reducing CO2

emissions do not include important impacts like ocean 

acidification or potential tipping points in natural or 

managed ecosystems. The unquantified benefits also include 

climate benefits from reducing emissions of non-CO2

greenhouse gasesGHGs (e.g., nitrous oxide and methane)37 and 

co-benefits from reducing direct exposure to SO2, NOX, and 

hazardous air pollutants (e.g., mercury and hydrogen 

chloride), as well as from reducing ecosystem effects and 

visibility impairment. 

We project employment gains and losses relative to 

base case for different types of labor, including 

 

37 Although CO2 is the predominant greenhouse gas released by the 

power sector, electricity generating units also emit small 

amounts of nitrous oxide and methane. For more detail about 

power sector emissions, see RIA Chapter 2 and the U.S. 

Greenhouse Gas Reporting Program’s power sector summary, 

http://www.epa.gov/ghgreporting/ghgdata/reported/powerplants.htm

l.
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construction, plant operation and maintenance, coal and 

natural gas production, and demand -side energy efficiency. 

In [X],2030, we project a net change of [X] decrease in 

job-years of about 31,000 under the rate-based approach and 

34,000 under the mass-based approach38 for construction, 

plant operation and maintenance, and coal and natural gas 

and [X]a gain of 52,000 to 83,000 jobs in the demand-side 

energy efficiency sector under either approach. Actual 

employment impacts will depend upon measures taken by 

states in their state plans and the specific actions 

sources take to comply. 

Based upon the foregoing, it is clear that the monetized 

benefits of this rule are substantial and far outweigh the 

costs. 

B. Organization and Approach for this Rule 

This final rule establishes the EPA’s emission guidelines 

for states to follow in developing plans to reduce CO2 emissions 

from the utility power sector. Section II of this preamble 

provides background information on climate change impacts from 

 

38 A job-year is not an individual job; rather, a job-year is the 

amount of work performed by the equivalent of one full-time 

individual for one year. For example, 20 job-years in 2025 may 

represent 20 full-time jobs or 40 half-time jobs. 
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GHG emissions, GHG emissions from fossil fuel-fired EGUs, the 

utility power sector, the CAA section 111(d) requirements, EPA 

actions prior to this final action, outreach and consultations, 

and the number and extent of comments received. In Section III 

of the preamble, we present a summary of the rule requirements 

and the legal basis for these. Section IV explains the EPA 

authority to regulate CO2 and EGUs, identifies affected EGUs, and 

describes the proposed treatment of source categories. Section V 

describes the agency’s determination of the BSER using fourthree

building blocks for setting state goals and our key 

considerations in doing so.making the determination. Section VI 

provides the source categorysubcategory-specific emission 

performance rates, and Section VII provides equivalent statewide 

rate-based and mass-based goals. Section VIII then describes 

state plan approaches and the requirements, and flexibilities, 

for state plans, followed by Section IX, in which considerations 

for communities are described. Interactions between this final 

rule and other EPA programs and rules are discussed in Section 

X. Impacts of the proposed action are then described in Section 

XI, followed by a discussion of statutory and executive order 

reviews in Section XII and the statutory authority for this 

action in Section XIIXIII. 
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We note that this rulemaking is being promulgated 

concurrently with atwo related rulemaking,rulemakings: the final 

new source performance standards (NSPS) for CO2 emissions from 

newly constructed, modified, and reconstructed EGUs [INSERT THE 

FEDERAL REGISTER REFERENCE FOR THE FINAL GHG NEW SOURCE RULE], 

which is being promulgated under CAA section 111(b). This 

rulemaking has its own rulemaking docket), and the proposed 

federal plan and model rules [INSERT THE FEDERAL REGISTER 

REFERENCE FOR THE FEDERAL PLAN PROPOSAL]. These rulemakings have 

their own rulemaking dockets. 

II. Background 

In this section, we discuss climate change impacts from GHG 

emissions, both on public health and public welfare. We also 

present information about GHG emissions from fossil fuel-fired 

EGUs, explainthe challenges associated with controlling carbon 

dioxide emisions, the uniqueness of the utility power sector,

and describe recentdrecent and continuing trends and transitions 

in thisthe utility power sector. In addition, we briefly

describe CAA regulations for power plants, provide highlights of 

Congressional awareness of climate change and international 

agreements and actions, and summarize the statutory and 

regulatory requirements relevant to this rulemaking. In 

addition, we provide background information on the EPA’s June 
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18, 2014 Clean Power Plan proposal, the November 4, 2014 

supplemental proposal, and other actions associated with this 

rulemaking,39 followed by information on stakeholder outreach and 

consultations and the comments that the EPA received prior to 

issuing this final rulemaking. 

A. Climate Change Impacts from GHG Emissions 

According to the National Research Council, “Emissions 

of CO2 from the burning of fossil fuels have ushered in a 

new epoch where human activities will largely determine the 

evolution of Earth’s climate. Because CO2 in the atmosphere 

is long lived, it can effectively lock Earth and future 

generations into a range of impacts, some of which could 

become very severe. Therefore, emission reduction choices 

made today matter in determining impacts experienced not 

just over the next few decades, but in the coming centuries 

and millennia.”40 

In 2009, based on a large body of robust and compelling 

scientific evidence, the EPA Administrator issued the 

 

39 The EPA also published in the Federal Register a notice of 

data availability (79 FR 64543; November 8, 2014) and a notice 

on the translation of emission rate-based CO2 goals to mass-based 

equivalents (79 FR 67406; November 13, 2014). 

40 National Research Council, Climate Stabilization Targets, p.3. 
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Endangerment Finding under CAA section 202(a)(1).41 In the 

Endangerment Finding, the Administrator found that the current, 

elevated concentrations of GHGs in the atmosphere—already at 

levels unprecedented in human history—may reasonably be 

anticipated to endanger public health and welfare of current and 

future generations in the United States. We summarize these 

adverse effects on public health and welfare briefly here. 

1. Public health impacts detailed in the 2009 Endangerment 

Finding 

Climate change caused by human emissions of GHGs threatens 

the health of Americans in multiple ways. By raising average 

temperatures, climate change increases the likelihood of heat 

waves, which are associated with increased deaths and illnesses. 

While climate change also increases the likelihood of reductions 

in cold-related mortality, evidence indicates that the increases 

in heat mortality will be larger than the decreases in cold 

mortality in the United States. Compared to a future without 

climate change, climate change is expected to increase ozone 

pollution over broad areas of the U.S., includingespecially on 

the highest ozone days and in the largest metropolitan areas 

 

41 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases Under Section 202(a) of the Clean Air Act,” 74 Fed. Reg. 

66,496FR 66496 (Dec. 15, 2009) (“Endangerment Finding”).
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with the worst ozone problems, and thereby increase the risk of 

morbidity and mortality. Climate change is also expected to 

cause more intense hurricanes and more frequent and intense 

storms and heavy precipitation, with impacts on other areas of 

public health, such as the potential for increased deaths, 

injuries, infectious and waterborne diseases, and stress-related 

disorders. Children, the elderly, and the poor are among the 

most vulnerable to these climate-related health effects. 

2. Public welfare impacts detailed in the 2009 Endangerment 

Finding 

Climate change impacts touch nearly every aspect of public 

welfare. Among the multiple threats caused by human emissions of 

GHGs, climate changes are expected to place large areas of the 

country at serious risk of reduced water supplies, increased 

water pollution, and increased occurrence of extreme events such 

as floods and droughts. Coastal areas are expected to face a 

multitude of increased risks, particularly from rising sea level 

and increases in the severity of storms. These communities face 

storm and flooding damage to property, or even loss of land due 

to inundation, erosion, wetland submergence and habitat loss. 

Impacts of climate change on public welfare also include 

threats to social and ecosystem services. Climate change is 

expected to result in an increase in peak electricity demand. 
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Extreme weather from climate change threatens energy, 

transportation, and water resource infrastructure. Climate 

change may also exacerbate ongoing environmental pressures in 

certain settlements, particularly in Alaskan indigenous 

communities, and is very likely to fundamentally rearrange U.S. 

ecosystems over the 21st century. Though some benefits may 

balance adverse effects on agriculture and forestry in the next 

few decades, the body of evidence points towards increasing 

risks of net adverse impacts on U.S. food production, 

agriculture and forest productivity as temperature continues to 

rise. These impacts are global and may exacerbate problems 

outside the U.S. that raise humanitarian, trade, and national 

security issues for the U.S. 

3. New scientific assessments and observations 

Since the administrative record concerning the Endangerment 

Finding closed following the EPA’s 2010 Reconsideration Denial, 

the climate has continued to change, with new records being set 

for a number of climate indicators such as global average 

surface temperatures, Arctic sea ice retreat, CO2 concentrations, 

and sea level rise. Additionally, a number of major scientific 

assessments have been released that improve understanding of the 

climate system and strengthen the case that GHGs endanger public 

health and welfare both for current and future generations. 
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These assessments, from the Intergovernmental Panel on Climate 

Change (IPCC), the U.S. Global Change Research Program (USGCRP), 

and the National Research Council (NRC), include: IPCC’s 2012 

Special Report on Managing the Risks of Extreme Events and 

Disasters to Advance Climate Change Adaptation (SREX) and the 

2013-2014 Fifth Assessment Report (AR5), the USGCRP’s 2014 

National Climate Assessment, Climate Change Impacts in the 

United States (NCA3), and the NRC’s 2010 Ocean Acidification: A 

National Strategy to Meet the Challenges of a Changing Ocean

(Ocean Acidification), 2011 Report on Climate Stabilization 

Targets: Emissions, Concentrations, and Impacts over Decades to 

Millennia (Climate Stabilization Targets), 2011 National 

Security Implications for U.S. Naval Forces (National Security 

Implications), 2011 Understanding Earth’s Deep Past: Lessons for 

Our Climate Future (Understanding Earth’s Deep Past), 2012 Sea 

Level Rise for the Coasts of California, Oregon, and Washington: 

Past, Present, and Future, 2012 Climate and Social Stress: 

Implications for Security Analysis (Climate and Social Stress), 

and 2013 Abrupt Impacts of Climate Change (Abrupt Impacts) 

assessments. 

The EPA has carefully reviewed these recent assessments in 

keeping with the same approach outlined in Section VIII.A of the 

2009 Endangerment Finding, which was to rely primarily upon the 
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major assessments by the USGCRP, the IPCC, and the NRC of the 

National Academies to provide the technical and scientific 

information to inform the Administrator’s judgment regarding the 

question of whether GHGs endanger public health and welfare. 

These assessments addressed the scientific issues that the EPA 

was required to examine, were comprehensive in their coverage of 

the GHG and climate change issues, and underwent rigorous and 

exacting peer review by the expert community, as well as 

rigorous levels of U.S. government review. 

The findings of the recent scientific assessments confirm 

and strengthen the conclusion that GHGs endanger public health, 

now and in the future. The NCA3 indicates that human health in 

the United States will be impacted by “increased extreme weather 

events, wildfire, decreased air quality, threats to mental 

health, and illnesses transmitted by food, water, and diseasecarriers such as mosquitoes and ticks.” The most recent 

assessments now have greater confidence that climate change will 

influence production of pollen that exacerbates asthma and other 

allergic respiratory diseases such as allergic rhinitis, as well 

as effects on conjunctivitis and dermatitis. Both the NCA3 and 

the IPCC AR5 found that increasing temperature has lengthened 

the allergenic pollen season for ragweed, and that increased CO2

by itself can elevate production of plant-based allergens. 
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The NCA3 also finds that climate change, in addition to 

chronic stresses such as extreme poverty, is negatively 

affecting indigenous peoples’ health in the United States 

through impacts such as reduced access to traditional foods, 

decreased water quality, and increasing exposure to health and 

safety hazards. The IPCC AR5 finds that climate change-induced 

warming in the Arctic and resultant changes in environment 

(e.g., permafrost thaw, effects on traditional food sources) 

have significant impacts, observed now and projected, on the 

health and well-being of Arctic residents, especially indigenous 

peoples. Small, remote, predominantly-indigenous communities are 

especially vulnerable given their “strong dependence on the 

environment for food, culture, and way of life; their political 

and economic marginalization; existing social, health, and 

poverty disparities; as well as their frequent close proximity 

to exposed locations along ocean, lake, or river shorelines.”42 

In addition, increasing temperatures and loss of Arctic sea ice 

 

42 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part B: Regional Aspects. Contribution of Working 

Group II to the Fifth Assessment Report of the Intergovernmental 

Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, 

M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. 

Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 

Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 

Cambridge University Press, Cambridge, p. 1581. 
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increases the risk of drowning for those engaged in traditional 

hunting and fishing. 

 The NCA3 concludes that children’s unique physiology and 

developing bodies contribute to making them particularly 

vulnerable to climate change. Impacts on children are expected 

from heat waves, air pollution, infectious and waterborne 

illnesses, and mental health effects resulting from extreme 

weather events. The IPCC AR5 indicates that children are among 

those especially susceptible to most allergic diseases, as well 

as health effects associated with heat waves, storms, and 

floods. The IPCC finds that additional health concerns may arise 

in low income households, especially those with children, if 

climate change reduces food availability and increases prices, 

leading to food insecurity within households. 

Both the NCA3 and IPCC AR5 conclude that climate change 

will increase health risks facing the elderly. Older people are 

at much higher risk of mortality during extreme heat events. 

Pre-existing health conditions also make older adults 

susceptible to cardiac and respiratory impacts of air pollution 

and to more severe consequences from infectious and waterborne 

diseases. Limited mobility among older adults can also increase 

health risks associated with extreme weather and floods. 
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The new assessments also confirm and strengthen the 

conclusion that GHGs endanger public welfare, and emphasize the 

urgency of reducing GHG emissions due to their projections that 

show GHG concentrations climbing to ever-increasing levels in 

the absence of mitigation. The NRC assessment Understanding 

Earth’s Deep Past projected that, without a reduction in 

emissions, CO2 concentrations by the end of the century would 

increase to levels that the Earth has not experienced for more 

than 30 million years.43 In fact, that assessment stated that 

“the magnitude and rate of the present greenhouse gas increase 

place the climate system in what could be one of the most severe 

increases in radiative forcing of the global climate system in 

Earth history.”44 Because of these unprecedented changes, several 

assessments state that we may be approaching critical, poorly 

understood thresholds: as stated in the NRC assessment 

Understanding Earth’s Deep Past, “As Earth continues to warm, it 

may be approaching a critical climate threshold beyond which 

rapid and potentially permanent—at least on a human timescale—

changes not anticipated by climate models tuned to modern 

conditions may occur.”. As stated in the assessment, “As Earth 

 

43 National Research Council, Understanding Earth’s Deep Past, p. 

1.

44 Id., p.138.
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continues to warm, it may be approaching a critical climate 

threshold beyond which rapid and potentially permanent—at least 

on a human timescale—changes not anticipated by climate models 

tuned to modern conditions may occur.” The NRC Abrupt Impacts 

report analyzed abrupt climate change in the physical climate 

system and abrupt impacts of ongoing changes that, when 

thresholds are crossed, can cause abrupt impacts for society and 

ecosystems. The report considered destabilization of the West 

Antarctic Ice Sheet (which could cause 3-4 m of potential sea 

level rise) as an abrupt climate impact with unknown but 

probably low probability of occurring this century. The report 

categorized a decrease in ocean oxygen content (with attendant 

threats to aerobic marine life); increase in intensity, 

frequency, and duration of heat waves; and increase in frequency 

and intensity of extreme precipitation events (droughts, floods, 

hurricanes, and major storms) as climate impacts with moderate 

risk of an abrupt change within this century. The NRC Abrupt 

Impacts report also analyzed the threat of rapid state changes 

in ecosystems and species extinctions as examples of an 

irreversible impact that is expected to be exacerbated by 

climate change. Species at most risk include those whose 

migration potential is limited, whether because they live on 

mountaintops or fragmented habitats with barriers to movement, 
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or because climatic conditions are changing more rapidly than 

the species can move or adapt. While the NRC determined that it 

is not presently possible to place exact probabilities on the 

added contribution of climate change to extinction, they did 

find that there was substantial risk that impacts from climate 

change could, within a few decades, drop the populations in many 

species below sustainable levels thereby committing the species 

to extinction. Species within tropical and subtropical 

rainforests such as the Amazon and species living in coral reef 

ecosystems were identified by the NRC as being particularly 

vulnerable to extinction over the next 30 to 80 years, as were 

species in high latitude and high elevation regions. Moreover, 

due to the time lags inherent in the Earth’s climate, the NRC 

Climate Stabilization Targets assessment notes that the full 

warming from any given concentration of CO2 reached will not be 

fully realized for several centuries, underscoring that emission 

activities today carry with them climate commitments far into 

the future. 

Future temperature changes will depend on what emission 

path the world follows. In its high emission scenario, the IPCC 

AR5 projects that global temperatures by the end of the century 

will likely be 2.6 °C to 4.8 °C (4.7 to 8.6 °F) warmer than 

today. Temperatures on land and in northern latitudes will 
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likely warm even faster than the global average. However, 

according to the NCA3, significant reductions in emissions would 

lead to noticeably less future warming beyond mid-century, and 

therefore less impact to public health and welfare. 

While rainfall may only see small globally and annually 

averaged changes, there are expected to be substantial shifts in 

where and when that precipitation falls. According to the NCA3, 

regions closer to the poles will see more precipitation, while 

the dry subtropics are expected to expand (colloquially, this 

has been summarized as wet areas getting wetter and dry regions 

getting drier). In particular, the NCA3 notes that the western 

U.S., and especially the Southwest, is expected to become drier. 

This projection is consistent with the recent observed drought 

trend in the West. At the time of publication of the NCA, even 

before the last 2 years of extreme drought in California, tree 

ring data was already indicating that the region might be 

experiencing its driest period in 800 years. Similarly, the NCA3 

projects that heavy downpours are expected to increase in many 

regions, with precipitation events in general becoming less 

frequent but more intense. This trend has already been observed 

in regions such as the Midwest, Northeast, and upper Great 

Plains. Meanwhile, the NRC Climate Stabilization Targets 

assessment found that the area burned by wildfire is expected to 
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grow by 2 to 4 times for 1 °C (1.8 °F) of warming. For 3 °C of 

warming, the assessment found that 9 out of 10 summers would be 

warmer than all but the 5 percent of warmest summers today, 

leading to increased frequency, duration, and intensity of heat 

waves. Extrapolations by the NCA also indicate that Arctic sea 

ice in summer may essentially disappear by mid-century. 

Retreating snow and ice, and emissions of carbon dioxide and 

methane released from thawing permafrost, will also amplify 

future warming. 

Since the 2009 Endangerment Finding, the USGCRP NCA3, and 

multiple NRC assessments have projected future rates of sea 

level rise that are 40 percent larger to more than twice as 

large as the previous estimates from the 2007 IPCC 4th Assessment 

Report due in part to improved understanding of the future rate 

of melt of the Antarctic and Greenland Ice sheets. The NRC Sea 

Level Rise assessment projects a global sea level rise of 0.5 to 

1.4 meters (1.6 to 4.6 feet) by 2100, the NRC National Security 

Implications assessment suggests that “the Department of the 

Navy should expect roughly 0.4 to 2 meters [1.3 to 6.6 feet] 

global average sea-level rise by 2100,”45 and the NRC Climate 

Stabilization Targets assessment states that an increase of 3°C 

 

45 NRC, 2011: National Security Implications of Climate Change 

for U.S. Naval Forces. The National Academies Press, p. 28. 
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will lead to a sea level rise of 0.5 to 1 meter (1.6 to 3.3 

feet) by 2100. These assessments continue to recognize that 

there is uncertainty inherent in accounting for ice sheet 

processes. Additionally, local sea level rise can differ from 

the global total depending on various factors: the east coast of 

the U.S. in particular is expected to see higher rates of sea 

level rise than the global average. For comparison, the NCA3 

states that “five million Americans and hundreds of billions of 

dollars of property are located in areas that are less than four 

feet above the local high-tide level,” and the NCA3 finds that 

“[c]oastal infrastructure, including roads, rail lines, energy 

infrastructure, airports, port facilities, and military bases, 

are increasingly at risk from sea level rise and damaging storm 

surges.”46 Also, because of the inertia of the oceans, sea level 

rise will continue for centuries after greenhouse gas 

concentrations have stabilized (though more slowly than it would 

have otherwise). Additionally, there is a threshold temperature 

above which the Greenland ice sheet will be committed to 

inevitable melting: according to the NCA, some recent research 

 

46 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 

Eds., 2014: Climate Change Impacts in the United States: The 

Third National Climate Assessment. U.S. Global Change Research 

Program, p. 9. 
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has suggested that even present day carbon dioxide levels could 

be sufficient to exceed that threshold. 

In general, climate change impacts are expected to be 

unevenly distributed across different regions of the United 

States and have a greater impact on certain populations, such as 

indigenous peoples and the poor. The NCA3 finds climate change 

impacts such as the rapid pace of temperature rise, coastal 

erosion and inundation related to sea level rise and storms, ice 

and snow melt, and permafrost thaw are affecting indigenous 

people in the United States. Particularly in Alaska, critical 

infrastructure and traditional livelihoods are threatened by 

climate change and, “[i]n parts of Alaska, Louisiana, the 

Pacific Islands, and other coastal locations, climate change 

impacts (through erosion and inundation) are so severe that some 

communities are already relocating from historical homelands to 

which their traditions and cultural identities are tied.”47 The 

IPCC AR5 notes, “Climate-related hazards exacerbate other 

stressors, often with negative outcomes for livelihoods, 

especially for people living in poverty (high confidence). 

 

47 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 

Eds., 2014: Climate Change Impacts in the United States: The 

Third National Climate Assessment. U.S. Global Change Research 

Program, p. 17. 
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Climate-related hazards affect poor people’s lives directly 

through impacts on livelihoods, reductions in crop yields, or 

destruction of homes and indirectly through, for example, 

increased food prices and food insecurity.”48 

Carbon dioxide in particular has unique impacts on ocean 

ecosystems. The NRC Climate Stabilization Targets assessment 

found that coral bleaching will increase due both to warming and 

ocean acidification. Ocean surface waters have already become 

30% percent more acidic over the past 250 years due to 

absorption of CO2 from the atmosphere. According to the NCA3, 

this acidification will reduce the ability of organisms such as 

corals, krill, oysters, clams, and crabs to survive, grow, and 

reproduce. The NRC Understanding Earth's Deep Past assessment 

notes four of the five major coral reef crises of the past 500 

million years were caused by acidification and warming that 

followed GHG increases of similar magnitude to the emissions 

increases expected over the next hundred years. The NRC Abrupt 

Impacts assessment specifically highlighted similarities between 

 

48 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part A: Global and Sectoral Aspects. Contribution 

of Working Group II to the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change [Field, C.B., V.R. 

Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. 

Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. 

Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, p. 796. 
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the projections for future acidification and warming and the 

extinction at the end of the Permian which resulted in the loss 

of an estimated 90 percent of known species. Similarly, the NRC 

Ocean Acidification assessment finds that “[t]he chemistry of 

the ocean is changing at an unprecedented rate and magnitude due 

to anthropogenic carbon dioxide emissions; the rate of change 

exceeds any known to have occurred for at least the past 

hundreds of thousands of years.”49 The assessment notes that the 

full range of consequences is still unknown, but the risks 

“threaten coral reefs, fisheries, protected species, and other 

natural resources of value to society.”50 

Events outside the United States, as also pointed out in 

the 2009 Endangerment Finding, will also have relevant 

consequences. The NRC Climate and Social Stress assessment 

concluded that it is prudent to expect that some climate events 

“will produce consequences that exceed the capacity of the 

affected societies or global systems to manage and that have 

global security implications serious enough to compel 

international response.” The NRC National Security Implications 

assessment recommends preparing for increased needs for 

 

49 NRC, 2010: Ocean Acidification: A National Strategy to Meet 

the Challenges of a Changing Ocean. The National Academies 

Press, p. 5. 

50 Ibid. 
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humanitarian aid; responding to the effects of climate change in 

geopolitical hotspots, including possible mass migrations; and 

addressing changing security needs in the Arctic as sea ice 

retreats. 

In addition to future impacts, the NCA3 emphasizes that 

climate change driven by human emissions of GHGs is already 

happening now and it is happening in the United States. 

According to the IPCC AR5 and the NCA3, there are a number of 

climate-related changes that have been observed recently, and 

these changes are projected to accelerate in the future. The 

planet warmed about 0.85 °C (1.5 °F) from 1880 to 2012. It is 

extremely likely (>95% percent probability) that human influence 

was the dominant cause of the observed warming since the mid-20th

century, and likely (>66% percent probability) that human 

influence has more than doubled the probability of occurrence of 

heat waves in some locations. In the Northern Hemisphere, the 

last 30 years were likely the warmest 30 year period of the last 

1400 years. U.S. average temperatures have similarly increased 

by 1.3 to 1.9 degrees F since 1895, with most of that increase 

occurring since 1970. Global sea levels rose 0.19 m (7.5 inches) 

from 1901 to 2010. Contributing to this rise was the warming of 

the oceans and melting of land ice. It is likely that 275 

gigatons per year of ice melted from land glaciers (not 
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including ice sheets) since 1993, and that the rate of loss of 

ice from the Greenland and Antarctic ice sheets increased 

substantially in recent years, to 215 gigatons per year and 147 

gigatons per year respectively since 2002. For context, 360 

gigatons of ice melt is sufficient to cause global sea levels to 

rise 1 mm. Annual mean Arctic sea ice has been declining at 3.5 

to 4.1 percent per decade, and Northern Hemisphere snow cover 

extent has decreased at about 1.6 percent per decade for March 

and 11.7 percent per decade for June. Permafrost temperatures 

have increased in most regions since the 1980s, by up to 3 °C 

(5.4 °F) in parts of Northern Alaska. Winter storm frequency and 

intensity have both increased in the Northern Hemisphere. The 

NCA3 states that the increases in the severity or frequency of 

some types of extreme weather and climate events in recent 

decades can affect energy production and delivery, causing 

supply disruptions, and compromise other essential 

infrastructure such as water and transportation systems. 

In addition to the changes documented in the assessment 

literature, there have been other climate milestones of note. In 

2009, the year of the Endangerment Finding, the average 

concentration of CO2 as measured on top of Mauna Loa was 387 

parts per million, far above preindustrial concentrations of 
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about 280 parts per million.51 The average concentration in 2013, 

the last full year before this rule was proposed, was 396 parts 

per million. The average concentration in 2014 was 399 parts per 

million. And the monthly concentration in April of 2014 was 401 

parts per million, the first time a monthly average has exceeded 

400 parts per million since record keeping began at Mauna Loa in 

1958, and for at least the past 800,000 years.52 Arctic sea ice 

has continued to decline, with September of 2012 marking a new 

record low in terms of Arctic sea ice extent, 40 percent below 

the 1979-2000 median. Sea level has continued to rise at a rate 

of 3.2 mm per year (1.3 inches/decade) since satellite 

observations started in 1993, more than twice the average rate 

of rise in the 20th century prior to 1993.53 And 2014 was the 

warmest year globally in the modern global surface temperature 

record, going back to 1880; this now means 19 of the 20 warmest 

years have occurred in the past 20 years, and except for 1998, 

the ten warmest years on record have occurred since 2002.54 The 

first months of 2015 have also been some of the warmest on 

record. 

 

51ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.tx

t

52 http://www.esrl.noaa.gov/gmd/ccgg/trends/

53 Blunden, J., and D. S. Arndt, Eds., 2014: State of the Climate 

in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238. 

54 http://www.ncdc.noaa.gov/sotc/global/2014/13 
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These assessments and observed changes make it clear that 

reducing emissions of GHGs across the globe is necessary in 

order to avoid the worst impacts of climate change, and 

underscore the urgency of reducing emissions now. The NRC 

Committee on America’s Climate Choices listed a number of 

reasons “why it is imprudent to delay actions that at least 

begin the process of substantially reducing emissions.”55 For 

example: 

 The faster emissions are reduced, the lower the risks 

posed by climate change. Delays in reducing emissions 

could commit the planet to a wide range of adverse 

impacts, especially if the sensitivity of the climate to 

greenhouse gases is on the higher end of the estimated 

range. 

 Waiting for unacceptable impacts to occur before taking 

action is imprudent because the effects of greenhouse gas 

emissions do not fully manifest themselves for decades 

and, once manifest, many of these changes will persist 

for hundreds or even thousands of years. 

 In the committee’s judgment, the risks associated with 

doing business as usual are a much greater concern than 

the risks associated with engaging in strong response 

efforts. 

4. Observed and Projected U.S. Regional Changes 

The NCA3 assessed the climate impacts in 8 regions of the 

United States, noting that changes in physical climate 

 

55 NRC, 2011: America’s Climate Choices, The National Academies 

Press. 
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parameters such as temperatures, precipitation, and sea ice 

retreat were already having impacts on forests, water supplies, 

ecosystems, flooding, heat waves, and air quality. Moreover, the 

NCA3 found that future warming is projected to be much larger 

than recent observed variations in temperature, with 

precipitation likely to increase in the northern states, 

decrease in the southern states, and with the heaviest 

precipitation events projected to increase everywhere. 

In the Northeast, temperatures increased almost 2 °F from 

1895 to 2011, precipitation increased by about 5 inches (10%), 

percent), and sea level rise of about a foot has led to an 

increase in coastal flooding. The 70% percent increase in the 

amount of rainfall falling in the 1% percent of the most intense 

events is a larger increase in extreme precipitation than 

experienced in any other USU.S. region. 

In the future, if emissions continue increasing, the 

Northeast is expected to experience 4.5 to 10 °F of warming by 

the 2080s. This will lead to more heat waves, coastal and river 

flooding, and intense precipitation events. The southern portion 

of the region is projected to see 60 additional days per year 

above 90 °F by mid-century. Sea levels in the Northeast are 

expected to increase faster than the global average because of 

subsidence, and changing ocean currents may further increase the 
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rate of sea level rise. Specific vulnerabilities highlighted by 

the NCA include large urban populations particularly vulnerable 

to climate-related heat waves and poor air quality episodes, 

prevalence of climate sensitive vector-borne diseases like Lyme 

and West Nile Virus, usage of combined sewer systems that may 

lead to untreated water being released into local water bodies 

after climate-related heavy precipitation events, and 1.6 

million people living within the 100-year coastal flood zone who 

are expected to experience more frequent floods due to sea level 

rise and tropical-storm induced storm-surge. The NCA also 

highlighted infrastructure vulnerable to inundation in coastal 

metropolitan areas, potential agricultural impacts from 

increased rain in the spring delaying planting or damaging crops 

or increased heat in the summer leading to decreased yields and 

increased water demand, and shifts in ecosystems leading to 

declines in iconic species in some regions, such as cod and 

lobster south of Cape Cod. 

In the Southeast, average annual temperature during the 

last century cycled between warm and cool periods. A warm peak 

occurred during the 1930s and 1940s followed by a cool period 

and temperatures then increased again from 1970 to the present 

by an average of 2°F. There have been increasing numbers of days 

above 95°F and nights above 75°F, and decreasing numbers of 
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extremely cold days since 1970. Daily and five-day rainfall 

intensities have also increased, and summers have been either 

increasingly dry or extremely wet. Louisiana has already lost 

1,880 square miles of land in the last 80 years due to sea level 

rise and other contributing factors. 

The Southeast is exceptionally vulnerable to sea level 

rise, extreme heat events, hurricanes, and decreased water 

availability. Major consequences of further warming include 

significant increases in the number of hot days (95°F or above) 

and decreases in freezing events, as well as exacerbated groundlevel ozone in urban areas. Although projected warming for some 

parts of the region by the year 2100 are generally smaller than 

for other regions of the United States, projected warming for 

interior states of the region are larger than coastal regions by 

1°F to 2°F. Projections further suggest that globally there will 

be fewer tropical storms, but that they will be more intense, 

with more Category 4 and 5 storms. The NCA identified New 

Orleans, Miami, Tampa, Charleston, and Virginia Beach as being 

specific cities that are at risk due to sea level rise, with 

homes and infrastructure increasingly prone to flooding. 

Additional impacts of sea level rise are expected for coastal 

highways, wetlands, fresh water supplies, and energy 

infrastructure. 
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In the Northwest, temperatures increased by about 1.3oF 

between 1895 and 2011. A small average increase in precipitation 

was observed over this time period. However, warming 

temperatures have caused increased rainfall relative to 

snowfall, which has altered water availability from snowpack 

across parts of the region. Snowpack in the Northwest is an 

important freshwater source for the region. More precipitation 

falling as rain instead of snow has reduced the snowpack, and 

warmer springs have corresponded to earlier snowpack melting and 

reduced streamflows during summer months. Drier conditions have 

increased the extent of wildfires in the region.

Average annual temperatures are projected to increase by 

3.3oF to 9.7oF by the end of the century (depending on future 

global greenhouse gas emissions), with the greatest warming is 

expected during the summer. Continued increases in global 

greenhouse gas emissions are projected to result in up to a 30% 

percent decrease in summer precipitation. Earlier snowpack melt 

and lower summer stream flows are expected by the end of the 

century and will affect drinking water supplies, agriculture, 

ecosystems, and hydropower production. Warmer waters are 

expected to increase disease and mortality in important fish 

species, including Chinook and sockeye salmon. Ocean 

acidification also threatens species such as oysters, with the 
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Northwest coastal waters already being some of the most 

acidified worldwide due to coastal upwelling and other local 

factors. Forest pests are expected to spread and wildfires burn 

larger areas. Other high-elevation ecosystems are projected to 

be lost because they can no longer survive the climatic 

conditions. Low lying coastal areas, including the cities of 

Seattle and Olympia, will experience heightened risks of sea 

level rise, erosion, seawater inundation and damage to 

infrastructure and coastal ecosystems. 

In Alaska, temperatures have changed faster than anywhere

else in the United States. Annual temperatures increased by 

about 3 °F in the past 60 years. Warming in the winter has been 

even greater, rising by an average of 6 °F. Arctic sea ice is 

thinning and shrinking in area, with the summer minimum ice 

extent now covering only half the area it did when satellite 

records began in 1979. Glaciers in Alaska are melting at some of 

the fastest rates on Earth. Permafrost soils are also warming 

and beginning to thaw. Drier conditions have contributed to more 

large wildfires in the last 10 years than in any previous decade 

since the 1940s, when recordkeeping began. Climate change 

impacts are harming the health, safety and livelihoods of Native 

Alaskan communities. 
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By the end of this century, continued increases in 

greenhouse gas emissions are expected to increase temperatures 

by 10 to 12 °F in the northernmost parts of Alaska, by 8 to 10

°F in the interior, and by 6 to 8 °F across the rest of the 

state. These increases will exacerbate ongoing arctic sea ice 

loss, glacial melt, permafrost thaw and increased wildfire, and 

threaten humans, ecosystems, and infrastructure. Precipitation 

is expected to increase to varying degrees across the state, 

however warmer air temperatures and a longer growing season are 

expected to result in drier conditions. Native Alaskans are 

expected to experience declines in economically, nutritionally, 

and culturally important wildlife and plant species. Health 

threats will also increase, including loss of clean water, 

saltwater intrusion, sewage contamination from thawing 

permafrost, and northward extension of diseases. Wildfires will 

increasingly pose threats to human health as a result of smoke 

and direct contact. Areas underlain by ice-rich permafrost 

across the state are likely to experience ground subsidence and 

extensive damage to infrastructure as the permafrost thaws. 

Important ecosystems will continue to be affected. Surface 

waters and wetlands that are drying provide breeding habitat for 

millions of waterfowl and shorebirds that winter in the lower 48 

states. Warmer ocean temperatures, acidification, and declining 
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sea ice will contribute to changes in the location and 

availability ifof commercially and culturally important marine 

fish. 

In the Southwest, temperatures are now about 2 °F higher 

than the past century, and are already the warmest that region 

has experienced in at least 600 years. The NCA notes that there 

is evidence that climate-change induced warming on top of recent 

drought has influenced tree mortality, wildfire frequency and 

area, and forest insect outbreaks. Sea levels have risen about 7 

or 8 inches in this region, contributing to inundation of 

Highway 101 and backup of seawater into sewage systems in the 

San Francisco area. 

Projections indicate that the Southwest will warm an 

additional 5.5 to 9.5 °F over the next century if emissions 

continue to increase. Winter snowpack in the Southwest is 

projected to decline (consistent with the record lows from this 

past winter), reducing the reliability of surface water supplies 

for cities, agriculture, cooling for power plants, and 

ecosystems. Sea level rise along the California coast will 

worsen coastal erosion, increase flooding risk for coastal 

highways, bridges, and low-lying airports, pose a threat to 

groundwater supplies in coastal cities such as Los Angeles, and 

increase vulnerability to floods for hundreds of thousands of 
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residents in coastal areas. Climate change will also have 

impacts on the high-value specialty crops grown in the region as 

a drier climate will increase demands for irrigation, more 

frequent heat waves will reduce yields, and decreased winter 

chills may impair fruit and nut production for trees in 

California. Increased drought, higher temperatures, and bark 

beetle outbreaks are likely to contribute to continued increases 

in wildfires. The highly urbanized population of the Southwest 

is vulnerable to heat waves and water supply disruptions, which 

can be exacerbated in cases where high use of air conditioning 

triggers energy system failures. 

The rate of warming in the Midwest has markedly accelerated 

over the past few decades. Temperatures rose by more than 1.5 °F 

from 1900 to 2010, but between 1980 and 2010 the rate of warming 

was three times faster than from 1900 through 2010. 

Precipitation generally increased over the last century, with 

much of the increase driven by intensification of the heaviest 

rainfalls. Several types of extreme weather events in the 

Midwest (e.g., heat waves and flooding) have already increased 

in frequency and/or intensity due to climate change.

In the future, if emissions continue increasing, the 

Midwest is expected to experience 5.6 to 8.5 °F of warming by 

the 2080s, leading to more heat waves. Though projections of 
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changes in total precipitation vary across the regions, more 

precipitation is expected to fall in the form of heavy downpours 

across the entire region, leading to an increase in flooding. 

Specific vulnerabilities highlighted by the NCA include longterm decreases in agricultural productivity, changes in the 

composition of the region’s forests, increased public health 

threats from heat waves and degraded air and water quality, 

negative impacts on transportation and other infrastructure 

associated with extreme rainfall events and flooding, and risks 

to the Great Lakes including shifts in invasive species, 

increases in harmful algal blooms, and declining beach health. 

High temperatures (more than 100 °F in the Southern Plains 

and more than 95 °F in the Northern Plains) are projected to 

occur much more frequently by mid-century. Increases in extreme 

heat will increase heat stress for residents, energy demand for 

air conditioning, and water losses. North Dakota’s increase in 

annual temperatures over the past 130 years is the fastest in 

the contiguous U.S., mainly driven by warming winters. Specific 

vulnerabilities highlighted by the NCA include increased demand 

for water and energy, changes to crop growth cycles and 

agricultural practices, and negative impacts on local plant and 

animal species from habitat fragmentation, wildfires, and 

changes in the timing of flowering or pest patterns. Communities 
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that are already the most vulnerable to weather and climate 

extremes will be stressed even further by more frequent extreme 

events occurring within an already highly variable climate 

system. 

In Hawaii, other Pacific islands, and the Caribbean, rising 

air and ocean temperatures, shifting rainfall patterns, changing 

frequencies and intensities of storms and drought, decreasing 

baseflow in streams, rising sea levels, and changing ocean 

chemistry will affect ecosystems on land and in the oceans, as 

well as local communities, livelihoods, and cultures. Low 

islands are particularly at risk. 

Rising sea levels, coupled with high water levels caused by 

tropical and extra-tropical storms, will incrementally increase 

coastal flooding and erosion, damaging coastal ecosystems, 

infrastructure, and agriculture, and negatively affecting 

tourism. Ocean temperatures in the Pacific region exhibit strong 

year-to-year and decadal fluctuations, but since the 1950s, they 

have exhibited a warming trend, with temperatures from the 

surface to a depth of 660 feet rising by as much as 3.6°F. As a 

result of current sea level rise, the coastline of Puerto Rico 

around Rincón is being eroded at a rate of 3.3 feet per year. 

Freshwater supplies are already constrained and will become more 

limited on many islands. Saltwater intrusion associated with sea 
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level rise will reduce the quantity and quality of freshwater in 

coastal aquifers, especially on low islands. In areas where 

precipitation does not increase, freshwater supplies will be 

adversely affected as air temperature rises. 

Warmer oceans are leading to increased coral bleaching 

events and disease outbreaks in coral reefs, as well as changed 

distribution patterns of tuna fisheries. Ocean acidification 

will reduce coral growth and health. Warming and acidification, 

combined with existing stresses, will strongly affect coral reef 

fish communities. For Hawaii and the Pacific islands, future sea 

surface temperatures are projected to increase 2.3°F by 2055 and 

4.7°F by 2090 under a scenario that assumes continued increases 

in emissions. Ocean acidification is also taking place in the 

region, which adds to ecosystem stress from increasing 

temperatures. Ocean acidity has increased by about 30% percent

since the pre-industrial era and is projected to further 

increase by 37% percent to 50% percent from present levels by 

2100. 

The NCA also discussed impacts that occur along the coasts 

and in the oceans adjacent to many regions, and noted that other 

impacts occur across regions and landscapes in ways that do not 

follow political boundaries. 
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B. GHG Emissions from Fossil Fuel-fired EGUs56

Fossil fuel-fired electric utility generating units (EGUs) 

are by far the largest emitters of GHGs among stationary sources 

in the U.S., primarily in the form of CO2, and among fossil fuelfired EGUs, coal-fired units are by far the largest emitters. 

This section describes the amounts of these emissions and places 

these amounts in the context of the U.S. Inventory of Greenhouse 

Gas Emissions and Sinks57 (the U.S. GHG Inventory). 

The EPA implements a separate program under 40 CFR Part 98 

called the Greenhouse Gas Reporting Program58 (GHGRP) that 

requires emitting facilities over threshold amounts of GHGs to 

report their emissions to the EPA annually. Using data from the 

GHGRP, this section also places emissions from fossil fuel-fired 

EGUs in the context of the total emissions reported to the GHGRP 

from facilities in the other largest-emitting industries. 

 

56 The emission data presented in this section of the preamble 

(Section II.B) are in metric tons, in keeping with reporting 

requirements for the GHGRP and the U.S. GHG Inventory. Note that 

the mass-based state goals presented in section VII of this 

preamble, and discussed elsewhere in this preamble, are 

presented in short tons. 

57 “Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 

2013”, Report EPA 430-R-15-004, United States Environmental 

Protection Agency, April 15, 2015. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

58 U.S. EPA Greenhouse Gas Reporting Program Dataset, see 

http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html
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The EPA prepares the official U.S. GHG Inventory to comply 

with commitments under the United Nations Framework Convention 

on Climate Change (UNFCCC). This inventory, which includes 

recent trends, is organized by industrial sectors. It provides 

the information in Table 23 below, which presents total U.S. 

anthropogenic emissions and sinks59 of GHGs, including CO2

emissions, for the years 1990, 2005 and 2013. 

Table 23. U.S. GHG Emissions and Sinks by Sector (million metric 

tons carbon dioxide equivalent (MMT CO2 Eq.))60

SECTOR 1990 2005 2013 

Energy61 5,290.5 6,273.6 5,636.6

Industrial Processes 

and Product Use 342.1 367.4 359.1

Agriculture 448.7 494.5 515.7

Land Use, Land-Use 

Change and Forestry 13.8 25.5 23.3 

Waste 206.0 189.2 138.3

Total Emissions 6,301.1 7,350.2 6,673.0

 (775.8) (911.9) (881.7)

 

59 Sinks are a physical unit or process that stores GHGs, such as 

forests or underground or deep sea reservoirs of carbon dioxide.

60 From Table ES-4 of “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html 

61 The energy sector includes all greenhouse gases resulting from 

stationary and mobile energy activities, including fuel 

combustion and fugitive fuel emissions. 
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Land Use, Land-Use 

Change and Forestry 

(Sinks) 

Net Emissions (Sources 

and Sinks) 5,525.2 6,438.3 5,791.2

Total fossil energy-related CO2 emissions (including both 

stationary and mobile sources) are the largest contributor to 

total U.S. GHG emissions, representing 77.3 percent of total 

2013 GHG emissions.62 In 2013, fossil fuel combustion by the 

utility power sector –- entities that burn fossil fuel and whose 

primary business is the generation of electricity –- accounted 

for 38.3 percent of all energy-related CO2 emissions.63 Table 34

below presents total CO2 emissions from fossil fuel-fired EGUs, 

for years 1990, 2005 and 2013. 

Table 34. U.S. GHG Emissions from Generation of Electricity from 

Combustion of Fossil Fuels (MMT CO2)64

 

62 From Table ES-2 “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

. 

63 From Table 3-1 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html 

64 From Table 3-5 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15 2015. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

. 

GHG EMISSIONS 1990 2005 2013 
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In addition to preparing the official U.S. GHG Inventory to 

present comprehensive total U.S. greenhouse gas emissions and 

comply with commitments under the UNFCCC, the EPA collects 

detailed GHG emissions data from the largest emitting facilities 

in the U.S. through its Greenhouse Gas Reporting Program 

(GHGRP). Data collected by the GHGRP from large stationary 

sources in the industrial sector show that the utility power 

sector emits far greater CO2 emissions than any other industrial 

sector. Table 45 below presents total GHG emissions in 2013 for 

the largest emitting industrial sectors as reported to the 

GHGRP. As shown in Table 34 and Table 45, respectively, CO2

emissions from fossil fuel-fired EGUs are nearly three times as 

large as the total reported GHG emissions from the next ten 

largest emitting industrial sectors in the GHGRP database 

combined. 

Table 45. Direct GHG Emissions Reported to GHGRP by Largest 

Emitting Industrial Sectors (MMT CO2e)65

 

65 U.S. EPA Greenhouse Gas Reporting Program Dataset as of August 

18, 2014. http://ghgdata.epa.gov/ghgp/main.do. 

Total CO2 from fossil fuelfired EGUs 1,820.8 2,400.9 2,039.8

 - from coal 1,547.6 1,983.8 1,575.0

 - from natural gas 175.3 318.8 441.9

 - from petroleum 97.5 97.9 22.4
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C

C. Challenges in Controlling Carbon Dioxide Emissions 

Carbon dioxide is a unique air pollutant and controlling it 

presents unique challenges. CO2 is emitted in enormous 

quantities, and those quantities, coupled with the fact that CO2

is relatively unreactive, make it much more difficult to mitigate 

by measures or technologies that are typically utilized within 

an existing power plant. Measures that may be used to limit CO2

emissions would include efficiency improvements, which have 

thermodynamic limitations and carbon capture and sequestration 

(CCS), which is energy resource intensive. 

Unlike other air pollutants which are results of trace 

impurities in the fuel, products of incomplete or inefficient 

combustion, or combustion byproducts, CO2 is an inherent product 

of clean, efficient combustion of fossil fuels, and therefore is 

an unavoidable product generated in enormous quantities, far 

Industrial Sector 2013

Petroleum Refineries 176.7 

Onshore Oil & Gas Production 94.8

Municipal Solid Waste Landfills 93.0 

Iron & Steel Production 84.2 

Cement Production 62.8

Natural Gas Processing Plants 59.0

Petrochemical Production 52.7

Hydrogen Production 41.9

Underground Coal Mines 39.8

Food Processing Facilities 30.8
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greater than any other air pollutant.66 In fact, CO2 is emitted 

in far greater quantities than all other air pollutants 

combined. Total emissions of all non-greenhouse gas (GHG) air 

pollutants in the U.S., from all sources, in 2013, were 121 

million metric tons.67,68 As noted above, total emissions of CO2

 

66 Lackner et al., “Comparative Impacts of Fossil Fuels and 

Alternative Energy Sources”, Issues in Environmental Science and 

Technology (2010). 

67 This includes NAAQS and HAPs, based on the following table: 

Pollutant 2013 tons 

(million short tons) Reference 

CO 69.758 

Trends file 

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

chie1/trends/) 

NOX 13.072 “ 

PM10 20.651 “ 

SO2 5.098 “ 

VOC 17.471 “ 

NH3 4.221 “ 

HAPS 3.641 

2011 NEI version 2 

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

/chief/net/2011inventor

y.html) 

Total 133.912 

It should be noted that PM2.5 is included in the amounts for PM10. 

Lead, another NAAQS pollutant, is emitted in the amounts of 

approximately 1,000 tons per year, and, in light of that 

relatively small quantity, was excluded from this analysis. 

Ammonia (NH3) is included because it is a precursor to PM2.5

secondary formation. Note that one short ton is equivalent to 

0.907185 metric ton. 

68 In addition, emissions of non-CO2 GHGs totaled 1.168 billion 

metric tons of carbon-dioxide equivalents (CO2e) in 2013. See 

Table ES-2, Executive Summary, 1990-2013 Inventory of U.S. 

Greenhouse Gas Emissions and Sinks. 

http://www.epa.gov/climatechange/Downloads/ghgemissions/US-GHGInventory-2015-Chapter-Executive-Summary.pdf 
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from coal-fired power plants alone – the largest stationary 

source emitter -- were 1.575 billion metric tons in that year,69

and total emissions of CO2 from all sources were 5.5 billion 

metric tons.70,71 Carbon makes up the majority of the mass of coal 

and other fossil fuels, and for every ton of carbon burned, more 

than 3 tons of CO2 is produced.72 In addition, unlike many of the 

other air pollutants that react with sunlight or chemicals in 

the atmosphere, or are rained out or deposited on surfaces, CO2

 

This includes emissions of methane, nitrous oxide, and 

fluorinated GHGs (hydrofluorocarbons, perfluorocarbons, sulfur 

hexafluoride, and nitrogen trifluoride). In the total, the 

emissions of each non-CO2 GHG have been translated from metric 

tons of that gas into metric tons of CO2e by multiplying the 

metric tons of the gas by the global warming potential (GWP) of 

the gas. (The GWP of a gas is a measure of the ability of one 

kilogram of that gas to trap heat in earth’s atmosphere compared 

to one kilogram of CO2.) 69 From Table 3-5 “Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015. 

http://epa.gov/climatechange/ghgemissions/usinventoryreport.html

. 

70 U.S. EPA, Greenhouse Gas Inventory Data Explorer, 

http://www.epa.gov/climatechange/ghgemissions/inventoryexplorer/

#allsectors/allgas/gas/current 

71 As another point of comparison, except for carbon dioxide, 

SO2 and NOx are the largest air pollutant emissions from coalfired power plants. Over the past decade, U.S. power plants have 

emitted more than 200 times as much CO2 as they have emitted SO2

and NOx. See de Gouw et al., “Reduced emissions of CO2, NOx, and 

SO2 from U.S. power plants owing to switch from coal to natural 

gas with combined cycle technology,” Earth’s Future (2014).

72 Each atom of carbon in the fuel combines with 2 atoms of 

oxygen in the air. 
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is relatively unreactive and difficult to remove directly from 

the atmosphere.73,74

CO2’s huge quantities and lack of reactivity make it 

challenging to remove from the smokestack. Retrofitted equipment 

is required to capture the CO2 before transporting it to a 

storage site. However, the scale of infrastructure required to 

directly mitigate CO2 emissions from existing EGUs through CCS 

can be quite large and difficult to integrate into the existing 

fossil fuel infrastructure. These CCS techniques are discussed 

in more depth elsewhere in the preamble for this rule and for 

the section 111(b) rule for new sources that accompanies this 

rule. 

The properties of CO2 can be contrasted with those of a 

number of other pollutants which have more accessible mitigation 

options. For example, the NAAQS pollutants – which generally are 

emitted in the largest quantities of any of the other air 

pollutants, except for CO2 – each have more accessible mitigation 

options. Sulfur dioxide (SO2) is the result of a contaminant in 

 

73 Seinfeld J. and Pandis S., Atmospheric Chemistry and Physics: 

From Air Pollution to Climate Change (1998). 

74 The fact that CO2 is unreactive means that it is primarily 

removed from the atmosphere by dissolving in oceans or by being 

converted into biomass by plants. Herzog, H., “Scaling up carbon 

dioxide capture and storage: From megatons to gigatons”, Energy 

Economics (2011). 
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the fuel, and, as a result, it can be reduced by using lowsulfur coal or by using flue-gas desulfurization (FGD) 

technologies. Emissions of nitrogen oxides (NOx) can be mitigated 

relatively easily using combustion control techniques (e.g., 

low-NOx burners) and by using downstream controls such as 

selective catalytic reduction (SCR) and selective non-catalytic 

reduction (SNCR) technologies. Particulate matter (PM) can be 

effectively mitigated using fabric filters, PM scrubbers, or 

electrostatic precipitators. Lead is part of particulate matter 

emissions and is controlled through the same devices. Carbon 

monoxide and VOCs are the products of incomplete combustion and 

can therefore be abated by more efficient combustion conditions, 

and can also be destroyed in the smokestack by the use of 

oxidation catalysts which complete the combustion process. Many 

air toxics are VOCs, such as polyaromatic hydrocarbons, and 

therefore can be abated in the same ways just described. But in 

every case, these pollutants can be controlled at the source 

much more readily than CO2 primarily because of the comparatively 

lower quantities that are produced, and also due to other 

attributes such as relatively greater reactivity and solubility.

D. The Utility Power Sector 

1. A brief history 
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The modern American electricity system is one of the 

greatest engineering achievements of the past 100 years. Since 

the invention of the incandescent light bulb in the 1870s,75

electricity has become one of the major foundations for modern 

American life. Beginning with the first power station in New 

York City in 1882, each power station initially served a 

discrete set of consumers, resulting in small and localized 

electricity systems.76 During the early 1900s, smaller systems 

consolidated, allowing generation resources to be shared over 

larger areas. Interconnecting systems have reduced generation 

investment costs and improved reliability.77 Local and state 

governments initially regulated these growing electricity 

 

75 Regulatory Assistance Project (RAP), Electricity Regulation in 

the US: A Guide, at 1 (2011), available at 

http://www.raponline.org/document/download/id/645. 

76 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 2-4 (2d ed. 2010). 77 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 5-6 (2d ed. 2010). Investment in 

electric generation is extremely capital intensive, with 

generation potentially accounting for 65 percent of customer 

costs. If these costs can be spread to more customers, then 

this can reduce the amount that each individual customer pays. 

Federal Energy Regulatory Commission, Energy Primer: A Handbook 

of Energy Market Basics, at 38 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 
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systems with federal regulation coming later in response to 

public concerns about rising electricity costs.78 

Initially, states had broad authority to regulate public 

utilities, but gradually federal regulation increased. In 1920, 

Congress passed the Federal Water Power Act, creating the 

Federal Power Commission (FPC) and providing for the licensing 

of hydroelectric facilities on U.S. government lands and 

navigable waters of the U.S.79 During this time period, the U.S. 

Supreme Court found that state authority to regulate public 

utilities is limited, holding that the Commerce Clause does not 

allow state regulation to directly burden interstate commerce.80

For example, in Public Utilities Commission of Rhode Island v. 

Attleboro Steam & Electric Company, Rhode Island sought to 

regulate the electricity rates that a Rhode Island generator was 

charging to a company in Massachusetts that resold the 

electricity to Attleboro, Massachusetts.81 The Supreme Court 

 

78 Burn, An Energy Journal, The Electricity Grid: A History, 

available at http://burnanenergyjournal.com/the-electric-grid-ahistory/ (last visited Mar. 9, 2015). 

79 The FPC became an independent Commission in 1930. United 

States Government Manual 1945: First Edition, at 486, available 

at http://www.ibiblio.org/hyperwar/ATO/USGM/FPC.html. 80 New York v. Federal Energy Regulatory Commission, 535 U.S. 1, 

5 (2002) (citation omitted).

81 Public Utils. Comm'n of Rhode Island v. Attleboro Steam & 

Elec. Co., 273 U.S. 83 (1927).
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found that Rhode Island’s regulation was impermissible because 

it imposed a "direct burden upon interstate commerce."82 The 

Supreme Court held that this kind of interstate transaction was 

not subject to state regulation. However, because Congress had 

not yet passed legislation to make these types of transactions 

subject to federal regulation, this became known as the 

"Attleboro gap" in regulation. In 1935, Congress passed the 

Federal Power Act (FPA), giving the FPC jurisdiction over “the 

transmission of electric energy in interstate commerce" and "the 

sale of electric energy at wholesale in interstate commerce."83

Under FPA section 205, the FPC was tasked with ensuring that 

rates for jurisdictional services are just, reasonable, and not 

unduly discriminatory or preferential.84 FPA section 206 

authorized the FPC to determine, after a hearing upon its own 

motion or in response to a complaint filed at the Commission, 

whether jurisdictional rates are just, reasonable, and not 

unduly discriminatory or preferential.85 In 1938, Congress passed 

the Natural Gas Act (NGA), giving the FPC jurisdiction over the 

 

82 Public Utils. Comm'n of Rhode Island v. Attleboro Steam & 

Elec. Co., 273 U.S. 83, 89 (1927).

83 16 U.S.C. § 824(b)(1). 

84 16 U.S.C. § 824d. 

85 16 U.S.C. § 824e. 
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transmission or sale of natural gas in interstate commerce.86 The 

NGA also gave the FPC the jurisdiction to “grant certificates 

allowing construction and operation of facilities used in 

interstate gas transmission and authorizing the provision of 

services.”87 In 1977, the FPC became FERC after Congress passed 

the Department of Energy Organization Act. 

By the 1930s, regulated electric utilities that provided 

the major components of the electrical system - generation, 

transmission, and distribution - were common.88 These regulated 

monopolies are referred to as vertically-integrated utilities. 

As utilities built larger and larger electric generation 

plants, the cost per unit to generate electricity decreased.89 

However, these larger plants were extremely capital intensive 

 

86 Energy Information Administration, Natural Gas Act of 1938, 

available at 

http://www.eia.gov/oil_gas/natural_gas/analysis_publications/ngm

ajorleg/ngact1938.html. 

87 Energy Information Administration, Natural Gas Act of 1938, 

available at 

http://www.eia.gov/oil_gas/natural_gas/analysis_publications/ngm

ajorleg/ngact1938.html. 

88 Burn, An Energy Journal, The Electricity Grid: A History, 

available at http://burnanenergyjournal.com/the-electric-grid-ahistory/(last visited Mar. 9, 2015).

89 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 38 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 
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for any one company to fund.90 Some neighboring utilities solved 

this issue by agreeing to share electricity reserves when 

needed.91 These utilities began building larger transmission 

lines to deliver power in times when large generators 

experienced outages.92 Eventually, some utilities that were in 

reserve sharing agreements formed electric power pools to 

balance electric load over a larger area. Participating 

utilities gave control over scheduling and dispatch of their 

electric generation units to a system operator.93 Some power 

pools evolved into today’s regional transmission organizations 

(RTOs) and independent system operators (ISOs). 

In the past, electric utilities generally operated as state 

regulated monopolies, supplying end-use customers with 

generation, distribution, and transmission service.94 However, 

 

90 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 38 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.

91 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 38 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.

92 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 38 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.

93 Shively, B, Ferrare, J, Understanding Today’s Electricity 

Business, Enerdynamics, at 94 (2012). 94 Maryland Department of Natural Resources, Maryland Power 

Plants and the Environment: A Review of the Impacts of Power 

Plants and Transmission Lines on Maryland’s Natural Resources, 

at 2-5 (2006). 
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the ability of electric utilities to operate as natural 

monopolies came with consumer protection safeguards.95 “In 

exchange for a franchised, monopoly service area, utilities 

accept an obligation to serve – meaning there must be adequate 

supply to meet customers’ needs regardless of the cost.”96 Under 

this obligation to serve, the utility agreed to provide service 

to any customer located within its service jurisdiction. 

On both a federal and state level, competition has entered 

the electricity sector to varying degrees in the last few 

decades.97 In the early 1990s, some states began to consider 

allowing competition to enter retail electric service.98 Federal 

 

95 Pacific Power, Utility Regulation, at 1, available at

https://www.pacificpower.net/content/dam/pacific_power/doc/About

_Us/Newsroom/Media_Resources/Regulation.PP.08.pdf. 

96 Pacific Power, Utility Regulation, at 1, available at

https://www.pacificpower.net/content/dam/pacific_power/doc/About

_Us/Newsroom/Media_Resources/Regulation.PP.08.pdf. 

97 For example, in 1978, Congress passed the Public Utilities 

Regulatory Policies Act (PURPA) which allowed non-utility owned 

power plants to sell electricity. Burn, An Energy Journal, The 

Electricity Grid: A History, available at 

http://burnanenergyjournal.com/the-electric-grid-a-history/ 

(last visited Mar. 9, 2015). PURPA, the Energy Policy Act of 

1992 (EPAct 1992), and the Energy Policy Act of 2005 (EPAct 

2005) “promoted competition by lowering entry barriers and 

increasing transmission access.” The Electric Energy Market 

Competition Task Force, Report to Congress on Competition in 

Wholesale and Retail Markets for Electric Energy, at 2, 

available at http://www.ferc.gov/legal/fed-sta/ene-polact/epact-final-rpt.pdf (last visited Mar. 20, 2015). 

98 The Electric Energy Market Competition Task Force, Report to 

Congress on Competition in Wholesale and Retail Markets for 
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and state efforts to allow competition in the electric utility 

industry have resulted in independent power producers (IPPs)99

producing approximately 37 percent of net generation in 2013.100

Electric utilities in some states remain vertically integrated 

without retail competition from IPPs. Today, there are over 

3,000 public, private, and cooperative utilities in the United 

States.101 These utilities include both investor-owned 

utilities102 and consumer-owned utilities.103 

Over time, the grid slowly evolved into a complex, 

interconnected transmission system that allows electric 

 

Electric Energy, at 2, available at

http://www.ferc.gov/legal/fed-sta/ene-pol-act/epact-finalrpt.pdf (last visited Mar. 20, 2015). 

99 These entities are also referred to as merchant generators. 

100 Energy Information Administration, Electric Power Annual, 

Table 1.1 Total Electric Power Summary Statistics, 2013 and 2012

(2015), available at

http://www.eia.gov/electricity/annual/html/epa_01_01.html. 

101 Regulatory Assistance Project (RAP), Electricity Regulation 

in the US: A Guide, at 9 (2011), available at 

http://www.raponline.org/document/download/id/645. 

102 Investor-owned utilities are private companies that are 

financed by a combination of shareholder equity and bondholder 

debt. Regulatory Assistance Project (RAP), Electricity 

Regulation in the US: A Guide, at 9 (2011), available at 

http://www.raponline.org/document/download/id/645. 

103 Consumer-owned utilities include municipal utilities, public 

utility districts, cooperatives, and a variety of other entities 

such as irrigation districts. Regulatory Assistance Project 

(RAP), Electricity Regulation in the US: A Guide, at 9-10 

(2011), available at 

http://www.raponline.org/document/download/id/645. 
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generators to produce electricity that is then fed onto 

transmission lines at high voltages.104 These larger transmission 

lines are able to access generation that is located more 

remotely, with transmission lines crossing many miles, including 

state borders.105 Closer to end users, electricity is transformed 

 

104 Peter Fox-Penner, Electric Utility Restructuring: A Guide to 

the Competitive Era, Public Utility Reports, Inc., at 5, 34 

(1997). “The extent of the power system’s short-run physical 

interdependence is remarkable, if not entirely unique. No other 

large, multi-stage industry is required to keep every single 

producer in a region – whether or not owned by the same company 

– in immediate synchronization with all other producers.” Id. at 

34. “At an early date, those providing electric power recognized 

that peak use for one system often occurred at a different time 

from peak use in other systems. They also recognized that 

equipment failures occurred at different times in various 

systems. Analyses showed significant economic benefits from 

interconnecting systems to provide mutual assistance; the 

investment required for generating capacity could be reduced and 

reliability could be improved. This lead [sic] to the 

development of local, then regional, and subsequently three 

transmission grids that covered the United States and parts of 

Canada.” Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 5-6 (2d ed. 2010). 105 Burn, An Energy Journal, The Electricity Grid: A History, 

available at http://burnanenergyjournal.com/the-electric-grid-ahistory/ (last visited Mar. 9, 2015). Because of the ease and 

low cost of converting voltages in an alternating current (AC) 

system from one level to another, the bulk power system is 

predominantly an AC system rather than a direct current (DC) 

system. In an AC system, electricity cannot be controlled like a 

gas or liquid by utilizing a valve in a pipe. Instead, absent 

the presence of expensive control devices, electricity flows 

freely along all available paths, according to the laws of 

physics. U.S.-Canada Power System Outage Task Force, Final 

Report on the August 14, 2003 Blackout in the United States and 

Canada: Causes and Recommendations, at 6 (Apr. 2004), available 
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into a lower voltage that is transported across localized 

transmission lines to homes and businesses.106 Localized 

transmission lines make up the distribution system. These three 

components of the electricity system - generation, transmission, 

and distribution - are closely related and must work in 

coordination to deliver electricity from the point of generation 

to the point of consumption. This interconnectedness is a 

fundamental aspect of the nation’s electricity system, requiring 

a complicated integration of all components of the system to 

balance supply and demand and a federal, state, and local 

regulatory network to oversee the physically interconnected 

network. Facilities planned and constructed in one segment can 

impact facilities and operations in other segments and vice 

versa. 

The North American electric grid has developed into a 

large, interconnected system.107 Electricity from a diverse set 

of generation resources such as natural gas, nuclear, coal, and 

 

at http://www.ferc.gov/industries/electric/indusact/reliability/blackout/ch1-3.pdf.

106 Peter Fox-Penner, Electric Utility Restructuring: A Guide to 

the Competitive Era, Public Utility Reports, Inc., at 5 (1997). 107 U.S.-Canada Power System Outage Task Force, Final Report on 

the August 14, 2003 Blackout in the United States and Canada: 

Causes and Recommendations, at 5 (Apr. 2004), available at

http://www.ferc.gov/industries/electric/indusact/reliability/blackout/ch1-3.pdf. 
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renewables is distributed over high-voltage transmission lines 

divided across the continental United States into three 

synchronous interconnections – the Eastern Interconnection, 

Western Interconnection, and the Texas Interconnection.108 These 

three synchronous systems each act like a single machine.109

Diverse resources generate electricity that is transmitted and 

 

108 Regulatory Assistance Project (RAP), Electricity Regulation 

in the US: A Guide, 2011, at 1, available at

http://www.raponline.org/document/download/id/645. 

109 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 159 (2d ed. 2010). Casazza, J. and 

Delea, F., Understanding Electric Power Systems, IEEE Press, at 

159 (2d ed. 2010). In an amicus brief to the Supreme Court, a 

group of electrical engineers, economists, and physicists 

specializing in electricity explained, “Energy is transmitted, 

not electrons. Energy transmission is accomplished through the 

propagation of an electromagnetic wave. The electrons merely 

oscillate in place, but the energy – the electromagnetic wave – 

moves at the speed of light. The energized electrons making the 

lightbulb in a house glow are not the same electrons that were 

induced to oscillate in the generator back at the power plant. 

. . . Energy flowing onto a power network or grid energizes the 

entire grid, and consumers then draw undifferentiated energy 

from that grid. A networked grid flexes, and electric current 

flows, in conformity with physical laws, and those laws do not 

notice, let alone conform to, political boundaries. . . . The 

path taken by electric energy is the path of least resistance . 

. . or, more accurately, the paths of least resistance. . . . 

If a generator on the grid increases its output, the current 

flowing from the generator on all paths on the grid increases. 

These increases affect the energy flowing into each point in the 

network, which in turn leads to compensating and corresponding 

changes in the energy flows out of each point.” Brief Amicus 

Curiae of Electrical Engineers, Energy Economists and Physicists 

in Support of Respondents at 2, 8-9, 11, New York v. FERC, 535 

U.S. 1 (2001) (No. 00-568).
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distributed through a complex system of interconnected 

components to industrial, business, and residential consumers. 

Unlike other industries where sources make operational decisions 

independently, the utility power sector is unique in that 

electricity system resources operate in a complex, 

interconnected grid system that is physically interconnected and 

operated on an integrated basis across large regions. 

Additionally, a federal, state, and local regulatory network 

oversees policies and practices that are applied to how the 

system is designed and operates. In this interconnected system, 

system operators must ensure that the amount of electricity 

available is precisely matched with the amount needed in real 

time. System operators have a number of resources potentially 

available to meet electricity demand, including electricity 

generated by electric generation units such as coal, nuclear, 

renewables, and natural gas, as well as demand-side resources110, 

 

110 “Measures using demand-side resources comprise actions taken 

on the customer’s side of the meter to change the amount and/or 

timing of electricity use in ways that will provide benefits to 

the electricity supply system.” David Crossley, Regulatory 

Assistance Project (RAP), Effective Mechanisms to Increase the 

Use of Demand-Side Resources, at 9 (2013), available at

www.raponline.org. 
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such as energy efficiency111 and demand response.112 Generation, 

outages, and transmission changes in one part of the synchronous 

grid can affect the entire interconnected grid.113 The 

interconnection is such that “[i]f a generator is lost in New 

York City, its affect is felt in Georgia, Florida, Minneapolis, 

St. Louis, and New Orleans.”114 The U.S. Supreme Court has 

similarly recognized the interconnected nature of the 

electricity grid.115 

 

111 Energy efficiency is using less energy to provide the same or 

greater level of service. Demand-side energy efficiency refers 

to an extensive array of technologies, practices and measures 

that are applied throughout all sectors of the economy to reduce 

energy demand while providing the same, and sometimes better, 

level and quality of service. 

112 Demand response involves “[c]hanges in electric usage by 

demand-side resources from their normal consumption patterns in 

response to changes in the price of electricity over time, or to 

incentive payments designed to induce lower electricity use at 

times of high wholesale market prices or when system reliability 

is jeopardized.” Federal Energy Regulatory Commission, Reports 

on Demand Response & Advanced Metering, (Dec. 23, 2014), 

available at http://www.ferc.gov/industries/electric/indusact/demand-response/dem-res-adv-metering.asp. 

113 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 159 (2d ed. 2010). 114 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 160 (2d ed. 2010). 115

Federal Power Comm’n v. Florida Power & Light Co., 404 U.S. 

453, at 460 (1972) (quoting a Federal Power Commission hearing 

examiner, "`If a housewife in Atlanta on the Georgia system 

turns on a light, every generator on Florida’s system almost 

instantly is caused to produce some quantity of additional 

electric energy which serves to maintain the balance in the 

interconnected system between generation and load.’”) (citation 
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Today, federal, state, and local entities regulate 

electricity providers.116 Overlaid on the physical electricity 

network is a regulatory network that has developed over the last 

century or more. This regulatory network “plays a vital role in 

the functioning of all other networks, sometimes providing 

specific rules for functioning while at other times providing 

restraints within which their operation must be conducted.”117 

This unique regulatory network results in an electricity grid 

that is both physically interconnected and connected through a 

network of regulation on the local, state, and federal levels. 

This regulation seeks to reconcile the fact that electricity is 

a public good with the fact that facilities providing that 

 

omitted). See also New York v. FERC, 535 U.S. 1, at 7 (2002) 

(stating that “any electricity that enters the grid immediately 

becomes a part of a vast pool of energy that is constantly 

moving in interstate commerce.”) (citation omitted). In Federal 

Power Comm’n v. Southern California Edison Co., 376 U.S. 205 

(1964), the Supreme Court found that a sale for resale of 

electricity from Southern California Edison to the City of 

Colton, which took place solely in California, was under Federal 

Power Commission jurisdiction because some of the electricity 

that Southern California Edison marketed came from out of state. 

The Supreme Court stated that, “`federal jurisdiction was to 

follow the flow of electric energy, an engineering and 

scientific, rather than a legalistic or governmental, test.’” 

Id. at 210 (quoting Connecticut Light & Power Co. v. Federal 

Power Commission, 324 U.S. 515, 529 (1945) (emphasis omitted)). 116 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 214 (2d ed. 2010). 117 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 213 (2d ed. 2010).
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electricity are privately owned.118 While this regulation began 

on the state and local levels, federal regulation of the 

electricity system increased over time. With the passage of the 

EPAct 1992 and the EPAct 2005, the federal government’s role in 

electricity regulation greatly increased.119 “The role of the 

regulator now includes support for the development of open and 

fair wholesale electric markets, ensuring equal access to the 

transmission system and more hands-on oversight and control of 

the planning and operating rules for the industry.”120 

2. Electric system dispatch 

System operators typically dispatch the electric system 

through a process known as economic dispatch.Security 

Constrained Economic dispatchDispatch.121 Security Constrained 

Economic Dispatch has been defined as “the operation two 

components – economic generation of generation facilities to 

produce energy at the lowest cost to reliably serve consumers, 

recognizing any operational limits of generation and 

 

118 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 213 (2d ed. 2010). 119 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 214 (2d ed. 2010). 120 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 214 (2d ed. 2010). 121 Economic Dispatch: Concepts, Practices and Issues, FERC Staff 

Presentation to the Joint Board for the Study of Economic 

Dispatch, Palm Springs, California (Nov. 13, 2005). 
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transmission facilities.”ensuring that the electric system 

remains reliable.122 Electricity demand varies across geography 

and time in response to numerous conditions, such that electric 

generators are constantly responding to changes in the most 

reliable and cost-effective manner possible. The cost of 

operating electric generation varies based on a number of 

factors, such as fuel and generator efficiency. 

 The decision to dispatch any particular electric generator 

depends upon the relative operating cost, or marginal cost, of 

generating electricity to meet the last increment of electric 

demand. Fuel is one common variable cost – especially for 

fossil-fueled generators. Coal plants will often have 

considerable variable costs associated with running pollution 

controls.123 Renewables, hydroelectric, and nuclear have little 

to no variable costs. In anIf electricity demand decreases or 

additional generation becomes available on the system, this 

 

122 Federal Energy Regulatory Commission, Security Constrained 

Economic Dispatch: Definitions, Practices, Issues and 

Recommendations: A Report to Congress (July 31, 2006). The 

Energy Policy Act of 2005 defined economic dispatch as “the 

operation of generation facilities to produce energy at the 

lowest cost to reliably serve consumers, recognizing any 

operational limits of generation and transmission facilities.”

Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594 

(2005), section 1234(b).

123 Variable costs also include costs associated with operation 

and maintenance and costs of operating a pollution control 

and/or emission allowance charges. 
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impacts how the system operator will dispatch the system. EGUs 

using technologies with relatively low variable costs, such as 

nuclear units and RE, are for economic dispatch system, units 

with reasons generally operated at their maximum output whenever 

they are available. When lower cost units are available to run, 

higher variable costscost units, such as fossil -fuel-fired

generators, are generally are the first generation to be 

displaced by lower variable cost generation, like RE. 

 In states with cost-of-service regulation of verticallyintegrated utilities, the utilities themselves form the 

balancing authorities who determine dispatch based upon the 

lowest marginal cost. These utilities sometimes arrange to buy 

and sell electricity with other balancing authorities. RTOs and 

ISOs are generally responsible for dispatch in non-vertically 

integrated states. TheyRTOs and ISOs coordinate, control, and 

monitor electricity transmission systems to ensure costeffective and reliable delivery of power, and they are 

independent from market participants. 

3. Reliability considerations 

The reliability of the electric system has long been a 

focus of the electric industry and regulators. Industry 

developed a voluntary organization in the early 1960s that 

assisted with bulk power system coordination in the U.S. and 
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Canada.124 In 1965, the northeastern U.S. and southeastern 

Ontario, Canada experienced the largest power blackout to date, 

impacting 30 million people.125 In response to the 1965 blackout 

and a Federal Power Commission recommendation,126 industry 

developed the National Electric Reliability Council (NERC) and 

nine reliability councils. The organization later became known 

as the North American Electric Reliability Council to recognize 

Canada’s participation.127 The North American Electric 

Reliability Council became the North American Electric 

Reliability Corporation in 2007.128 

 

124 North American Electric Reliability Corporation, History of 

NERC, at 1 (2013), available at

http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf. 

125 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 39 (2012), available at

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 

126 The Federal Power Commission, a precursor to FERC, 

recommended “the formation of a council on power coordination 

made up of representatives from each of the nation’s regional 

coordinating organizations, to exchange and disseminate 

information and to review, discuss and assist in resolving 

interregional coordination matters.” North American Electric 

Reliability Corporation, History of NERC, at 1 (2013), available 

at http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf. 127 North American Electric Reliability Corporation, History of 

NERC, at 2 (2013), available at

http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf

. The North American Electric Reliability Council became the 

North American Electric Reliability Corporation in 2007. Id. at 

4. .

128 North American Electric Reliability Corporation, History of 

NERC, at 4 (2013), available at

http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.
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In August 2003, North America experienced its worst 

blackout to date creating an outage in the Midwest, Northeast, 

and Ontario, Canada.129 This blackout was massive in scale 

impacting an area with an estimated 50 million people and 61,800 

megawatts of electric load.130 The U.S. and Canada formed a joint 

task force to investigate the causes of the blackout and made 

recommendations to avoid similar outages in the future. One of 

the task force’s major recommendations was that the U.S. 

Congress should pass legislation making electric reliability 

standards mandatory and enforceable.131

Congress responded to this recommendation in EPAct 2005, 

adding a new section 215 to the Federal Power Act making 

reliability standards mandatory and enforceable and authorizing 

 

129 North American Electric Reliability Corporation, History of 

NERC, at 3 (2013), available at

http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.

130 U.S.-Canada Power System Outage Task Force, Final Report on 

the August 14, 2003 Blackout in the United States and Canada: 

Causes and Recommendations, at 1 (Apr. 2004), available at

http://www.ferc.gov/industries/electric/indusact/reliability/blackout/ch1-3.pdf. The outage impacted areas 

within Ohio, Michigan, Pennsylvania, New York, Vermont, 

Massachusetts, Connecticut, New Jersey, and the Canadian 

province of Ontario. Id. 131 U.S.-Canada Power System Outage Task Force, Final Report on 

the August 14, 2003 Blackout in the United States and Canada: 

Causes and Recommendations, at 2 (Apr. 2004), available at

http://www.ferc.gov/industries/electric/indusact/reliability/blackout/ch1-3.pdf. 
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the creation of a new Electric Reliability Organization (ERO). 

Under this new system, FERC certifies an entity as the ERO. The 

ERO develops reliability standards, which are subject to FERC 

review and approval. Once FERC approves reliability standards 

the ERO may enforce those standards or FERC can do so 

independently.132 In 2006, the Federal Energy Regulatory 

Commission (FERC) certified NERC as the ERO.133 “NERC develops 

and enforces Reliability Standards; monitors the Bulk-Power 

System; assesses adequacy annually via a 10-year forecast and 

winter and summer forecasts; audits owners, operators and users 

for preparedness; and educates and trains industry personnel.”134

The United States, Canada, and part of Mexico are divided 

up into eight reliability regional entities.135 These regional 

entities include Florida Reliability Coordinating Council 

(FRCC), Midwest Reliability Organization (MRO), Northeast Power 

 

132 Mandatory Reliability Standards for the Bulk-Power System, 

Order No. 693, 118 FERC ¶ 61,218, at P 3 (2007) (citing 16 

U.S.C. 824o(e)(3)). 

133 Rules Concerning Certification of the Electric Reliability 

Organization; and Procedures for the Establishment, Approval, 

and Enforcement of Electric Reliability Standards, Order No. 

672, 114 FERC ¶ 61,104 (2006). 

134 North American Electric Reliability Corporation, Frequently 

Asked Questions, at 2 (Aug. 2013), available at

http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf. 

135 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 49-50 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 
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Coordinating Council (NPCC), Reliability First Corporation 

(RFC), SERC Reliability Corporation (SERC), Southwest Power 

Pool, RE (SPP), Texas Reliability Entity (TRE), and Western 

Electricity Coordinating Council (WECC).136 Regional entity 

members come from all segments of the electric industry.137 NERC 

delegates authority, with FERC approval, to these regional 

entities to enforce reliability standards, both national and 

regional reliability standards, and engage in other standardsrelated duties delegated to them by NERC.138 NERC ensures that 

 

136 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 50 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 

137 North American Electric Reliability Corporation, Key Players, 

available at

http://www.nerc.com/AboutNERC/keyplayers/Pages/default.aspx 

(last visited Mar. 12, 2015). “The members of the regional 

entities come from all segments of the electric industry: 

investor-owned utilities; federal power agencies; rural electric 

cooperatives; state, municipal and provincial utilities; 

independent power producers; power marketers; and end-use 

customers.” Id. 138 North American Electric Reliability Corporation, Frequently 

Asked Questions, at 5 (2013), available at 

http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf. 

For example, a regional entity may propose reliability 

standards, including regional variances or regional reliability 

standards required to maintain and enhance electric service 

reliability, adequacy, and security in the region. See, e.g.,

Amended and Restated Delegation Agreement Between North American 

Reliability Corporation and Midwest Reliability Organization, 

Bylaws of the Midwest Reliability Organization, Inc., Section 

2.2 (2012), available at

http://www.nerc.com/FilingsOrders/us/Regional%20Delegation%20Agr

eements%20DL/MRO_RDA_Effective_20130612.pdf. 
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there is a consistency of application of delegated functions 

with appropriate regional flexibility.139 NERC divides the 

country into assessment areas and annually analyzes the 

reliability, adequacy, and associated risks that may affect the 

upcoming summer, winter, and long-term, 10-year period. Multiple 

other entities such as FERC, the Department of Energy, state 

public utility commissions, ISOs/RTOs140, and other planning 

authorities also consider the reliability of the electric 

system. There are numerous remedies that can be utilized to 

solve a potential reliability problem, including long-term 

planning, transmission system upgrades, installation of new 

 

139 North American Electric Reliability Corporation, Frequently 

Asked Questions, at 5 (2013), available at 

http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf.

140 ISOs/RTOs plan for system needs by “effectively managing the 

load forecasting, transmission planning, and system and resource 

planning functions.” For example, the New York Independent 

System Operator (NYISO) conducts reliability planning studies, 

which “are used to assess current reliability needs based on 

user trends and historical energy use.” NYISO, Planning Studies, 

available at

http://www.nyiso.com/public/markets_operations/services/planning

/planning_studies/index.jsp. See also PJM, Reliability 

Assessments, available at https://www.pjm.com/planning/rtepdevelopment/reliability-assessments.aspx (stating that the PJM 

“Regional Transmission Expansion Planning (RTEP) process 

includes the development of periodic reliability assessments to 

address specific system reliability issues in addition to the 

ongoing expansion planning process for the interconnection 

process of generation and merchant transmission.”). 
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generating capacity, demand response, and other demand side 

actions. 

4. Modern electric system trends 

 Today, the electricity sector is undergoing a period of 

intense change. Fossil fuels – such as coal, natural gas, and 

oil – have historically provided a large percentage of 

electricity in the U.S., along with nuclear power, with smaller 

amounts provided by other types of generation, including 

nuclear, and renewables such as wind, solar, and hydroelectric 

power. Coal provided the largest percentage of the fossil fuel 

generation.141 In recent years, the nation has seen a sizeable 

increase in renewable generation such as wind and solar, as well 

as a shift from coal to natural gas.142 In 2013, fossil fuels 

supplied 67 percent of U.S. electricity,143 but the amount of 

 

141 U.S. Energy Information Administration, “Table 7.2b 

Electricity Net Generation: Electric Power Sector” data from 

Monthly Energy Review May 2015, available at

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last 

visited May 26, 2015). 

142 U.S. Energy Information Administration, “Table 7.2b 

Electricity Net Generation: Electric Power Sector” data from 

Monthly Energy Review May 2015, release data April 25, 2014, 

available at

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last 

visited May 26, 2015). 

143 U.S. Energy Information Administration, “Table 7.2b 

Electricity Net Generation: Electric Power Sector” data from 

Monthly Energy Review May 2015, release data April 25, 2014, 

available at
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renewable generation capacity continued to grow.144 From 2007 to 

2014, use of lower- and zero-carbon energy sources such as wind 

and solar grew, while other major energy sources such as coal 

and petroleum generally experienced declines.145 Renewable 

electricity generation, including from large hydro-electric 

projects, grew from 8 percent to 13 percent over that time 

period.146 Between 2000 and 2013, approximately 90 percent of new 

power generation capacity built in the U.S. came in the form of 

natural gas or renewable energy facilities.147 In 2015, the U.S. 

 

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last 

visited May 26, 2015). 

144 Based on Table 6.3 (New Utility Scale Generating Units by 

Operating Company, Plant, Month, and Year) of the U.S. Energy 

Information Administration (EIA) Electric Power Monthly, data 

for December 2013, for the following renewable energy sources: 

solar, wind, hydro, geothermal, landfill gas, and biomass. 

Available at: http:// 

www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_6_0

3. 

145 U.S. Energy Information Administration, “Table 7.2b 

Electricity Net Generation: Electric Power Sector” data from 

Monthly Energy Review May 2015, available at

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf (last 

visited May 26, 2015).

146 Bloomberg New Energy Finance and the Business Council for 

Sustainable Energy, 2015 Factbook: Sustainable Energy in 

America, at 16 (2015), available at

http://www.bcse.org/images/2015%20Sustainable%20Energy%20in%20Am

erica%20Factbook.pdf. Bloomberg gave projections for 2014 

values, accounting for seasonality, based on latest monthly 

values from EIA (data available through October 2014). 

147 Energy Information Administration, Electricity: Form EIA-860 

detailed data (Feb. 17, 2015), available at

http://www.eia.gov/electricity/data/eia860/. 
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Energy Information Administration (EIA) projected the need for 

28.4 GW of additional base load or intermediate load generation 

capacity through 2020.148 The vast majority of this new electric 

capacity (20.4 GW) is already under development (under 

construction or in advanced planning), with approximately 0.7 GW 

of new coal-fired capacity, 5.5 GW of new nuclear capacity, and 

14.2 GW of new NGCC capacity already in development. 

While the change in the resource mix has accelerated in 

recent years, wind, solar, other renewables, and energy 

efficiency resources have been reliably participating in the 

electric sector for a number of years. This rapid development of 

non-fossil fuel resources is occurring as much of the existing 

power generation fleet in the U.S. is aging and in need of 

modernization and replacement. For exampleIn 2025, the average 

age of U.S.the coal steam-fired generating fleet is projected to 

be 49 years old, and 20 percent of those units would be more 

than 60 years old if they remain in 2015 is 45.149operation at 

 

148 EIA, Annual Energy Outlook for 2015 with Projections to 2040, 

Final Release, available at

http://www.eia.gov/forecasts/AEO/pdf/0383(2015).pdf. The AEO 

numbers include projects that are under development and modelprojected nuclear, coal, and NGCC projects.

149 We calculated the average age of coal steam units based on 

the NEEDS inventory (a “snapshot” of the sector in 2016), and 

adding back units with actual/planned retirements in 2012-2016. 

See http://www.epa.gov/airmarkets/documents/ipm/needs_v514.xlsx. 
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that time. In its 2013 Report Card for America’s Infrastructure, 

the American Society for Civil Engineers noted that “America 

relies on an aging electrical grid and pipeline distribution 

systems, some of which originated in the 1880s.”150 While there 

has been an increased investment in electric transmission 

infrastructure since 2005, the report also found that “ongoing 

permitting issues, weather events, and limited maintenance have 

contributed to an increasing number of failures and power 

interruptions.”151 However, innovative technologies have 

increasingly entered the electric energy space, helping to 

provide new answers to how to meet the electricity needs of the 

nation. These new technologies can enable the nation to answer 

not just questions as to how to reliably meet electricity 

demand, but also how to meet electricity demand reliably and 

cost-effectively with the lowest possible emissions and the 

greatest efficiency. 

Natural gas has a long history of meeting electricity 

demand in the U.S., with a rapidly growing role as domestic 

 

150 American Society for Civil Engineers, 2013 Report Card for 

America’s Infrastructure (2013), available at

http://www.infrastructurereportcard.org/energy/. 

151 American Society for Civil Engineers, 2013 Report Card for 

America’s Infrastructure (2013), available at

http://www.infrastructurereportcard.org/energy/. 
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supplies of natural gas have dramatically increased. Natural gas 

net generation increased by approximately 32 percent between 

2005 and 2014.152 In 2014, natural gas accounted for 

approximately 27 percent of net generation.153 EIA projects that 

this demand growth will continue with its Annual Energy Outlook 

2015 (AEO 2015) Reference case forecasting that natural gas will 

produce 31 percent of U.S. electric generation in 2040.154 

Renewable sources of electric generation also have a 

history of meeting electricity demand in the United States and 

are expected to have an increasing role going forward. A series 

of energy crises provided the impetus for renewable energy 

development in the early 1970s. The OPEC oil embargo in 1973 and 

 

152 U.S. Energy Information Administration (EIA), Electric Power 

Monthly: Table 1.1 Net Generation by Energy Source: Total (All 

Sectors), 2005-February 2015 (2015), available at

http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=e

pmt_1_1 (last visited May 26, 2015). 

153 Id. 154 U.S. Energy Information Administration (EIA), Annual Energy 

Outlook 2015 with Projections to 2040, at 24-25 (2015), 

available at

http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf. According 

to the EIA, the reference case assumes, “Real gross domestic 

product (GDP) grows at an average annual rate of 2.4% from 2013 

to 2040, under the assumption that current laws and regulations 

remain generally unchanged throughout the projection period. 

North Sea Brent crude oil prices rise to $141/barrel (bbl) (2013 

dollars) in 2040.” Id. at 1. The EIA provides complete 

projection tables for the reference case in Appendix A of its 

report. 
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oil crisis of 1979 caused oil price spikes, more frequent energy 

shortages, and significantly affected the national and global 

economy. In 1978, partly in response to fuel security concerns, 

Congress passed the Public Utilities Regulatory Policies Act 

(PURPA) which required local electric utilities to buy power 

from qualifying facilities (QFs).155 QFs were either cogeneration 

facilities156 or small generation resources that use renewables 

such as wind, solar, biomass, geothermal, or hydroelectric power 

as their primary fuels.157 Through PURPA, Congress supported the 

development of more renewable energy generation in the U.S. 

States have also taken a significant lead in requiring the 

development of renewable resources. In particular, a number of 

states have adopted renewable portfolio standards (RPS). As of 

2013, 29 states and the District of Columbia have enforceable 

RPS or similar laws.158 

 

155 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 220-221 (2d ed. 2010). 156 Cogeneration facilities utilize a single source of fuel to 

produce both electricity and another form of energy such as heat 

or steam. Casazza, J. and Delea, F., Understanding Electric 

Power Systems, IEEE Press, at 220-221 (2d ed. 2010). 157 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 220-221 (2d ed. 2010). 158 U.S. Energy Information Administration (EIA), Annual Energy 

Outlook 2014 with Projections to 2040, at LR-5 (2014), available 

at http://www.eia.gov/forecasts/aeo/pdf/0383(2014).pdf (last 

visited May 26, 2015). 
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Use of RE continues to grow rapidly in the U.S. In 2013, 

electricity generated from renewable technologies, including 

conventional hydropower, represented 13 percent of total U.S. 

electricity.159 Total, up from 9 percent in 2005.160 In 2013, U.S.

non-hydro RE capacity was approximately 13,000 megawatts (MW) in 

1998. In 2013, for the total capacity was over five times higher 

withelectric power industry exceeded 80,000 MW of non-hydro RE 

capacity, reflecting a fivefold increase in just 15 years.161 In 

particular, there has been substantial growth in the wind and 

photovoltaic (PV) markets in the past decade. Since 2009, U.S. 

 

159 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at ES-6 (2014). 

160 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at ES-6 (2014) and Energy Information 

Administration, Monthly Energy Review, May 2015, Table 7.2b, 

available at

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf. 

161 Barbose, G., Renewables Portfolio Standards in the United 

States: A Status Update, Presentation at State-Federal RPS 

Collaborative National Summit on RPS (2013), available at

http://emp.lbl.gov/sites/all/files/rps_summit_nov_2013.pdf (last 

visited May 27, 2015). Non-hydro RE capacity for the total 

electric power industry was more than 16,000 megawatts (MW) in 

1998. Energy Information Administration, 1990-2013 Existing 

Nameplate and Net Summer Capacity by Energy Source Producer Type 

and State (EIA-860), available at

http://www.eia.gov/electricity/data/state/.
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wind energygeneration has tripled and solar capacitygeneration

has grown twenty-fold.162 

 The global market for RE is projected to grow to $460 

billion per year by 2030.163 RE growth is further encouraged by 

the significant amount of existing natural resources that can 

support RE production (solar, water, wind, and geothermal) in 

the United States.164 In the Energy Information Administration’s 

Annual Energy Outlook 2015, RE generation grows substantially 

from 2013 to 2040 in the reference case and all alternative 

cases.165 In the reference case, RE generation increases by more 

than 70 percent from 2013 to 2040 and accounts for over onethird of new generation capacity.166 Rapid growth in RE 

 

162 Energy Information Administration, Monthly Energy Review, May 

2015, Table 7.2b, available at

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf. 

163 “Global Renewable Energy Market Outlook.” Bloomberg New Energy 

Finance (Nov. 16, 2011), available at 

http://bnef.com/WhitePapers/download/53.

164 Lopez et al., NREL, ‘‘U.S. Renewable Energy 

Technical Potentials: A GIS-Based Analysis,’’ (July 2012).

165

 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at 25 (2014), available at

http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf. 

166 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at ES-6 (2015), available at

http://www.eia.gov/forecasts/aeo/pdf/0383(2015).pdf (last 

visited May 27, 2015).
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generation is projected to continue as costs of RE generation 

fall relative to the costs of other generation technologies.

Price pressures caused by oil embargoes in the 1970s also 

brought the issues of conservation and energy efficiency to the 

forefront of U.S. energy policy.167 This trend continued in the 

early 1990s. Energy efficiency has been utilized to meet energy 

demand to varying levels since that time. As of April 2014, 25 

states168 have “enacted long-term (3+ years), binding energy 

savings targets, or energy efficiency resource standards 

 

167 Edison Electric Institute, Making a Business of Energy 

Efficiency: Sustainable Business Models for Utilities, at 1 

(2007), available at

http://www.eei.org/whatwedo/PublicPolicyAdvocacy/StateRegulation

/Documents/Making_Business_Energy_Efficiency.pdf. Congress 

passed legislation in the 1970s that jumpstarted energy 

efficiency in the U.S. For example, President Ford signed the 

Energy Policy and Conservation Act (EPCA) of 1975 – the first 

law on the issue. EPCA authorized the Federal Energy 

Administration (FEA) to “develop energy conservation contingency 

plans, established vehicle fuel economy standards, and 

authorized the creation of efficiency standards for major 

household appliances.” Alliance to Save Energy, History of 

Energy Efficiency, at 6 (2013) (citing Anders, “The Federal 

Energy Administration,” 5; Energy Policy and Conservation Act, 

S. 622, 94th Cong. (1975-1976)), available at

https://www.ase.org/sites/ase.org/files/resources/Media%20browse

r/ee_commission_history_report_2-1-13.pdf. 

168 American Council for an Energy-Efficient Economy, State 

Energy Efficiency Resource Standards (EERS) (2014), available at 

http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf. ACEEE 

did not include Indiana (EERS eliminated), Delaware (EERS 

pending), Florida (programs funded at levels far below what is 

necessary to meet targets), Utah, or Virginia (voluntary 

standards) in its calculation. 
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(EERS).”169 Funding for energy efficiency programs has grown 

rapidly in recent years, with budgets for electric efficiency 

programs totaling $5.9 billion in 2012.170 

 Advancements and innovation in power sector technologies 

provide the opportunity to address CO2 emission levels at 

affected power plants while at the same time improving the 

overall power system in the U.S. by lowering the carbon 

intensity of power generation, and ensuring a reliable supply of 

power at a reasonable cost. 

E. Clean Air Act Regulations for Power Plants 

In this section, we provide a general description of major 

CAA regulations for power plants. We refer to these in later 

sections of this preamble. 

1. Title IV Acid Rain Program 

The EPA’s Acid Rain Program, established in 1990 under 

Title IV of the CAA, addresses the presence of acidic compounds 

and their precursors (i.e., SO2 and NOx), in the atmosphere by 

targeting “the principal sources” of these pollutants through an 

 

169 American Council for an Energy-Efficient Economy, State 

Energy Efficiency Resource Standards (EERS) (2014), available at 

http://aceee.org/files/pdf/policy-brief/eers-04-2014.pdf. 

170 American Council for an Energy-Efficient Economy, The 2013 

State Energy Efficiency Scorecard, at 17 (Nov. 2013), available 

at

http://aceee.org/sites/default/files/publications/researchreport

s/e13k.pdf. 
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SO2 cap-and-trade program for fossil-fuel fired power plants and 

through a technology based NOx emission limit for certain utility 

boilers. Altogether, Title IV was designed to achieve reductions 

of ten million tons of annual SO2 emissions, and, in combination 

with other provisions of the CAA, two million tons of annual NOx

emissions.171 

 The SO2 cap-and-trade program was implemented in two phases. 

The first phase, beginning in 1995, targeted one-hundred and ten 

named power plants, including specific generator units at each 

plant, requiring the plants to reduce their cumulative emissions 

to a specific level.172 Under certain conditions, the owner or 

operator of a named power plant could reassign an affected 

unit’s reduction requirement to another unit and/or request an 

extension of two years for meeting the requirement.173 Congress 

also established an energy conservation and renewable energy 

reserve from which up to 300,000 allowances could be allocated 

for qualified energy conservation measures or qualified 

renewable energy.174 

 

171 42 U.S.C. § 7651(b). 172 42 U.S.C. § 7651c (Table A). 173 42 U.S.C. § 7651c(b) and (d). 174 42 U.S.C. § 7651c(f) and (g). 
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The second phase, beginning in 2000, expanded coverage to 

more than 2,000 generating units and set a national cap at 8.90 

million tons.175 Generally, allowances were allocated at a rate 

of 1.2 lbs./mmBtu multiplied by the unit’s baseline and divided 

by 2000.176 However, bonus allowances could be awarded to certain 

units. 

Title IV also required the EPA to hold or sponsor annual 

auctions and sales of allowances for a small portion of the 

total allowances allocated each year. This ensured that some 

allowances would be directly available for new sources, 

including independent power production facilities.177 

The provisions of the EPA’s Acid Rain Program are 

implemented through permits issued under the EPA’s Title V 

Operating Permit Program.178 In accordance with Title IV, 

moreover, each Title V permit application must include a 

compliance plan for the affected source that details how that 

source expects to meet the requirements of Title IV.179 

 

175 U.S. Dept. of Energy, Energy Information Administration, “The 

Effects of Title IV of the Clean Air Act Amendments of 1990 on 

Electric Utilities: An Update,” p. vii. (March 1997). 

176 See 42 U.S.C. § 7651d. 177 42 U.S.C. § 7651o. 178 42 U.S.C. § 7651g. 179 Such plans may simply state that the owner or operator 

expects to hold sufficient allowances or, in the case of 

alternative compliance methods, must provide a “comprehensive 
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2. Transport rulemakings 

CAA section 110(a)(2)(D)(i)(I), the “Good Neighbor 

Provision,” requires state implementation plans (SIPs) to 

prohibit emissions that “contribute significantly to 

nonattainment . . . or interfere with maintenance” of the NAAQS 

in any other state.180 If the EPA finds that a state has failed 

to submit an approvable SIP, the EPA must issue a federal 

implementation plan (FIP) to prohibit those emissions “at any 

time” within the next two years.181

In three major rulemakings — the NOx SIP Call,182 the Clean 

Air Interstate Rule (CAIR),183 and the Cross State Air Pollution 

Rule (CSAPR)184 — the EPA has attempted to delineate the scope of 

the Good Neighbor Provision. These rulemakings have several 

features in common. Although the Good Neighbor Provision does 

not speak specifically about EGUs, in all three rulemakings, the 

EPA set state emission “budgets” for upwind states based in part 

on emissions reductions achievable by EGUs through application 

 

description of the schedule and means by which the unit will 

rely on one or more alternative methods of compliance in the 

manner and time authorized under [Title IV].” 42 U.S.C. § 

7651g(b). 

180 42 U.S.C. § 7410(a)(2)(D)(i)(I). 181 EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584, 

1600–01 (2014) (citing 42 U.S.C. § 7410(c)). 

182 63 FR 57356 (Oct. 27, 1998). 183 70 FR 25162 (May 12, 2005). 184 76 FR 48208 (Aug. 8, 2011). 
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of cost-effective controls. Each rule also adopted a phased 

approach to reducing emissions with both interim and final 

goals. 

a. NOx SIP Call. In 1998, the EPA promulgated the NOx SIP Call, 

which required 23 upwind states to reduce emissions of NOx that 

would impact downwind areas with ozone problems. The EPA 

determined emission reduction requirements based on reductions 

achievable through “highly cost-effective” controls—i.e., 

controls that would cost on average no more than $2,000 per ton 

of emissions reduced.185 The EPA determined that a uniform 

emission rate on large EGUs coupled with a cap-and-trade program 

was one such set of highly cost-effective controls.186 

Accordingly, the EPA established an interstate cap-and-trade 

program—the NOx Budget Trading Program—as a mechanism for states 

to reduce emissions from EGUs and other sources in a highly 

cost-effective manner. The D.C. Circuit upheld the NOx SIP Call 

in most significant respects, including its use of costs to 

apportion emission reduction responsibilities.187 

 

185 63 FR at 57377–78. 186 63 FR at 57377–78. In addition to EGUs, the NOx SIP Call also 

set budgets based on highly cost-effective emission reductions 

from certain other large sources. Id. 187 Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000). 
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b. Clean Air Interstate Rule (CAIR). In 2005, the EPA 

promulgated CAIR, which required 28 upwind states to reduce 

emissions of NOx and SO2 that would impact downwind areas with 

projected nonattainment and maintenance problems for ozone and 

PM2.5. The EPA determined emission reduction requirements based 

on “controls that are known to be highly cost effective for 

EGUs.”188 The EPA established cap-and-trade programs for sources 

of NOx and SO2 in states that chose to participate in the trading 

programs via their SIPs and for states ultimately subject to a 

FIP.189 As relevant here, the D.C. Circuit remanded CAIR in North 

Carolina v. EPA due to in part the structure of its interstate 

trading provisions and the way in which EPA applied the costeffective standard, but kept the rule in place while the EPA 

developed an acceptable substitute.190

c. Cross-state Air Pollution Rule (CSAPR). In 2011, the EPA 

promulgated CSAPR, which required 27 upwind states to reduce 

emissions of NOx and SO2 that would impact downwind areas with 

projected nonattainment and maintenance problems for ozone and 

PM2.5. The EPA determined emission reduction requirements based 

 

188 70 FR at 25163. 189 70 FR at 25273–75; 71 FR 25328 (April 28, 2006). 190 531 F.3d 896, 917–22 (D.C. Cir. 2008), modified on rehearing 

550 F.3d 1176, 1178 (D.C. Cir. 2008). 
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in part on the reductions achievable at certain cost thresholds 

by EGUs in each state, with certain provisions developed to 

account for the need to ensure reliability of the electric 

generating system.191 In the same action establishing these 

emission reduction requirements, the EPA promulgated FIPs that 

subjected states to trading programs developed to achieve the 

necessary reductions within each state.192 The U.S. Supreme Court 

upheld the EPA’s use of cost to set emission reduction 

requirements, as well as its authority to issue the FIPs.193 

3. Clean Air Mercury Rule 

On March 15, 2005, the EPA issued a rule to control mercury 

(Hg) emissions from new and existing fossil fuel-fired power 

plants under CAA section 111(b) and (d). The rule, known as the 

Clean Air Mercury Rule (CAMR), established, in relevant part, a 

nationwide cap-and-trade program under CAA section 111(d), which 

was designed to complement the cap-and-trade program for SO2 and 

NOx emissions under the Clean Air Interstate Rule (CAIR), 

discussed above.194 Though CAMR was later vacated by the D.C. 

 

191 76 FR at 48270. The EPA adopted this approach in part to 

comport with the D.C. Circuit’s opinion in North Carolina v. EPA 

remanding CAIR. Id. at 48270–71. 192 76 FR at 48209–16. 193 EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584 

(2014).

194 See 70 FR 28606 (May 18, 2005). 
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Circuit on account of the EPA’s flawed CAA section 112 delisting 

rule, the court declined to reach the merits of the EPA’s 

interpretation of CAA section 111(d).195 Accordingly, CAMR 

continues to be an informative model for a cap-and-trade program 

under CAA section 111(d). 

The cap-and-trade program in CAMR was designed to take 

effect in two phases: in 2010, the cap was set at 38 tons of 

mercury per year, and in 2018, the cap would be lowered to 15 

tons per year. The Phase I cap was set at a level reflecting the 

co-benefits of CAIR as determined through economic and 

environmental modeling.196 For the more stringent Phase II cap, 

the EPA projected that sources would “install SCR [selective 

catalytic reduction] to meet their SO2 and NOx requirements and 

take additional steps to address the remaining Hg reduction 

requirements under CAA section 111, including adding Hg-specific 

control technologies (model applies ACI [activated carbon 

injection]), additional scrubbers and SCR, dispatch changes, and 

coal switching.”197 Based on this analysis, EPA determined that 

 

195 New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). 196 70 FR 28606, at 28617. The EPA’s projections under CAIR 

showed a significant number of affected sources would install 

scrubbers for SO2 and selective catalytic reduction for NOx on 

coal-fired power plants, which had the co-benefit of capturing 

mercury emissions. Id. at 28619. 197 70 FR 28606, at 28619. 
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the BSER “refers to the combination of the cap-and-trade 

mechanism and the technology needed to achieve the chosen cap 

level.”198

To accompany the nationwide emissions cap, the EPA also 

assigned a statewide emissions budget for mercury. Pursuant to 

CAA section 111(d), states would be required to submit plans to 

the EPA “detailing the controls that will be implemented to meet 

its specified budget for reductions from coal-fired Utility 

Units.”199 Of course, states were “not required to adopt and 

implement” the emission trading program, “but they [were] 

required to be in compliance with their statewide Hg emission 

budget.”200 

4. Mercury Air Toxics Rule 

On February 16, 2012, the EPA issued the MATS rule (77 FR 

9304) to reduce emissions of toxic air pollutants from new and 

existing coal- and oil-fired EGUs. The MATS rule will reduce 

emissions of heavy metals, including mercury, arsenic, chromium, 

and nickel; and acid gases, including hydrochloric acid and 

hydrofluoric acid. These toxic air pollutants, also known as 

 

198 70 FR 28606, at 28620. 199 70 FR 28606, at 28621. 200 70 FR 28606, at 28621. That said, states could “require 

reductions beyond those required by the [s]tate budget.” Id. at 

28621. 
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hazardous air pollutants or air toxics, are known to cause, or 

suspected of causing, nervous system damage, cancer, and other 

serious health effects. The MATS rule will also reduce SO2 and 

fine particle pollution, which will reduce particle 

concentrations in the air and prevent thousands of premature 

deaths and tens of thousands of heart attacks, bronchitis cases 

and asthma episodes. 

New or reconstructed EGUs (i.e., sources that commence 

construction or reconstruction after May 3, 2011) subject to the 

MATS rule are required to comply by April 16, 2012 or upon 

startup, whichever is later. 

Existing sources subject to the MATS rule were required to 

begin meeting the rule’s requirements on April 16, 2015. 

Controls that will achieve the MATS performance standards are 

being installed on many units. Certain units, especially those 

that operate infrequently, may be considered not worth investing 

in given today’s electricity market, and are closing. The final 

MATS rule provided a foundation on which states and other 

permitting authorities could rely in granting an additional, 

fourth year for compliance provided for by the CAA. States 

report that these fourth year extensions are being granted. In 

addition, the EPA issued an enforcement policy that provides a 

clear pathway for reliability-critical units to receive an 
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administrative order that includes a compliance schedule of up 

to an additional year, if it is needed to ensure electricity 

reliability. 

Following promulgation of the MATS rule, industry, states 

and environmental organizations challenged many aspects of the 

EPA's threshold determination that regulation of EGUs is 

"appropriate and necessary" and the final standards regulating 

hazardous air pollutants from EGUs. The U.S. Court of Appeals 

for the D.C. Circuit upheld all aspects of the MATS rule. White 

Stallion Energy Center v. EPA, 748 F.3d 1222 (D.C. Cir. 

2014). In Michigan v. EPA, case no. 14-46, the U.S. Supreme 

Court reversed the portion of the D.C. Circuit decisionfinding 

the EPA was not required to consider cost when determining 

whether regulation of EGUs was "appropriate" pursuant to section 

112(n)(1). The Supreme Court considered only the narrow question 

of whether the EPA erred in not considering cost when making 

this threshold determination. The Court’s decision did not 

disturb any of the other holdings of the D.C. Circuit. The 

Court remanded the case to the D.C. Circuit for further 

proceedings, and the MATS rule remains in place at this time. 
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5. Regional Haze Rule D. Congress’ Awareness of Climatic 

Change201 

 As early as 1970 

Under CAA section 169A, Congress “declare[d] as a national 

goal the prevention of any future, and the remedying of any 

existing, impairment of visibility” in national parks and 

wilderness areas that results from anthropogenic emissions.202 To 

achieve this goal, Congress directed the EPA to promulgate 

regulations directing states to submit SIPs that “contain such 

emission limits, schedules of compliance and other measures as 

may be necessary to make reasonable progress toward meeting the 

national goal . . . .”203 One such measure that Congress deemed 

necessary to make reasonable progress was a requirement that 

certain older stationary sources that cause or contribute to 

visibility impairment “procure, install, and operate, as 

expeditiously as practicable . . . the best available retrofit 

technology,” more commonly referred to as BART.204 When 

determining BART for large fossil-fuel fired utility power 

 

201 The following discussion is not meant to be exhaustive; 

indeed, there are many other instances, including outside the 

context of the CAA, where Congress discussed climate change. 

202 42 U.S.C. § 7491(a)(1). 203 42 U.S.C. § 7491(b)(2). 204 42 U.S.C. § 7491(b)(2)(A). 
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plants, Congress required states to adhere to guidelines to be 

promulgated by the EPA.205 As with other SIP-based programs, the 

EPA is required to issue a FIP within two years if a state fails 

to submit a regional haze SIP or if the EPA disapproves such SIP 

in whole or in part.206

 In 1999, the EPA promulgated the Regional Haze Rule to 

satisfy Congress’ mandate that EPA promulgate regulations 

directing states to address visibility impairment.207 Among other 

things, the Regional Haze Rule allows states to satisfy the 

Act’s BART requirement either by adopting source-specific 

emission limitations or by adopting alternatives, such as 

emissions-trading programs, that achieve greater reasonable 

progress than would source-specific BART.208 The Ninth Circuit 

and D.C. Circuit have both upheld the EPA’s interpretation that 

CAA section 169A(b)(2) allows for BART alternatives in lieu of 

source-specific BART.209 In 2005, the EPA promulgated BART 

Guidelines to assist states in determining which sources are 

 

205 42 U.S.C. § 7491(b)(2). 206 42 U.S.C. §§ 7410(c); 7491(b)(2)(A). 207 64 FR 35714 (July 1, 1999) (codified at 40 CFR 51.308-309). 208 40 CFR 51.308(e)(1) & (2). 209 See Utility Air Regulatory Grp. v. EPA, 471 F.3d 1333 (D.C. 

Cir. 2006); Ctr. for Econ. Dev. v. EPA, 398 F.3d 653 (D.C. Cir. 

2005); Cent. Ariz. Water Dist. v. EPA, 990 F.2d 1531 (9th Cir. 

1993). 
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subject to BART and what emission limitations to impose at those 

sources.210

 The Regional Haze Rule set a goal of achieving natural 

visibility conditions by 2064 and requires states to revise 

their regional haze SIPs every ten years.211 The first planning 

period, which ends in 2018, focused heavily on the BART 

requirement. States (or the EPA in the case of FIPs) made 

numerous source-specific BART determinations, and developed 

several BART alternatives, for utility power plants. For the 

next planning period, states will need to determine whether 

additional controls are necessary at these plants (and others 

that were not subject to BART) in order to make reasonable 

progress towards the national visibility goal.212

F. Congressional Awareness of Climate Change in the Context of 

the Clean Air Act Amendments213 

 During its deliberations on the 1970 Clean Air Act 

Amendments, Congress learned that ongoing pollution, including 

 

210 70 FR 39104 (July 6, 2005) (codified at 40 CFR pt. 51, app. 

Y). 

211 See 40 CFR 51.308(d)(1)(i)(B), (f). 212 See 42 U.S.C. § 7491(b)(2); 40 CFR 51.308(d)(3). 213 The following discussion is not meant to be exhaustive. There 

are many other instances outside the context of the CAA, before 

and after 1970, when Congress discussed or was presented with 

evidence on climate change. 
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from manmade carbon dioxide, could “threaten irreversible 

atmospheric and climatic changes.”214 Likewise,At that time, 

Congress heard the views of scientists that carbon dioxide 

emissions tended to increase global temperatures, but that there 

was uncertainty as to the extent to which those increases would 

be offset by the decreases in temperatures brought about by 

emissions of particulates. President Nixon’s Council on 

Environmental Quality (CEQ) reported that “the addition of 

particulates and carbon dioxide in the atmosphere could have 

dramatic and long-term effects on world climate.”215 In fact, 

theThe CEQ’s First Annual Report, which was transmitted to 

Congress, devoted an entirea chapter to “Man’s Inadvertent 

Modification of Weather and Climate.”216 Moreover, Charles 

Johnson, Jr., Administrator of the Consumer Protection and 

Environmental Health Service even, testified before the House 

 

214 Sen. Scott, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA 

Legis. Hist. at 349.

215 Council on Environmental Quality, “The First Annual Report of 

the Council on Environmental Quality,” p. 110 (Aug. 1970) 

(recognizing also that “[man] can increase the carbon dioxide 

content of the atmosphere by burning fossil fuels” and 

postulating that an increase in the earth’s average temperature 

by about 2o to 3o F “could in a period of decades, lead to the 

start of substantial melting of ice caps and flooding of coastal 

regions.”). 

216 Council on Environmental Quality, “The First Annual Report of 

the Council on Environmental Quality,” p. 93-104 (Aug. 1970) 
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Subcommittee on Public Health that “the carbon dioxide balance 

might result in the heating up of the atmosphere whereas the 

reduction of the radiant energy through particulate matter 

released to the atmosphere might cause reduction in radiation 

that reaches the earth.”217 Administrator Johnson explained that 

the Nixon Administration was “concerned ...... that neither of 

these things happen” and that they were “watching carefully the 

kind of prognosis, the kind of calculations that the scientists 

make to look at the continuous balance between heat and cooling 

of the total earth’s atmosphere.”218 He concluded that “[w]hat we 

are trying to do, however, in terms of our air pollution effort 

should have a very salutary effect on either of these.”219

Climatic effectsScientific reports on climatic change

continued to gain Congressional attention by traction in 

 

217 Testimony of Charles Johnson, Jr., Administrator of the 

Consumer Protection and Environmental Health Service 

(Administration Testimony), Hearing of the House Subcommittee on 

Public Health and Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. 

at 1381. 

218 Testimony of Charles Johnson, Jr., Administrator of the 

Consumer Protection and Environmental Health Service 

(Administration Testimony), Hearing of the House Subcommittee on 

Public Health and Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. 

at 1381. 

219 Testimony of Charles Johnson, Jr., Administrator of the 

Consumer Protection and Environmental Health Service 

(Administration Testimony), Hearing of the House Subcommittee on 

Public Health and Welfare (Mar. 16, 1970), 1970 CAA Legis. Hist. 

at 1381. 
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Congress through the mid-1970s, including while Congress was 

considering the 1977 CAA Amendments. However, scientific studies 

remained inconclusiveuncertainty continued as to whether the 

increased warming orbrought about by carbon dioxide emissions 

would be offset by cooling trends.220 In deference to that 

uncertainty, andbrought about by particulate emissions.221

 

220 For instance, while scientists, such as Stephen Schneider of 

the National Center for Atmospheric Research, testified that 

“manmade pollutants will affect the climate,” they believed that 

we would “see a general cooling of the Earth’s atmosphere.” Rep. 

Scheuer, H. Debates on H.R. 10498 (Sept. 15, 1976), 1977 CAA 

Legis. Hist. at 6477. Additionally, the Department of 

Transportation’s climatic impact assessment program and the 

Climatic Impact Committee of the National Research Council, 

National Academies of Science and Engineering both reported that 

“warming or cooling” could occur. Id. at 6476. See also Sen. 

Bumpers, Sen. Debates on S. 3219 (August 3, 1976), 1977 CAA 

Legis. Hist. at 5368 (inserting “Summary of Statements Received 

[in the Subcommittee on the Environment and the Atmosphere] from 

Professional Societies for the Hearings on Effects of Chronic 

Pollution” into the record, which noted that “there is near 

unamity [sic] that carbon dioxide concentrations in the 

atmosphere are increasing rapidly.”). 

221 For instance, while scientists, such as Stephen Schneider of 

the National Center for Atmospheric Research, testified that 

“manmade pollutants will affect the climate,” they believed that 

we would “see a general cooling of the Earth’s atmosphere.” Rep. 

Scheuer, H. Debates on H.R. 10498 (Sept. 15, 1976), 1977 CAA 

Legis. Hist. at 6477. Additionally, the Department of 

Transportation’s climatic impact assessment program and the 

Climatic Impact Committee of the National Research Council, 

National Academies of Science and Engineering both reported that 

“warming or cooling” could occur. Id. at 6476. See also Sen. 

Bumpers, S. Debates on S. 3219 (August 3, 1976), 1977 CAA Legis. 

Hist. at 5368 (inserting “Summary of Statements Received [in the 

Subcommittee on the Environment and the Atmosphere] from 

Professional Societies for the Hearings on Effects of Chronic 
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Congress ordered, as part of the 1977 CAA Amendments, Congress 

ordered the National Oceanic and Atmospheric Administration to 

research and monitor the stratosphere “for the purpose of early 

detection of changes in the stratosphere and climatic effects of 

such changes.”222 

Finally, inBetween the 1977 and 1990 CAAClean Air Act 

Amendments, scientific uncertainty yielded to the predominant 

view that global warming “was likely to dominate on time scales 

that would be significant to human societies.”223 In fact, as 

part of the 1990 Clean Air Act Amendments, Congress specifically 

required the EPA to collect data on carbon dioxide emissions –- 

the most significant of the greenhouse gases -- from all sources 

subject to the newly enacted operating permit program.224 The 

provision recognizes that “[s]cientists have disagreed about the 

scope and magnitude of global under Title V.225 Although 

Congress did not require the EPA to take immediate action to 

 

Pollution” into the record, which noted that “there is near 

unamity [sic] that carbon dioxide concentrations in the 

atmosphere are increasing rapidly.”). 

222 “Clean Air Act Amendments of 1977,” § 125, 91 Stat. at 728. 223 Peterson, Thomas C., William M. Connolley, and John Fleck, 

“The Myth of the 1970s Global Cooling Scientific Consensus,” 

Bulletin of the American Meteorological Society, p. 1326 

(September 2008), available at 

http://journals.ametsoc.org/doi/pdf/10.1175/2008BAMS2370.1. 

224 “Clean Air Act Amendments of 1990,” § 820, 104 Stat. at 2699. 225 “Clean Air Act Amendments of 1990,” § 820, 104 Stat. at 2699. 
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address climate change from manmade air pollution, and much of 

that disagreement stems from lack of necessary data to assess 

the impact these emissions may have on the Earth’s climate.”226

Accordingly, the provision “helps fill this information gap.”227

It was designed to “give us a head start if and when we need to 

take steps to reduce our carbon dioxide emissions.”228

, Congress also recognized thatdid identify certain tools 

that were particularly helpful in addressing climate change. For 

instance, in the utility power sector. The Senate report 

discussing the acid rain provisions of Title IV noted that 

“[e]nergysome of the measures that would reduce coal-fired power 

plant emissions of the precursors to acid rain would also reduce 

those facilities’ emissions of carbon dioxide. The report 

stated: 

Energy efficiency is a crucial tool for controlling 

the emissions of carbon dioxide, the gas chiefly 

responsible for the intensification of the atmospheric 

‘greenhouse effect.’”229 Similarly, In the last several 

years, the Committee has received extensive scientific 

testimony that increases in the human-caused emissions 

of carbon dioxide and other greenhouse gases will lead 

 

226 Rep. Moorhead, H. Debate on H.R. 3030 (May 21, 1990), 1990 

CAA Legis. Hist. at 2612. 

227 Rep. Moorhead, H. Debate on H.R. 3030 (May 21, 1990), 1990 

CAA Legis. Hist. at 2612. 

228 Rep. Moorhead, H. Debate on H.R. 3030 (May 21, 1990), 1990 

CAA Legis. Hist. at 2613. 

229 Sen. Chaffe, Sen. Debate on S. 1630 (Jan. 24, 1990), 1990 CAA 

Legis. Hist. at 8662. 
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to catastrophic shocks in the global climate system. 

Accordingly, new title IV shapes an acid rain 

reduction policy that encourages energy efficiency and 

other policies aimed at controlling greenhouse 

gases.230 

Similarly, Title IV provisions to encourage renewable energy 

were justified because “renewables not only significantly 

curtail sulfur dioxide emissions, but they emit little or no 

nitrogen oxides and carbon dioxide”.231

EG. International Agreements and Actions 

In this final rule, the United States is taking action to 

limit GHGs from one of its largest emission sources. Climate 

change is a global problem, and the United States is not alone 

in taking action to address it. The United Nations Framework 

Convention on Climate Change (UNFCCC)232 is the international 

treaty under which countries (called “Parties”) cooperatively 

consider what can be done to limit anthropogenic climate 

change233 and adapt to climate change impacts. Currently, there 

 

230 Sen. Chaffe, S. Debate on S. 1630 (Jan. 24, 1990), 1990 CAA 

Legis. Hist. at 8662. 

231 Additional Views of Rep. Markey and Rep. Moorhead, H.R. Rep. 

No. 101-490, at 674 (May 17, 1990). 

232 http://unfccc.int/2860.php 233 Article 2, Objective, The ultimate objective of this 

Convention and any related legal instruments that the Conference 

of the Parties may adopt is to achieve, in accordance with the 

relevant provisions of the Convention, stabilization of 

greenhouse gas concentrations in the atmosphere at a level that 

would prevent dangerous anthropogenic interference with the 
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are 195 Parties to the UNFCCC, including the United States. The 

Conference of the Parties (COP) meets annually and is currently 

considering commitments countries can make to limit emissions 

after 2020. The 2015 COP will be in Paris, and countries will 

announce their post-2020 commitments there or beforehand. In 

April 2015, the United States announced its commitment to reduce 

GHG emissions 26-28% below 2005 levels by 2025.234The 2015 COP 

will be in Paris and is expected to represent an historic step 

for climate change mitigation. The Parties to the UNFCC will 

meet to establish a climate agreement that applies to all 

countries and focuses on reducing greenhouse gas emissions. Such 

an outcome would send a beneficial signal to the markets and 

civil society about global action to address climate change. 

Many countries have announced their intended post-2020 

commitments already, and other countries are expected to do so 

 

climate system. Such a level should be achieved within a time 

frame sufficient to allow ecosystems to adapt naturally to 

climate change, to ensure that food production is not threatened 

and to enable economic development to proceed in a sustainable 

manner. 

http://unfccc.int/files/essential_background/convention/backgrou

nd/application/pdf/convention_text_with_annexes_english_for_post

ing.pdf 

234 United States Cover Note to Intended Nationally Determined 

Contribution (INDC). Available online at:

http://www4.unfccc.int/submissions/INDC/Published%20Documents/Un

ited%20States%20of%20America/1/U.S.%20Cover%20Note%20INDC%20and%

20Accompanying%20Information.pdf
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before December. In April 2015, the United States announced its 

commitment to reduce GHG emissions 26-28 percent below 2005 

levels by 2025.235

 As Parties to both the UNFCCC and the Kyoto Protocol236, the 

European Union (EU) and member countries have taken aggressive 

action to reduce GHG emissions.237 EU initiatives to reduce 

greenhouse gas emissions include the EU Emissions Trading 

System, legislation to increase the adoption of renewable energy 

sources, strengthened energy efficiency targets, vehicle 

emission standards, and support for the development of CCS 

technology for use by the power sector and other industrial 

sources. In 2009, the EU announced its “20-20-20 targets,” 

including a 20% percent reduction in GHG emissions from 1990 

levels by 2020, an increase of 20% percent in the share of 

energy consumption produced by renewable resources, and a 20% 

percent improvement in energy efficiency. In March 2015, the EU 

announced its commitment to reduce domestic GHG emissions by at 

least 40% from 1990 levels by 2030.

 

235 United States Cover Note to Intended Nationally Determined 

Contribution (INDC). Available online at:

http://www4.unfccc.int/submissions/INDC/Published%20Documents/Un

ited%20States%20of%20America/1/U.S.%20Cover%20Note%20INDC%20and%

20Accompanying%20Information.pdf

236 http://unfccc.int/kyoto_protocol/items/2830.php 237 http://ec.europa.eu/clima/policies/brief/eu/index_en.htm 
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 Recently, China has also agreed to take action to address 

climate change. In November 2014, in a joint announcement by 

President Obama and China’s President Xi, China pledged to 

curtail GHG emissions, with emissions peaking in 2030 and then 

declining thereafter, and to increase the share of energy from 

non-carbon sources (solar, wind, hydropower, nuclear) to 20 

percent by 2030. 

Mexico is committed to reduce unconditionally 25% percent

of its emissions of greenhouse gases and short lived climate 

pollutants (below business as usual) for the year 2030. This 

commitment implies a 22 percent reduction of GHG emissions and a 

51 percent reduction of black carbon emissions. 

Brazil has reduced its net CO2 emissions more than any other 

country through a historic effort to slow forest loss. The 

deforestation rate in Brazil in 2014 was roughly 75% percent

below the average for 1996 to 2005.238  

Together, countries that have already announced their 

intended post-2020 commitments, including the U.S., China, 

European Union, Mexico, Russian Federation and Brazil, make up a 

large majority of global emissions. 

 

238 http://www.nature.com/news/stopping-deforestation-battle-forthe-amazon-1.17223 
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President Obama’s Climate Action Plan contains a number of 

policies and programs that are intended to cut carbon pollution 

that causes climate change and affects public health. The Clean 

Power Plan is a key component of the plan, addressing the 

nation’s largest source of emissions in a comprehensive manner. 

Collectively, these policies will help spark business 

innovation, result in cleaner forms of energy, create jobs, and 

cut dependence on foreign oil. They also demonstrate to the rest 

of the world that the United States is contributing its share of 

the global effort that is needed to address climate change.239 

This demonstration encourages other major economies to take on 

similar contributions, which is critical given the global impact 

of greenhouse gas emissions. The State Department Special Envoy 

for Climate Change Todd Stern, the lead U.S. climate change 

negotiator, noted the connection between domestic and 

international action to address climate change in his speech at 

Yale University on October 14, 2014: 

“This mobilization of American effort matters. Enormously. It 

matters because the United States is the biggest economy and 

 

239 President Obama stated, in announcing the Climate Action 

Plan: 

“The actions I’ve announced today should send a strong 

signal to the world that America intends to take bold 

action to reduce carbon pollution. We will continue to lead 

by the power of our example, because that’s what the United 

States of America has always done.” President Obama, 

Climate Action Plan speech, Georgetown University, 2013. 
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largest historic emitter of greenhouse gases. Because, here, 

as in so many areas, we feel a responsibility to lead. And 

because here, as in so many areas, we find that American 

commitment is indispensable to effective international action. 

And make no mistake – other countries see what we are doing 

and are taking note. As I travel the world and meet with my 

counterparts, the palpable engagement of President Obama and 

his team has put us in a stronger, more credible position than 

ever before.” 

This final rule demonstrates to other countries that the 

United States is taking action to limit GHG emissions from its 

largest emission sources, in line with our international 

commitments. The impact of GHGs is global, and U.S. action to 

reduce GHG emissions complements and encourages ongoing programs 

and efforts in other countries.

FH. Legislative and Regulatory Background for CAA Section 111 

In the final days of December 1970, Congress enacted 

sweeping changes to the Air Quality Act of 1967 to confront an 

“environmental crisis.”240 The Air Quality Act—which expanded 

federal air pollution control efforts after the enactment of the 

Clean Air Act of 1963—prioritized the adoption of ambient air 

standards but failed to target stationary sources of air 

pollution. As a result, “[c]ities up and down the east coast 

were living under clouds of smoke and daily air pollution 

 

240 Sen. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA 

Legis. Hist. at 224. 
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alerts.”241 In fact, “[o]ver 200 million tons of contaminants ...

spilled into the air” each year.242 The 1970 CAA Amendments were 

designed to face this crisis “with urgency and in candor.”243 

For the most part, Congress gave EPA and the states 

flexible tools to implement the CAA. This is best exhibited by 

the newly enacted programs regulating stationary sources. For 

these sources, Congress crafted a three-legged regime upon which 

the regulation of stationary sources was intended to sit. 

The first prong—CAA sections 107-110—addressed what are 

commonly referred to as criteria pollutants, “the presence of 

which in the ambient air results from numerous or diverse mobile 

or stationary sources” and are determined to have “an adverse 

effect on public health or welfare”.244 Under these provisions, 

states would have the primary responsibility for assuring air 

 

241 Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-1783 

(Dec. 18, 1970), 1970 CAA Legis. Hist. at 123. 

242 Sen. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA 

Legis. Hist. at 224. These pollutants fell into five main 

classes of pollutants: carbon monoxide, particulates, sulfur 

oxides, hydrocarbons, and nitrogen oxides. See Sen. Boggs, id. 

at 244. 

243 Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-1783 

(Dec. 18, 1970), 1970 CAA Legis. Hist. at 123. 

244 “Clean Air Act Amendments of 1970,” Pub. L. 91-604, § 4, 84 

Stat. 1676, 1678 (Dec. 31, 1970). The “adverse effect” criterion 

was later amended to refer to pollutants “which may reasonably 

be anticipated to endanger public health or welfare”. See 42 

U.S.C. § 7408(a)(1)(A). Similar language is also used under the 

current CAA section 111. See 42 U.S.C. § 7411(b)(1)(A). 
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quality within their entire geographic area but would submit 

plans to the Administrator for “implementation, maintenance, and 

enforcement” of national ambient air quality standards. These 

plans would include “emission limitations, schedules, and 

timetables for compliance ... and such other measures as may be 

necessary to insure attainment and maintenance” of the national 

ambient air quality standards.245

The second prong—CAA section 111—addressed pollutants on a 

source category-wide basis. Under CAA section 111(b), the EPA 

lists source categories which “contribute significantly to air 

pollution which causes or contributes to the endangerment of 

public health or welfare,” And then establishes “standards of 

performance” for the new sources in the listed category.246 For 

existing sources in a listed source category, CAA section 111(d) 

set out procedures for the establishment of federally 

enforceable “emission standards” of any pollutant not otherwise 

controlled under the CAA’s SIP provisions or CAA section 112. 

Lastly, the third prong—CAA section 112—addressed hazardous 

air pollutants through the establishment of national “emission 

standards” at a level which “provides an ample margin of safety 

 

245 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1680. 246 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1684. 
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to protect the public health”.247 All new or modified sources of 

any hazardous air pollutant would be required to meet these 

emission standards. Existing sources were required to meet the 

same standards or would be shut down unless they obtained a 

temporary EPA waiver or Presidential exemption.248

At its inception, CAA section 111 was intended to bear a 

significant weight under this three-legged regime. Indeed, by 

1977, the EPA had promulgated six times as many performance 

standards under CAA section 111 than emission standards under 

CAA section 112.249 That said, states, including Texas and New 

Jersey, levied “substantial criticisms” against the EPA for not 

moving rapidly enough.250 Accordingly, the 1977 CAA Amendments 

were designed to “provide a greater role for the [s]tates in 

standards setting under the [CAA],” “protect [s]tates from 

‘environmental blackmail’ as they attempt to regulate mobile and 

competitive industries,” and lastly “provide a check on the 

Administrator’s inaction or failure to control emissions 

adequately.”251

 

247 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1685. 248 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1685. 249 H.R. Rep. No. 95-294, at 194 (May 12, 1977). 250 H.R. Rep. No. 95-294, at 194 (May 12, 1977). 251 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 
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At bottom, CAA section 111 rests on the definition of a 

standard of performance under CAA section 111(a)(1), which reads 

nearly the same now as it did when it was first adopted in the 

1970 CAA Amendments. In 1970, Congress defined standard of 

performance—a term which had not previously appeared in the CAA—

as 

a standard for emissions of air pollutants which reflects 

the degree of emission limitation achievable through the 

application of the best system of emission reduction which 

(taking into account the cost of achieving such reduction) 

the Administrator determines has been adequately 

demonstrated.252

Despite significant changes to this definition in 1977, Congress 

reversed course in 1990 and largely reinstated the original 

definition.253 As presently defined, the term applies to the 

regulation of new and existing sources under CAA sections 111(b) 

and (d).254 

The level of control reflected in the definition is 

generally referred to as the “best system of emission 

 

252 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1683. 253 “Clean Air Act Amendments of 1990,” Pub. L. 101-549, § 403, 

104 Stat. 2399, 2631 (Nov. 15, 1990) (retaining only the 

obligation to account for “any nonair quality health and 

environmental impact and energy requirements” that was added in 

1977). 

254 As CAA section 111(d) was originally adopted, state plans 

would have established “emission standards” instead of 

“standards of performance.” This distinction was later abandoned 

in 1977 and the same term is used in both CAA sections 111(b) 

and (d). 
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reduction,” or the BSER. The BSER, however, is not further 

defined, and only appeared after conference between the House 

and Senate in late 1970, and was neither discussed in the 

conference report nor openly debated in either chamber. 

Nevertheless, the originating bills from both houses shed light 

on its construction. 

The BSER grew out of proposed language in two bills, which, 

for the first time, targeted air pollution from stationary 

sources. The House bill sought to establish national emission 

standards to “prevent and control ... emissions [of nonhazardous pollutants] to the fullest extent compatible with the 

available technology and economic feasibility”.255 The House also 

proposed to prohibit the construction or operation of new 

sources of “extremely hazardous” pollutants.256 The Senate bill, 

on the other hand, authorized “Federal standards of 

performance,” which would “reflect the greatest degree of 

emission control which the Secretary [later, the Administrator] 

determines to be achievable through application of the latest 

available control technology, processes, operating methods, or 

 

255 H.R. 17255, 91st Cong. § 5 (1970). 256 H.R. 17255, 91st Cong. § 5 (1970). 
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other alternatives.”257 The Senate also would have authorized 

“national emission standards” for hazardous air pollution and 

other “selected air pollution agents.”258

After conference, CAA section 111 emerged as one of the 

CAA’s three programs for regulating stationary sources. In 

defining the newly formed “standards of performance,” Congress 

appeared to merge the various “means of preventing and 

controlling air pollution” under the Senate bill with the 

consideration of costs that was central to the House bill into 

the BSER. At the time, however, this definition only applied to 

new sources under CAA section 111(b). 

To regulate existing sources, Congress collapsed section 

114 of the Senate bill into CAA section 111(d).259 Section 114 of 

the Senate bill established emission standards for “selected air 

pollution agents,” and was intended to bridge the gap between 

criteria pollutants and hazardous air pollutants. As proposed, 

 

257 S. 4358, 91st Cong. § 6 (1970) (emphasis added). The breadth 

of the Senate bill is further emphasized in the conference 

report, which explains that a standard of performance “refers to 

the degree of emission control which can be achieved through 

process changes, operation changes, direct emission control, or 

other methods” and also includes “other means of preventing or 

controlling air pollution.” S. Rep. No. 91-1196, at 15-16 (Sept. 

17, 1970). 

258 S. 4358, 91st Cong. § 6 (1970). 259 The House bill did not provide for the direct regulation of 

existing sources. 
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the Senate identified fourteen substances for regulation under 

section 114 and only four substances for regulation under Senate 

bill 4358, section 115, the predecessor of CAA section 112.260 

As adopted, CAA section 111(d) requires states to submit 

plans to the Administrator establishing “emission standards” for 

certain existing sources of air pollutants that were not 

otherwise regulated as criteria pollutants or hazardous air 

pollutants. This ensured that there would be “no gaps in control 

activities pertaining to stationary source emissions that pose 

any significant danger to public health or welfare.”261 

The term “emission standards,” however, was not expressly 

defined in the 1970 CAA Amendments (save for purposes of citizen 

suit enforcement) even though the term was also used under the 

CAA’s SIP provisions and CAA section 112.262 That said, under the 

newly enacted “ambient air quality and emission standards” 

sections, Congress directed the EPA to provide states with 

information “on air pollution control techniques,” including 

data on “available technology and alternative methods of 

 

260 See S. Rep. No. 91-1196, at 18 and 20 (Sept. 17, 1970). 261 S. Rep. No. 91-1196, at 20 (Sept. 17, 1970) (discussing the 

relationship between sections 114 (addressing emission standards 

for “selected air pollution agents”) and 115 (addressing 

hazardous air pollutants) of the Senate bill). 

262 See “Clean Air Act Amendments of 1970,” § 12, 84 Stat. at 

1706. 
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prevention and control of air pollution” and on “alternative 

fuels, processes, and operating methods which will result in 

elimination or significant reduction of emissions.”263 Similarly, 

the Administrator would “issue information on pollution control 

techniques for air pollutants” in conjunction with establishing 

emission standards under CAA section 112. However, analogous 

text is absent from CAA section 111(d). 

After the enactment of the 1970 CAA Amendments, the EPA 

proposed standards of performance for an “initial list of five 

stationary source categories which contribute significantly to 

air pollution” in August 1971.264 The first category listed was 

for fossil-fuel fired steam generators, for which EPA proposed 

and promulgated standards for particulate matter, sulfur 

dioxide, and nitrogen oxides.265 

Several years later, the EPA proposed its implementing 

regulations for CAA section 111(d).266 These regulations were 

 

263 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1679. 264 “Standards of Performance for New Stationary Sources: 

Proposed Standards for Five Categories,” 36 F.R.FR 15704 (Aug. 

17, 1971). See “Clean Air Act Amendments of 1970,” § 4, 84 Stat. 

at 1684 (requiring the Administrator to publish a list of 

categories of stationary sources within 90 days of the enactment 

of the 1970 CAA Amendments). 

265 36 FR at 15704-706; and “Standards of Performance for New 

Stationary Sources,” 36 FR 24876, 24879 (Dec. 23, 1971). 

266 See “State Plans for the Control of Existing Facilities,” 39 

F.R.FR 36102 (Oct. 7, 1974). 
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finalized in November 1975, and provided for the publication of 

emission guidelines.267 The first emission guidelines were 

proposed in May 1976 and finalized in March 1977.268

Despite these first steps taken under CAA sections 111(b) 

and (d), Congress revisited the CAA in 1977 to address growing 

concerns with the nation’s response to the 1973 oil embargo 

(noted above), to respond to new environmental problems such as 

stratospheric ozone depletion, and to resolve other issues 

associated with implementing the 1970 CAA Amendments.269 Most 

 

267 See “State Plans for the Control of Certain Pollutants from 

Existing Facilities,” 40 F.R.FR 53340 (Nov. 17, 1975). 

268 See “Phosphate Fertilizer Plants; Draft Guideline Document; 

Availability,” 41 FR 19585 (May 12, 1976); and “Phosphate 

Fertilizer Plants; Final Guideline Document Availability,” 42 FR 

12022 (Mar. 1, 1977) 

269 For example, Congress recognized that many air pollutants had 

not been regulated despite “mounting evidence” that these 

pollutants “are associated with serious health hazards”. H.R. 

Rep. No. 94-1175, 22 (May, 15, 1976). Because EPA “failed to 

promulgate regulations to institute adequate control measures,” 

Congress ordered EPA to regulate four specific pollutants that 

had “been found to be cancer-causing or cancer-promoting”. Id.

at 23. This directive, reflected in CAA section 122, 

specifically added radioactive pollutants, cadmium, arsenic, and 

polycyclic organic matter “under the various provisions of the 

Clean Air Act and allows their regulation as criteria pollutants 

under ambient air quality standards, as hazardous air 

pollutants, or under new source performance standards, as 

appropriate.” H.R. Conf. Rep. No. 95-564, 142 (Aug. 3, 1977), 

1977 CAA Legis. Hist. at 522. At the same time, Congress made 

sure that these commands would have no effect on the 

Administrator’s discretion to address “any substance (whether or 

not enumerated [under CAA section 122(a))” under CAA sections 

108, 112, or 111. 42 U.S.C. § 7422(b). 
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notably, an increase in coal use as a result of the oil crisis 

meant that “vigorous and effective control” of air emissions was 

“even more urgent.”270 Thus, to curb the projected surge in air 

emissions, Congress enacted several new provisions to the CAA. 

These new provisions include the prevention of significant 

deterioration (PSD) program, visibility protections, and 

requirements for nonattainment areas.271 

Congress also made significant changes to CAA section 111. 

For example, Congress amended the definition of a standard of 

performance (including by requiring the consideration of “nonair 

quality health and environmental impact and energy 

requirements”), authorized alternative (e.g., work practice or 

design) standards in limited circumstances, provided states with 

authority to petition the Administrator for new or revised (and 

more stringent) standards, and imposed a strict regulatory 

schedule for establishing standards of performance for 

categories of major stationary sources that had not yet been 

listed.272

 

270 See Statement of EPA Administrator Costle, S. Hearings on S. 

272, S. 273, S. 977, and S. 1469 (Apr. 5, 7, May 25, June 24 and 

30, 1977), 1977 CAA Legis. Hist. at 3532. 

271 See “Clean Air Act Amendments of 1977,” Pub. L. 95-95, §§ 

127-129, 91 Stat. 685 (Aug. 7, 1977). 

272 “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 697. 
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The 1977 definition for a standard of performance required 

“all new sources to meet emission standards based on the 

reductions achievable through the use of the ‘best technological 

system of continuous emission reduction.’”273 For fossil-fuel 

fired stationary sources, Congress further required a percentage 

reduction in emissions from the use of fuels.274 Together, this 

was designed to “force new sources to burn high-sulfur fuel thus 

freeing low-sulfur fuel for use in existing sources where it is 

harder to control emissions and where low-sulfur fuel is needed 

for compliance.”275

Congress also clarified that with respect to CAA section 

111(d), standards of performance (now applicable in lieu of 

emission standards) “would be based on the best available means 

(not necessarily technological)”.276 This was intended to 

 

273 H.R. Rep. No. 95-294, at 192 (May 12, 1977). Congress 

separately defined “technological system of continuous emission 

reduction” as “(A) a technological process for production or 

operation by any source which is inherently low-polluting or 

nonpolluting, or (B) technological system for continuous 

reduction of the pollution generated by a source before such 

pollution is emitted into the ambient air, including 

precombustion cleaning or treatment of fuels.” “Clean Air Act 

Amendments of 1977,” § 109, 91 Stat. at 700; see also 42 U.S.C. 

§ 7411(a)(7). 

274 “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 700. 275 “New Stationary Sources Performance Standards; Electric 

Utility Steam Generating Units,” 44 F.R.FR 33580, 33581-82 (June 

11, 1979). 

276 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 
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distinguish existing source standards from new source standards, 

for which “the requirement for [the BSER] has been more narrowly 

redefined as best technological system of continuous emission 

reduction.”277 Additionally, Congress clarified that states could 

consider “the remaining useful life” of a source when applying a 

standard of performance to a particular existing source.278 

In the twenty years since the 1970 CAA Amendments and in 

spite of the refinements of the 1977 CAA Amendments, “many of 

the Nation’s most important air pollution problems [had] failed 

to improve or [had] grown more serious.”279 Indeed, in 1988, 

President George Bush said that “‘progress has not come quickly 

enough and much remains to be done.’”280 This time, with the 1990 

CAA Amendments, Congress substantially overhauled the CAA. In 

particular, Congress again added to the NAAQS program, 

completely revised CAA section 112, added a new title to target 

existing fossil fuel-fired stationary sources and address 

growing concerns with acid rain, imported an operating permit 

 

277 Sen. Muskie, S. Consideration of the H.R. Conf. Rep. No. 95-

564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353. 

278 This concept was already reflected in the EPA’s CAA section 

111(d) implementing regulations under 40 C.F.R. §CFR 60.24(f). 

See 40 F.R.FR 53340, 53347 (Nov. 17, 1975). 279 H.R. Rep. No. 101-490, at 144 (May 17, 1990). 280 H.R. Rep. No. 101-490, at 144 (May 17, 1990). 
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modeled off the Clean Water Act, and established a phase out of 

certain ozone depleting substances. 

All told, however, there was minimal debate on changes to 

CAA section 111. In fact, the only discussion centered on the 

repeal of the percentage reduction requirement, which became 

seen as unduly restrictive. Accordingly, Congress reverted the 

definition of “standard of performance” to the definition agreed 

to in the 1970 CAA Amendments, but retained the requirement to 

consider nonair quality environmental impacts and energy 

requirements added in 1977.281 However, the repeal would only 

apply so long as the SO2 cap under CAA section 403(e) of the 

newly established acid rain program remained in effect.282

Lastly, Congress instructed the EPA to revise its new source 

performance standards for SO2 emissions from fossil fuel-fired 

power plants but required that the revised emission rate be no 

less stringent than before.283

I. Statutory and Regulatory Requirements 

Clean Air Act section 111, which Congress enacted as part 

of the 1970 Clean Air Act Amendments, establishes mechanisms for 

 

281 Congress also updated the regulatory schedule that was added 

in the 1977 CAA Amendments to reflect the newly enacted 1990 CAA 

Amendments. See “Clean Air Act Amendments of 1990,” § 108, 104 

Stat. 2467. 

282 “Clean Air Act Amendments of 1990,” § 403, 104 Stat. at 2631. 283 “Clean Air Act Amendments of 1990,” § 301, 104 Stat. at 2631. 
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controlling emissions of air pollutants from stationary sources. 

This provision requires the EPA to promulgate a list of 

categories of stationary sources that the Administrator, in his 

or her judgment, finds “causes, or contributes significantly to, 

air pollution which may reasonably be anticipated to endanger 

public health or welfare.”284 The EPA has listed more than 60 

stationary source categories under this provision.285 Once the 

EPA lists a source category, the EPA must, under CAA section 

111(b)(1)(B), establish “standards of performance” for emissions 

of air pollutants from new sources in the source categories.286

These standards are known as new source performance standards 

(NSPS), and they are national requirements that apply directly 

to the sources subject to them. 

When the EPA establishes NSPS for new sources in a 

particular source category, the EPA is also required, under CAA 

section 111(d)(1), to prescribe regulations for states to submit 

plans regulating existing sources in that source category for 

any air pollutant that, in general, is not regulated under the 

CAA section 109 requirements for the NAAQS or regulated under 

the CAA section 112 requirements for hazardous air pollutants 

 

284 CAA §section 111(b)(1)(A). 285 See 40 CFR 60 subparts Cb – OOOO. 286 CAA §section 111(b)(1)(B), 111(a)(1). 
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(HAP).HAP. CAA section 111(d)’s mechanism for regulating 

existing sources differs from the one that CAA section 111(b) 

provides for new sources because CAA section 111(d) contemplates 

states submitting plans that establish “standards of 

performance” for the affected sources and that contain other 

measures to implement and enforce those standards. 

“Standards of performance” are defined under CAA section 

111(a)(1) as standards for emissions that reflect the emission 

limitation achievable from the “best system of emission 

reduction,” considering costs and other factors, that 

“the Administrator determines has been adequately demonstrated.” 

CAA section 111(d)(1) grants states the authority, in applying a 

standard of performance to a particular source, to take into 

account the source’s remaining useful life or other factors. 

Under CAA section 111(d), a state must submit its plan to the 

EPA for approval, and the EPA must approve the state plan if it 

is “satisfactory.”287 If a state does not submit a plan, or if 

the EPA does not approve a state’s plan, then the EPA must 

establish a plan for that state.288 Once a state receives the 

EPA’s approval of its plan, the provisions in the plan become 

federally enforceable against the entity responsible for 

 

287 CAA section 111(d)(2)(A). 288 CAA section 111(d)(2)(A). 
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noncompliance, in the same manner as the provisions of an 

approved SIP under the Act. 

Section 302(d) of the CAA defines the term “state” to 

include the Commonwealth of Puerto Rico, the Virgin Islands, 

Guam, American Samoa and the Commonwealth of the Northern 

Mariana Islands. While 40 CFR part 60 contains a separate 

definition of “state” at § 60.2, this definition expands on, 

rather than narrows, the definition in section 302(d) of the 

CAA. The introductory language to 40 CFR 60.2 provides: “The 

terms in this part are defined in the Act or in this section as 

follows.” Section 60.2 defines “State” as “all non-Federal 

authorities, including local agencies, interstate associations, 

and State-wide programs that have been delegated authority to 

implement: (1) the provisions of this part and/or (2) the permit 

program established under part 70 of this chapter. The term 

State shall have its conventional meaning where clear from the 

context.” The EPA believes that the last sentence refers to the 

conventional meaning of “state” under the CAA. Thus, the EPA 

believes the term “state” as used in the emission guidelines is 

most reasonably interpreted as including the meaning ascribed to 

that term in section 302(d) of the CAA, which expressly includes 

U.S. territories. 

Section 301(d)(A) of the CAA recognizes that the American 
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Indian tribes are sovereign Nations and authorizes the EPA to 

“treat tribes as States under this Act”. The Tribal Authority 

Rule (63 Federal Register 7254, February 12, 1998) identifies 

that EPA will treat tribes in a manner similar to states for all 

of the CAA provisions with the exception of, among other things, 

specific plan submittal and implementation deadlines under the 

CAA. As a result, though they operate as part of the 

interconnected system of electricity production and 

distribution, affected EGUs located in Indian country would not 

be encompassed within a state’s CAA section 111(d) plan. 

Instead, an Indian tribe with one or more affected EGUs located 

in its area of Indian country289 will have the opportunity, but 

not the obligation, to apply for eligibility to develop and 

implement a CAA section 111(d) plan. The Indian tribe would need 

to be approved by the EPA as eligible to develop and implement a 

CAA section 111(d) plan following the procedure set forth in 40 

CFR part 49. Once a tribe is approved as eligible for that 

purpose, it would be treated in the same manner as a state, and 

 

289 The EPA is aware of at least four affected sources located in 

Indian Country: two on Navajo lands – the Navajo Generating 

Station and the Four Corners Generating Station; one on Ute 

lands – the Bonanza Generating Station; and one on Fort Mojave 

lands, the South Point Energy Center. The affected EGUs at the 

first three plants are coal-fired EGUs. The fourth affected EGU 

is an NGCC facility.
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references in the emission guidelines to states would refer 

equally to the tribe. The EPA notes that, while tribes have the 

opportunity to apply for eligibility to administer CAA programs, 

they are not required to do so. Further, the EPA has established 

procedures in 40 CFR part 49 (see particularly 40 CFR 49.7(c)) 

that permit eligible tribes to request approval of reasonably 

severable partial program elements. Those procedures are 

applicable here. 

Although the EPA believes the current emission guidelines 

are sufficiently inclusive, the EPA is amending the 

applicability provision of the emission guidelines slightly to 

avoid any doubt that the guidelines apply to U.S. territories 

with affected EGUs and to any Indian tribe that has been 

approved by the EPA as eligible to develop and implement a plan. 

In these final emission guidelines, the term “state” 

encompasses the 50 states and the District of Columbia, U.S. 

territories, and any Indian tribe that has been approved by the 

EPA pursuant to 40 CFR 49.9 as to develop and implement a CAA 

section 111(d) plan. 
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The EPA issued regulations implementing CAA section 111(d) 

in 1975,290 and has revised them in the years since.291 (We refer 

to the regulations generally as the implementing regulations.) 

These regulations provide that, in promulgating requirements for 

sources under CAA section 111(d), the EPA first develops 

regulations known as “emission guidelines,” which establish 

binding requirements that states must address when they develop 

their plans.292 The implementing regulations also establish 

timetables for state and EPA action: states must submit state 

plans within 9 months of the EPA’s issuance of the guidelines,293

and the EPA must take final action on the state plans within 4 

months of the due date for those plans,294 although the EPA has 

authority to extend those deadlines.295 In this rulemaking, the 

EPA is following the requirements of the implementing 

 

290 “State Plans for the Control of Certain Pollutants from 

Existing Facilities,” 40 FR 53,34053340 (Nov. 17, 1975). 291 The most recent amendment was in 77 Fed. Reg.FR 9304 (Feb. 

16, 2012). 

292 40 CFR 60.22. In the 1975 rulemaking, the EPA explained that 

it used the term “emissionsemission guidelines” – instead of 

emissions limitations – to make clear that guidelines would not 

be binding requirements applicable to the sources, but instead 

are “criteria for judging the adequacy of State plans.” 40 Fed. 

Reg.FR at 53,34353343. 293 40 CFR 60.23(a)(1). 294 40 CFR 60.27(b). 295 See 40 CFR 60.27(a). 
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regulations, and is not re-opening them, except that the EPA is 

extending the timetables, as described below. 

Over the last forty years, under CAA section 111(d), the 

agency has regulated four pollutants from five source categories 

(i.e., sulfuric acid plants (acid mist), phosphate fertilizer 

plants (fluorides), primary aluminum plants (fluorides), Kraft 

pulp plants (total reduced sulfur), and municipal solid waste 

landfills (landfill gases)).296 In addition, the agency has 

regulated additional pollutants under CAA section 111(d) in 

conjunction with CAA section 129.297 The agency has not 

previously regulated CO2 or any other greenhouse gas under CAA 

section 111(d). 

The EPA’s previous CAA section 111(d) actions were 

necessarily geared toward the pollutants and industries 

 

296 See “Phosphate Fertilizer Plants; Final Guideline Document 

Availability,” 42 Fed. Reg. 12,022FR 12022 (Mar. 1, 1977); 

“Standards of Performance for New Stationary Sources; Emission 

Guideline for Sulfuric Acid Mist,” 42 Fed. Reg. 55,796FR 55796

(Oct. 18, 1977); “Kraft Pulp Mills, Notice of Availability of 

Final Guideline Document,” 44 Fed. Reg. 29,828FR 29828 (May 22, 

1979); “Primary Aluminum Plants; Availability of Final Guideline 

Document,” 45 Fed. Reg. 26,294FR 26294 (Apr. 17, 1980); 

“Standards of Performance for New Stationary Sources and 

Guidelines for Control of Existing Sources: Municipal Solid 

Waste Landfills, Final Rule,” 61 Fed. Reg.FR 9905 (Mar. 12, 

1996). 

297 See, e.g., “Standards of Performance for New Stationary 

Sources and Emission Guidelines for Existing Sources: Sewage 

Sludge Incineration Units, Final Rule,” 76 Fed. Reg. 15,372FR 

15372 (Mar. 21, 2011). 
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regulated. Similarly, in this rulemaking, in defining CAA 

section 111(d) emission guidelines for the states and 

determining the BSER, the EPA believes that taking into account 

the particular characteristics of carbon pollution, the 

interconnected nature of the power sector and the manner in 

which EGUs are currently operated is warranted. Specifically, 

the operators themselves treat increments of generation as 

interchangeable between and among sources in a way that creates 

options for relying on varying utilization levels, lowering 

carbon generation, and reducing demand as components of the 

overall method for reducing CO2 emissions. Doing so results in a 

broader, forward-thinking approach to the design of programs to 

yield critical CO2 reductions that improve the overall power 

system by lowering the carbon intensity of power generation, 

while offering continued reliability and cost-effectiveness. 

These opportunities exist in the utility power sector in ways 

that were not relevant or available for other industries for 

which the EPA has established CAA section 111(d) emission 

guidelines.298

 

298 See “Phosphate Fertilizer Plants; Final Guideline Document 

Availability,” 42 Fed. Reg. 12,022FR 12022 (Mar. 1, 1977); 

“Standards of Performance for New Stationary Sources; Emission 

Guideline for Sulfuric Acid Mist,” 42 Fed. Reg. 55,796FR 55796

(Oct. 18, 1977); “Kraft Pulp Mills, Notice of Availability of 
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In this action, the EPA is promulgating emission guidelines 

for states, U.S. territories, and tribes to follow in developing 

their CAA section 111(d) plans to reduce emissions of CO2 from 

the utility power sector. 

GJ. Legislative and Regulatory Background for CAA Section 111 

In the final days of December 1970, Congress enacted 

sweeping changes to the Air Quality Act of 1967 to confront an 

“environmental crisis.”299 The Air Quality Act—which expanded 

federal air pollution control efforts after the enactment of the 

Clean Air Act of 1963—prioritized the adoption of ambient air 

standards but failed to target stationary sources of air 

pollution. As a result, “[c]ities up and down the east coast 

were living under clouds of smoke and daily air pollution 

alerts.”300 In fact, “[o]ver 200 million tons of contaminants ...

 

Final Guideline Document,” 44 Fed. Reg. 29,828FR 29828 (May 22, 

1979); “Primary Aluminum Plants; Availability of Final Guideline 

Document,” 45 Fed. Reg. 26,294FR 26294 (Apr. 17, 1980); 

“Standards of Performance for New Stationary Sources and 

Guidelines for Control of Existing Sources: Municipal Solid 

Waste Landfills, Final Rule,” 61 Fed. Reg.FR 9905 (Mar. 12, 

1996). 

299 Sen. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA 

Legis. Hist. at 224. 

300 Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-1783 

(Dec. 18, 1970), 1970 CAA Legis. Hist. at 123. 
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spilled into the air” each year.301 The 1970 CAA Amendments were 

designed to face this crisis “with urgency and in candor.”302 

For the most part, Congress gave EPA and the states 

flexible tools to implement the CAA. This is best exhibited by 

the newly enacted programs regulating stationary sources. For 

these sources, Congress crafted a three-legged regime upon which 

the regulation of stationary sources was intended to sit. 

The first prong—CAA sections 107-110—addressed what are 

commonly referred to as criteria pollutants, “the presence of 

which in the ambient air results from numerous or diverse mobile 

or stationary sources” and are determined to have “an adverse 

effect on public health or welfare”.303 Under these provisions, 

states would have the primary responsibility for assuring air 

quality within their entire geographic area but would submit 

plans to the Administrator for “implementation, maintenance, and 

 

301 Sen. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA 

Legis. Hist. at 224. These pollutants fell into five main 

classes of pollutants: carbon monoxide, particulates, sulfur 

oxides, hydrocarbons, and nitrogen oxides. See Sen. Boggs, id. 

at 244. 

302 Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-1783 

(Dec. 18, 1970), 1970 CAA Legis. Hist. at 123. 

303 “Clean Air Act Amendments of 1970,” Pub. L. 91-604, § 4, 84 

Stat. 1676, 1678 (Dec. 31, 1970). The “adverse effect” criterion 

was later amended to refer to pollutants “which may reasonably 

be anticipated to endanger public health or welfare”. See 42 

U.S.C. § 7408(a)(1)(A). Similar language is also used under the 

current CAA section 111. See 42 U.S.C. § 7411(b)(1)(A). 
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enforcement” of national ambient air quality standards. These 

plans would include “emission limitations, schedules, and 

timetables for compliance ... and such other measures as may be 

necessary to insure attainment and maintenance” of the national 

ambient air quality standards.304

The second prong—CAA section 111—addressed pollutants on a 

source category-wide basis. For new sources in a listed source 

category, CAA section 111(b) established “standards of 

performance” for pollutants which “cause[] or contribute to the 

endangerment of public health or welfare.”305 For existing 

sources in a listed source category, CAA section 111(d) set out 

procedures for the establishment of federally enforceable 

“emission standards” of any pollutant not otherwise controlled 

under the CAA’s SIP provisions or CAA section 112. 

Lastly, the third prong—CAA section 112—addressed hazardous 

air pollutants through the establishment of national “emission 

standards” at a level which “provides an ample margin of safety 

to protect the public health”.306 All new or modified sources of 

any hazardous air pollutant would be required to meet these 

emission standards. Existing sources were required to meet the 

 

304 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1680. 305 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1684. 306 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1685. 
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same standards or would be shut down unless they obtained a 

temporary EPA waiver or Presidential exemption.307

At its inception, CAA section 111 was intended to bear a 

significant weight under this three-legged regime. Indeed, by 

1977, the EPA had promulgated six times as many performance 

standards under CAA section 111 than emission standards under 

CAA section 112.308 That said, states, including Texas and New 

Jersey, levied “substantial criticisms” against the EPA for not 

moving rapidly enough.309 Accordingly, the 1977 CAA Amendments 

were designed to “provide a greater role for the [s]tates in 

standards setting under the [CAA],” “protect [s]tates from 

‘environmental blackmail’ as they attempt to regulate mobile and 

competitive industries,” and lastly “provide a check on the 

Administrator’s inaction or failure to control emissions 

adequately.”310

At bottom, CAA section 111 rests on the definition of a 

standard of performance under CAA section 111(a)(1), which reads 

nearly the same now as it did when it was first adopted in the 

1970 CAA Amendments. In 1970, Congress defined standard of 

 

307 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1685. 308 H.R. Rep. No. 95-294, at 194 (May 12, 1977). 309 H.R. Rep. No. 95-294, at 194 (May 12, 1977). 310 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 
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performance—a term which had not previously appeared in the CAA—

as 

a standard for emissions of air pollutants which reflects 

the degree of emission limitation achievable through the 

application of the best system of emission reduction which 

(taking into account the cost of achieving such reduction) 

the Administrator determines has been adequately 

demonstrated.311

Despite significant changes to this definition in 1977, Congress 

reversed course in 1990 and largely reinstated the original 

definition.312 As presently defined, the term applies to the 

regulation of new and existing sources under CAA sections 111(b) 

and (d).313 

The level of control reflected in the definition is 

generally referred to as the “best system of emission 

reduction,” or the BSER. The BSER, however, is not further 

defined, and only appeared after conference between the House 

and Senate in late 1970, and was neither discussed in the 

conference report nor openly debated in either chamber. 

 

311 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1683. 312 “Clean Air Act Amendments of 1990,” Pub. L. 101-549, § 403, 

104 Stat. 2399, 2631 (Nov. 15, 1990) (retaining only the 

obligation to account for “any nonair quality health and 

environmental impact and energy requirements” that was added in 

1977). 

313 As CAA section 111(d) was originally adopted, state plans 

would have established “emission standards” instead of 

“standards of performance.” This distinction was later abandoned 

in 1977 and the same term is used in both CAA sections 111(b) 

and (d). 
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Nevertheless, the originating bills from both houses shed light 

on its construction. 

The BSER grew out of proposed language in two bills, which, 

for the first time, targeted air pollution from stationary 

sources. The House bill sought to establish national emission 

standards to “prevent and control ... emissions [of non-hazardous 

pollutants] to the fullest extent compatible with the available 

technology and economic feasibility”.314 The House also proposed 

to prohibit the construction or operation of new sources of 

“extremely hazardous” pollutants.315 The Senate bill, on the 

other hand, authorized “Federal standards of performance,” which 

would “reflect the greatest degree of emission control which the 

Secretary [later, the Administrator] determines to be achievable 

through application of the latest available control technology, 

processes, operating methods, or other alternatives.”316 The 

Senate also would have authorized “national emission standards” 

 

314 H.R. 17255, 91st Cong. § 5 (1970). 315 H.R. 17255, 91st Cong. § 5 (1970). 316 S. 4358, 91st Cong. § 6 (1970) (emphasis added). The breadth 

of the Senate bill is further emphasized in the conference 

report, which explains that a standard of performance “refers to 

the degree of emission control which can be achieved through 

process changes, operation changes, direct emission control, or 

other methods” and also includes “other means of preventing or 

controlling air pollution.” S. Rep. No. 91-1196, at 15-16 (Sept. 

17, 1970). 
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for hazardous air pollution and other “selected air pollution 

agents.”317

After conference, CAA section 111 emerged as one of the 

CAA’s three programs for regulating stationary sources. In 

defining the newly formed “standards of performance,” Congress 

merged the various “means of preventing and controlling air 

pollution” under the Senate bill with the consideration of costs 

that was central to the House bill into the BSER. At the time, 

however, this definition only applied to new sources under CAA 

section 111(b). 

To regulate existing sources, Congress collapsed section 

114 of the Senate bill into CAA section 111(d).318 Section 114 of 

the Senate bill established emission standards for “selected air 

pollution agents,” and was intended to bridge the gap between 

criteria pollutants and hazardous air pollutants. As proposed, 

the Senate identified fourteen substances for regulation under 

section 114 and only four substances for regulation under Senate 

bill 4358, section 115, the predecessor of CAA section 112.319 

As adopted, CAA section 111(d) requires states to submit 

plans to the Administrator establishing “emission standards” for 

 

317 S. 4358, 91st Cong. § 6 (1970). 318 The House bill did not provide for the direct regulation of 

existing sources. 

319 See S. Rep. No. 91-1196, at 18 and 20 (Sept. 17, 1970). 
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certain existing sources of air pollutants that were not 

otherwise regulated as criteria pollutants or hazardous air 

pollutants. This ensured that there would be “no gaps in control 

activities pertaining to stationary source emissions that pose 

any significant danger to public health or welfare.”320 

The term “emission standards,” however, was not expressly 

defined in the 1970 CAA Amendments (save for purposes of citizen 

suit enforcement) even though the term was also used under the 

CAA’s SIP provisions and CAA section 112.321 That said, under the 

newly enacted “ambient air quality and emission standards” 

sections, Congress directed the EPA to provide states with 

information “on air pollution control techniques,” including 

data on “available technology and alternative methods of 

prevention and control of air pollution” and on “alternative 

fuels, processes, and operating methods which will result in 

elimination or significant reduction of emissions.”322 Similarly, 

the Administrator would “issue information on pollution control 

techniques for air pollutants” in conjunction with establishing 

 

320 S. Rep. No. 91-1196, at 20 (Sept. 17, 1970) (discussing the 

relationship between sections 114 (addressing emission standards 

for “selected air pollution agents”) and 115 (addressing 

hazardous air pollutants) of the Senate bill). 

321 See “Clean Air Act Amendments of 1970,” § 12, 84 Stat. at 

1706. 

322 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1679. 
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emission standards under CAA section 112. However, analogous 

text is absent from CAA section 111(d). 

After the enactment of the 1970 CAA Amendments, the EPA 

proposed standards of performance for an “initial list of five 

stationary source categories which contribute significantly to 

air pollution” in August 1971.323 The first category listed was 

for fossil-fuel fired steam generators, for which EPA proposed 

and finalized standards for particulate matter, sulfur dioxide, 

and nitrogen oxides.324 

Several years later, the EPA proposed its implementing 

regulations for CAA section 111(d).325 These regulations were 

finalized in November 1975, and provided for the publication of 

emission guidelines.326 The first emissions guidelines were 

proposed in May 1976 and finalized in March 1977.327

 

323 “Standards of Performance for New Stationary Sources: 

Proposed Standards for Five Categories,” 36 FR 15704 (Aug. 17, 

1971). See “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 

1684 (requiring the Administrator to publish a list of 

categories of stationary sources within 90 days of the enactment 

of the 1970 CAA Amendments). 

324 36 F.R. at 15704-706; and “Standards of Performance for New 

Stationary Sources,” 36 F.R. 24876, 24879 (Dec. 23, 1971). 

325 See “State Plans for the Control of Existing Facilities,” 39 

FR 36102 (Oct. 7, 1974). 

326 See “State Plans for the Control of Certain Pollutants from 

Existing Facilities,” 40 FR 53340 (Nov. 17, 1975). 

327 See “Phosphate Fertilizer Plants; Draft Guideline Document; 

Availability,” 41 F.R. 19585(May 12, 1976); and “Phosphate 
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Despite these first steps taken under CAA sections 111(b) 

and (d), Congress revisited the CAA in 1977 to address growing 

concerns with the nation’s response to the 1973 oil embargo 

(noted above), to respond to new environmental problems such as 

stratospheric ozone depletion, and to resolve other issues 

associated with implementing the 1970 CAA Amendments.328 Most 

notably, an increase in coal use as a result of the oil crisis 

meant that “vigorous and effective control” of air emissions was 

“even more urgent.”329 Thus, to curb the projected surge in air 

 

Fertilizer Plants; Final Guideline Document Availability,” 42 

F.R. 12022 (Mar. 1, 1977) 

328 For example, Congress recognized that many air pollutants had 

not been regulated despite “mounting evidence” that these 

pollutants “are associated with serious health hazards”. H.R. 

Rep. No. 94-1175, 22 (May, 15, 1976). Because EPA “failed to 

promulgate regulations to institute adequate control measures,” 

Congress ordered EPA to regulate four specific pollutants that 

had “been found to be cancer-causing or cancer-promoting”. Id.

at 23. This directive, reflected in CAA section 122, 

specifically added radioactive pollutants, cadmium, arsenic, and 

polycyclic organic matter “under the various provisions of the 

Clean Air Act and allows their regulation as criteria pollutants 

under ambient air quality standards, as hazardous air 

pollutants, or under new source performance standards, as 

appropriate.” H.R. Conf. Rep. No. 95-564, 142 (Aug. 3, 1977), 

1977 CAA Legis. Hist. at 522. At the same time, Congress made 

sure that these commands would have no effect on the 

Administrator’s discretion to address “any substance (whether or 

not enumerated [under CAA section 122(a))” under CAA sections 

108, 112, or 111. 42 U.S.C. § 7422(b). 

329 See Statement of EPA Administrator Costle, S. Hearings on S. 

272, S. 273, S. 977, and S. 1469 (Apr. 5, 7, May 25, June 24 and 

30, 1977), 1977 CAA Legis. Hist. at 3532. 
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emissions, Congress enacted several new provisions to the CAA. 

These new provisions include the prevention of significant 

deterioration (PSD) program, visibility protections, and 

requirements for nonattainment areas.330 

Congress also made significant changes to CAA section 111. 

For example, Congress amended the definition of a standard of 

performance (including by requiring the consideration of “nonair 

quality health and environmental impact and energy 

requirements”), authorized alternative (e.g., work practice or 

design) standards in limited circumstances, provided states with 

authority to petition the Administrator for new or revised (and 

more stringent) standards, and imposed a strict regulatory 

schedule for establishing standards of performance for 

categories of major stationary sources that had not yet been 

listed.331

The 1977 definition for a standard of performance required 

“all new sources to meet emission standards based on the 

reductions achievable through the use of the ‘best technological 

system of continuous emission reduction.’”332 For fossil-fuel 

 

330 See “Clean Air Act Amendments of 1977,” Pub. L. 95-95, §§ 

127-129, 91 Stat. 685 (Aug. 7, 1977). 

331 “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 697. 332 H.R. Rep. No. 95-294, at 192 (May 12, 1977). Congress 

separately defined “technological system of continuous emission 
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fired stationary sources, Congress further required a percentage 

reduction in emissions from the use of fuels.333 Together, this 

was designed to “force new sources to burn high-sulfur fuel thus 

freeing low-sulfur fuel for use in existing sources where it is 

harder to control emissions and where low-sulfur fuel is needed 

for compliance.”334

Congress also clarified that with respect to CAA section 

111(d), standards of performance (now applicable in lieu of 

emission standards) “would be based on the best available means 

(not necessarily technological)”.335 This was intended to 

distinguish existing source standards from new source standards, 

for which “the requirement for [the BSER] has been more narrowly 

redefined as best technological system of continuous emission 

reduction.”336 Additionally, Congress clarified that states could 

 

reduction” as “(A) a technological process for production or 

operation by any source which is inherently low-polluting or 

nonpolluting, or (B) technological system for continuous 

reduction of the pollution generated by a source before such 

pollution is emitted into the ambient air, including 

precombustion cleaning or treatment of fuels.” “Clean Air Act 

Amendments of 1977,” § 109, 91 Stat. at 700; see also 42 U.S.C. 

§ 7411(a)(7). 

333 “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 700. 334 “New Stationary Sources Performance Standards; Electric 

Utility Steam Generating Units,” 44 FR 33580, 33581-82 (June 11, 

1979). 

335 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 336 Sen. Muskie, S. Consideration of the H.R. Conf. Rep. No. 95-

564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353. 
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consider “the remaining useful life” of a source when applying a 

standard of performance to a particular existing source.337 

In the twenty years since the 1970 CAA Amendments and in 

spite of the refinements of the 1977 CAA Amendments, “many of 

the Nation’s most important air pollution problems [had] failed 

to improve or [had] grown more serious.”338 Indeed, in 1988, 

President George Bush said that “‘progress has not come quickly 

enough and much remains to be done.’”339 This time, with the 1990 

CAA Amendments, Congress substantially overhauled the CAA. In 

particular, Congress again added to the NAAQS program, 

completely revised CAA section 112, added a new title to target 

existing fossil fuel-fired stationary sources and address 

growing concerns with acid rain, imported an operating permit 

modeled off the Clean Water Act, and established a phase out of 

certain ozone depleting substances. 

All told, however, there was minimal debate on changes to 

CAA section 111. In fact, the only discussion centered on the 

repeal of the percentage reduction requirement, which became 

seen as unduly restrictive. Accordingly, Congress reverted the 

 

337 This concept was already reflected in the EPA’s CAA section 

111(d) implementing regulations under 40 CFR 60.24(f). See 40 FR 

53340, 53347 (Nov. 17, 1975). 

338 H.R. Rep. No. 101-490, at 144 (May 17, 1990). 339 H.R. Rep. No. 101-490, at 144 (May 17, 1990). 
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definition of “standard of performance” to the definition agreed 

to in the 1970 CAA Amendments, but retained the requirement to 

consider nonair quality environmental impacts and energy 

requirements added in 1977.340 However, the repeal would only 

apply so long as the SO2 cap under CAA section 403(e) of the 

newly established acid rain program remained in effect.341

Lastly, Congress instructed the EPA to revise its new source 

performance standards for SO2 emissions from fossil fuel-fired 

power plants but required that the revised emission rate be no 

less stringent than before.342

H. Clean Power Plan Proposal and Supplemental Proposal 

On June 18, 2014, the EPA proposed emission guidelines for 

states to follow in developing plans to address greenhouse gas 

(GHG) emissions from existing fossil fuel-fired electric 

generating units (EGUs). Specifically, the EPA proposed ratebased goals for carbon dioxide (CO2) emissions for each state 

with existing fossil fuel-fired EGUs, as well as guidelines for 

plans to achieve those goals. On November 4, 2014, the EPA 

published a supplemental proposal that proposed emission rate-

 

340 Congress also updated the regulatory schedule that was added 

in the 1977 CAA Amendments to reflect the newly enacted 1990 CAA 

Amendments. See “Clean Air Act Amendments of 1990,” § 108, 104 

Stat. 2467. 

341 “Clean Air Act Amendments of 1990,” § 403, 104 Stat. at 2631. 342 “Clean Air Act Amendments of 1990,” § 301, 104 Stat. at 2631. 
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based goals for CO2 emissions for U.S. territories and areas of 

Indian country with existing fossil fuel-fired EGUs. In the 

supplemental proposal, the EPA also solicited comment on 

authorizing jurisdictions (including any states, territories and 

areas of Indian country) without existing fossil fuel-fired EGUs 

subject to the proposed emission guidelines to partner with 

jurisdictions (including any states) that do have existing 

fossil fuel-fired EGUs subject to the proposed emission 

guidelines in developing multi-jurisdictional plans. The EPA 

also solicited comment on the treatment of renewable energy, 

demand-side energy efficiency and other new low- or nonzeroemitting electricity generation across international boundaries 

in a state plan. 

The EPA also issued two notices after the June 18, 2014 

proposal. On October 30, 2014, the EPA published a notice of 

data availability (NODA) in which the agency provided additional 

information on several topics raised by stakeholders and 

solicited comment on the information presented. The notice 

covered three topic areas: 1) the emission reduction compliance 

trajectories created by the interim goal for 2020 to 2029, 2) 

certain aspects of the building block methodology, and 3) the 

way state-specific CO2 goals are calculated. 
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In a separate action, the EPA published a notice regarding 

potential methods for determining the mass that is equivalent to 

an emission rate-based CO2 goal (79 FR 67406; November 13, 2014). 

With the notice, the EPA also made available, in the docket for 

this rulemaking, a technical support document (TSD) that 

provided two examples of how a state, U.S. territory or tribe 

could translate a rate-based CO2 goal to total metric tons of CO2

(a mass-based equivalent). 

JK. Stakeholder Outreach and Consultations 

Following the direction in the Presidential Memorandum to 

the Administrator (June 25, 2013),343 the EPA engaged in 

extensive and vigorous outreach to stakeholders and the general 

public at every stage of development of this rule. Our outreach 

has included direct engagement with the energy and environment 

officials in states, tribes, and a full range of stakeholders 

including leaders in the utility power sector, labor leaders, 

non-governmental organizations, other federal agencies, other 

experts, community groups and members of the public. The EPA 

participated in more than 300 meetings before the rule was 

proposed and more than 300 after the proposal. 

 

343 Presidential Memorandum – Power Sector Carbon Pollution 

Standards, June 25, 2013. http://www.whitehouse.gov/the-pressoffice/2013/06/25/presidential-memorandum-power-sector-carbonpollution-standards. 
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Throughout the rulemaking process, the agency has 

encouraged, organized, and participated in hundreds of meetings 

about CAA section 111(d) and reducing carbon pollution from 

existing power plants. The agency’s outreach prior to proposal, 

as well as during the public comment period, was designed to 

solicit policy ideas,344 concerns, and technical information. The 

agency received 4.3 million comments about all aspects of the 

proposed rule and thousands of people participated in the 

agency’s public hearings, webinars, listening sessions,345

teleconferences and meetings held all across the country. 

Our engagement has brought together a variety of states and 

stakeholders to discuss a wide range of issues related to the 

utility power sector and the development of emission guidelines 

under CAA section 111(d). The meetings were attended by the EPA 

Regional Administrators, other senior managers and staff who 

have been instrumental in the development of the rule and will 

play key roles in developing and implementing it. 

 

344 The EPA received more than 2,000 emails offering input into 

the development of these guidelines through email and a webbased form. These emails and other materials provided to the EPA 

are posted on line as part of a non-regulatory docket, EPA 

Docket ID No. EPA-HQ-OAR-2014-0020, at www.regulations.gov. 

345 Summaries of the 11 public listening sessions in 2013 are 

available at www.regulations.gov at EPA Docket ID No. EPA-HQOAR-2014-0020. 
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This outreach process has produced a wealth of information 

which has informed this rule significantly. The pre-proposal 

outreach efforts far exceeded what is required of the agency in 

the normal course of a rulemaking process, and the EPA expects 

that the dialogue with states and stakeholders will continue 

after the rule is finalized. The EPA recognizes the importance 

of working with all stakeholders, and in particular with the 

states, to ensure a clear and common understanding of the role 

the states will play in addressing carbon pollution from power 

plants. We firmly believe that our outreach has resulted in a 

more workable rule that will achieve the statutory goals and has 

enhanced the likelihood of timely and successful achievement of 

the carbon reduction goals, given the critical importance and 

urgency of the concrete action. 

The EPA has given stakeholder comments careful 

consideration and, as a result, this final rule includes 

features that are responsive to many stakeholder concerns. 

1. Public hearings 

More than 2,700 people attended the public hearings 

sessions held in Atlanta, Denver, Pittsburgh, and Washington, 

DC. More than 1,300 people spoke at the public hearings. 

Additionally, about 100 people attended the public hearing held 

in Phoenix, Arizona, on the November 4, 2014 supplemental 
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proposal. Speakers at the public hearings included Members of 

Congress, other public officials, industry representatives, 

faith-based organizations, unions, environmental groups, 

community groups, students, public health groups, energy groups, 

academia and concerned citizens. 

Participants shared a range of perspectives. Many were 

concerned with the impacts of climate change on their health and 

on future generations, others were worried about the impact of 

regulations on the economy. Their support for the agency’s 

efforts varied. 

2. State officials 

Since fall 2013, the agency has provided multiple 

opportunities for the states to inform this rulemaking. 

Administrator McCarthy has engaged with governors from states 

with a variety of interests in the rulemaking. Other senior 

agency officials have engaged with every branch and major agency 

of state government - including state legislators, attorneys 

general, state energy, environment, and utility officials, and 

governors' staff. 

On several occasions, state environmental commissioners met 

with senior agency officials to provide comments on the Clean 

Power Plan. The EPA organized, encouraged and attended meetings 

with states to discuss multi-state planning efforts. States have 
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come together with several collaborative groups to discuss ways 

to work together to make the Clean Power Plan more affordable. 

The EPA has participated in and supported the states in these 

discussions. Because of the interconnectedness of the power 

sector, and the fact that electricity generated at power plants 

crosses state lines; states, utilities and ratepayers may 

benefit from states working together to implement the 

requirements of this rulemaking. The meetings provided state 

leaders, including governors, environmental commissioners, 

energy officers, public utility commissioners, and air 

directors, opportunities to engage with the EPA officials. In 

addition, the states submitted public comments from several 

agencies within each state. The wealth of comments and input 

from states was important in developing the final rulemaking. 

Agency officials listened to ideas, concerns and details 

from states, including from states with a wide range of 

experience in reducing carbon pollution from power plants. The 

EPA reached out to all 50 states to engage with both 

environmental and energy departments at all levels of 

government. As an example, a three-part webinar series in 

June/July 2014 for the states and tribes offered an interactive 

format for technical staff at the EPA and in the states/tribes 

to exchange ideas and ask clarifying question. The webinars were 
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then posted online so other stakeholders could view them. A few 

weeks after the postings, the EPA organized follow-up conference 

calls with stakeholder groups. Also, the EPA hosted scores of 

technical meetings between states and the EPA in the weeks and 

months after the rule was proposed. 

Additionally, the EPA organized “hub” calls; these 

teleconferences brought all of the states in a given EPA region 

together to discuss technical and interstate aspects of the 

proposal. These exchanges helped provide the stakeholders with 

the information they needed to comment on the proposal 

effectively. The EPA also held a series of webinars with state 

environmental associations and their members on a series of 

technical issues. 

The agency has collected policy papers and comment letters 

from states with overarching energy goals and technical details 

on the states’ utility power sector. EPA leadership and staff 

also participated in webinars and meetings with state and tribal 

officials hosted by collaborative groups and trade associations. 

After the comment period closed, and based on our meetings over 

the last year, as well as written comments on the proposal and 

NODA, the EPA analyzed information about data errors that needed 

to be addressed for the final rule. In February and March 2015, 

we reached out to particular states to clarify ambiguous or 
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unclear information that was submitted to the EPA related to 

NEEDS and eGRID data. The EPA contacted particular states to 

clarify the technical comments or concerns to ensure that any 

changes we make are accurate and appropriate. 

To help prepare for implementation of the Clean Power 

Planthis rule, the agency initiated several outreach activities 

to assist with state planning efforts. The agency participated 

in meetings organized by the National Association of State 

Energy Officials (NASEO), the National Association of Regulatory 

Utility Commissioners (NARUC), and the National Association of 

Clean Air Agencies (NACAA) (the “3N” groups). Meeting 

participants discussed issues related to energy efficiency and 

renewable energy. 

To help state officials prepare for the planning process 

that will take place in the states, the EPA presented a webinar 

on February 24, 2015. This webinar provided an update on 

training plans and further connection with states in the 

implementation process. Forty-nine states, the District of 

Columbia, and 14 tribes were represented at this webinar. The 

EPA is developing a state plan electronic collection system to 

receive, track, and store state submittals of plans and reports. 

The EPA plans to use an integrated project team to solicit 

stakeholder input on the system during development. The team 
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membership, including state representatives, will bring together 

the business and technology skills required to construct a 

successful product and promote transparency in the EPA’s 

implementation of the rule. 

To help identify training needs for the final Clean Power 

Plan, the agency reached out to a number of state and local 

organizations such as the Central State Air Resources Agencies 

and other such regional air agencies. The EPA’s outreach on 

training has included sharing the plans with the states and 

incorporating changes to the training topics based on the 

states’ needs. The EPA training plan includes a wide variety of 

topics such as basic training on the electric power sector as 

well as specific pollution control strategies to reduce carbon 

emissions from power plants. In particular, the states requested 

training on how to use programs such as combined heat and power, 

energy efficiency and renewable energy to reduce carbon 

emissions. The EPA will continue to work with states to tailor 

training activities to their needs. 

The agency has engaged, and will continue to engage with 

states, territories, Washington, D.C., and tribes after the 

rulemaking process and throughout implementation. 

3. Tribal officials 
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 The EPA conducted significant outreach to and consultation 

with tribes. Tribes are not required to, but may, develop or 

adopt Clean Air Act programs. The EPA is aware of four 

facilities with affected EGUs located in Indian country: the 

South Point Energy Center, in Fort Mojave Indian country, 

geographically located within Arizona; the Navajo Generating 

Station, in Navajo Indian country, geographically located within 

Arizona; the Four Corners Power Plant, in Navajo Indian country, 

geographically located within New Mexico; and the Bonanza Power 

Plant, in Ute Indian country, geographically located within 

Utah. The EPA offered consultation to the leaders of the tribes 

on whose lands these facilities are located as well as all of 

the federally recognized tribes to ensure that they had the 

opportunity to have meaningful and timely input into this rule. 

Section III (“Stakeholder Outreach and Conclusions”) of the June 

18, 2014 proposal documents the EPA’s extensive outreach efforts 

to tribal officials prior to that proposal, including an 

informational webinar, outreach meeting, teleconferences with 

tribal officials and the National Tribal Air Association (NTAA), 

and letters offering consultation. Additional outreach to tribal 

officials conducted by the EPA prior to the November 4, 2014 

supplemental proposal is discussed in Section II.D (“Additional 

Outreach and Consultation”) of the supplemental proposal. The 
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additional outreach for the supplemental proposal included 

consultations with all three tribes that have affected EGUs on 

their lands, as well as several other tribes that requested 

consultation, and also additional teleconferences with the NTAA. 

After issuing the supplemental proposal, the EPA offered an 

additional consultation to the leaders of all federally 

recognized tribes. The EPA held an informational meeting open to 

all tribes and also held consultations with the Navajo Nation, 

Fort McDowell Yavapai Nation, Fort Mojave Tribe, Ak-Chin Indian 

Community, and Hope Tribe on November 18, 2014. The EPA held a 

consultation with the Ute Tribe of the Uintah and Ouray 

Reservation on December 16, 2014, and a consultation with the 

Gila River Indian Community on January 15, 2015. The EPA held a 

public hearing on the supplemental proposal on November 19, 

2014, in Phoenix, Arizona. On April 28, 2015, the EPA held an 

additional consultation with the Navajo Nation. 

 Tribes were interested in the impact of this rule on other 

ongoing regulatory actions at the affected EGUs, such as 

permitting or requirements for the best available retrofit 

technology (BART). Tribes also noted that it was important to 

allow renewable energy projects on tribal lands to contribute 

toward meeting state goals. Some tribes indicated an interest in 

being involved in the development of implementation plans for 
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areas of Indian country. Additional detail regarding the EPA’s 

outreach to tribes and comments and recommendations from tribes 

can be found in Section X.F of this preamble. 

4. U.S. territories 

The EPA has met with individual U.S. territories and 

affected EGUs in U.S. territories during the rulemaking process. 

On July 22, 2014, the EPA met with representatives from the 

Puerto Rico Environmental Quality Board, the Puerto Rico 

Electric Power Authority, the Governor’s Office, and the Office 

of Energy, Puerto Rico. On September 8, 2014, the EPA held a 

meeting with representatives from the Guam Environmental 

Protection Agency (GEPA) and the Guam Power Authority and, on 

February 18, 2015, the EPA met again with representatives from 

GEPA. 

5. Industry representatives 

Agency officials have engaged with industry leaders and 

representatives from trade associations in many one-on-one and 

national meetings. Many meetings occurred at the EPA 

headquarters and in the EPA’s Regional Offices and some were 

sponsored by stakeholder groups. Because the focus of the rule 

is on the utility power sector, many of the meetings with 

industry have been with utilities and industry representatives 

directly related to the utility power sector. The agency has 
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also met with energy industries such as coal and natural gas 

interests, as well as companies that offer new technology to 

prevent or reduce carbon pollution, including companies that 

have expertise in renewable energy and energy efficiency. Other 

meetings have been held with representatives of energy intensive 

industries, such as the iron and steel and aluminum industries, 

to help understand the issues related to large industrial users 

of electricity. 

6. Electric utility representatives 

Agency officials participated in many meetings with 

utilities and their associations to discuss all aspects of the 

proposed guidelines. We have met with all types of companies 

that produce electricity, including private utilities or 

investor owned utilities. Public utilities and cooperative 

utilities were also part of in-depth conversations about CAA 

section 111(d) with EPA officials. 

The conversations included meetings with the EPA 

headquarters and regional offices. State officials were included 

in many of the meetings. Meetings with utility associations and 

groups of utilities were held with key EPA officials. The 

meetings covered technical, policy and legal topics of interest 

and utilities expressed a wide variety of support and concerns 

about CAA section 111(d). 
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7. Electricity grid operators 

The EPA had a number of conversations with the Independent 

System Operators and Regional Transmission Organizations (ISOs 

and RTOs) to discuss the rule and issues related to grid 

operations and reliability. EPA staff met with the ISO/RTO 

Council on several occasions to collect their ideas. The EPA 

regional offices also met with the ISOs and RTOs in their 

regions. System operators have offered suggestions in using 

regional approaches to implement CAA section 111(d) while 

maintaining reliable, affordable electricity. 

8. Representatives from community and non-governmental 

organizations 

Agency officials engaged with community groups representing 

low-incomevulnerable communities, and faith-based groups, among 

others, during the outreach effort. In response to a request 

from communities, the EPA held a day-long training on the Clean 

Power Plan on October 30, 2014, in Washington D.C. At this 

meeting, the EPA met with a number of environmental groups to 

provide information on how the agency plans on reducing carbon 

pollution from existing power plants using CAA section 111(d). 

Many environmental organizations discussed the need for 

reducing carbon pollution. Meetings were technical, policy and 

legal in nature and many groups discussed specific state 
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policies that are already in place to reduce carbon pollution in 

the states. 

 A number of organizations representing religious groups 

have reached out to the EPA on several occasions to discuss 

their concerns and ideas regarding this rule. Many members of 

faith communities attended the four public hearings. 

 Public health groups discussed the need for protection of 

children’s health from harmful air pollution. Doctors and health 

care providers discussed the link between reducing carbon 

pollution and air pollution and public health. Consumer groups 

representing advocates for low income electricity customers 

discussed the need for affordable electricity. They talked about 

reducing electricity prices for consumers through energy 

efficiency and low-cost carbon reductions. 

 In winter/spring 2015, EPA continued to offer webinars and 

teleconferences for community groups on the rulemaking. 

9. Environmental Justice Organizations 

Agency officials engaged with environmental justice groups 

representing communities of color, low-income communities and 

others during the outreach effort. Agency officials also engaged 

with the EPA’s National Environmental Justice Advisory Council 

(NEJAC) members in September 2013. The NEJAC is composed of 

stakeholders, including environmental justice leaders and other 
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leaders from state and local government and the private sector. 

Additionally, the agency conducted a community call on February 

26, 2015, and on February 27, 2015, the EPA conducted a follow 

up webinar for participants in an October 30, 2014 training 

session. The EPA also held a webinar for communities on the 

Clean Air Act (CAA) and section 111(d) of the CAA on April 2, 

2015. The agency, in partnership with FERC and DOE, held two 

additional webinars for communities on the electricity grid and 

on energy markets on June 11, 2015, and July 9, 2015.

During the EPA’s extensive outreach conducted before and 

after proposal, the EPA has heard a variety of issues raised by 

environmental justice communities. Communities expressed the 

desire for the agency to conduct an environmental justice (EJ) 

analysis and to require that states in the development of their 

state plans conduct one as well. Additionally, they asked that 

the agency require that states engage with communities in the 

development of their state plans and that the agency conduct 

meaningful involvement with communities, throughout the whole 

rulemaking process, including the implementation phase. 

Furthermore, communities stressed the importance of low-income 

and communities of color receiving the benefits of this 

rulemaking and being protected from being adversely impacted by 

this rulemaking. 
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The purpose of this rule is to substantially reduce 

emissions of CO2, a key contributor to climate change, which 

adversely and disproportionallydisproportionately affects 

vulnerable and disadvantaged communities in the USU.S. and 

throughoutaround the world. In addition, the rule will result 

in substantial reductions of conventional air pollutants, 

providing immediate public health benefits to the communities 

where the facilities are located and for many miles around. The 

EPA is committed to ensuring that all Americans benefit from the 

public health and other benefits that this rule will bring. 

Further discussion of the impacts of this rule on vulnerable

communities and actions that the EPA is taking to address 

concerns cited by communities is available in Sections IX and 

XII.J of this preamble. 

10. Labor 

Senior agency officials met with a number of labor union 

representatives about reducing carbon pollution using CAA 

section 111(d). Those unions included: the United Mine Workers 

of America; the Sheet Metal, Air, Rail and Transportation Union 

(SMART); the International Brotherhood of Boilermakers, Iron 

Ship Builders, Blacksmiths, Forgers and Helpers (IBB); United 

Association of Journeymen and Apprentices of the Plumbing and 

Pipe Fitting Industry of the United States and Canada; the 
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International Brotherhood of Electrical Workers (IBEW): and the 

Utility Workers Union of America. In addition, agency leaders 

met with the Presidents of several unions and the President of 

the American Federation of Labor-Congress of Industrial 

Organizations (AFL-CIO) at the AFL-CIO headquarters. 

EPA officials attended meetings sponsored by labor unions 

to give presentations and engage in discussions about reducing 

carbon pollution using CAA section 111(d). These included 

meetings sponsored by the IBB and the IBEW. 

11. Other federal agencies and independent agencies 

Throughout the development of the rulemaking, the EPA 

consulted with other federal agencies with relevant expertise. 

For example, the EPA met with managers from the U.S. Department 

of Agriculture’s (USDA’s) Rural Utility Service to discuss the 

rule and potential effects on affected EGUs in rural areas and 

how USDA programs could interact with affected EGUs during rule 

implementation. 

The U.S. Department of Energy (DOE) was a frequent source 

of expertise and advice on the proposed and final rule. EPA 

management and staff had numerous meetings with management and 

staff at DOE on a range of topics, including the effectiveness 

and costs of energy generation technologies, and energy 

efficiency. 
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DOE provided technical assistance relating to RE and 

demand-side EE, including RE and demand-side EE cost and 

performance data and, for RE, information on the feasibility of 

deploying and reliably integrating increased RE generation. 

Further, EPA and DOE staff discussed emission measurement and 

verification (EM&V) strategies. 

 The EPA also consulted with DOE on electric reliability 

issues. EPA staff and managers met and spoke with DOE staff and 

managers throughout the development of the proposed and final 

rules on topic related to electric system reliability. 

 EPA officials worked closely with DOE and Federal Energy 

Regulatory Commission (FERC) officials to ensure, to the 

greatest extent possible, that actions taken by states and 

affected EGUs to comply with the final rule mitigate potential 

electric system reliability issues. Senior EPA officials met 

with each of the FERC Commissioners and EPA staff had frequent 

contact with FERC staff throughout the development the rule. 

FERC held four technical conferences to discuss implications of 

compliance approaches to the rule for electric reliability. EPA 

staff attended the four conferences and EPA leadership spoke at 

all of them. The EPA, DOE, and FERC will continue to work 

together to ensure electric grid reliability in the development 

and implementation of state plans. 
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KL. Comments on the Proposal 

The Administrator signed the proposed emission guidelines 

on June 2, 2014, and, on the same day, the EPA made this version 

available to the public at http://www.epa.gov/cleanpowerplan/.

The 120-day public comment period on the proposal began on June 

18, 2014, the day of publication of the proposal in the Federal 

Register. On September 18, 2014, in response to requests from 

stakeholders, the EPA extended the comment period by 45 days, to 

December 1, 2014, giving stakeholders over 165 days to review 

and comment upon the proposal. Stakeholders also had the 

opportunity to comment on the NODA, as well as the notice and 

TSD regarding potential methods for determining the mass that is 

equivalent to an emission rate-based CO2 goal, through December 

1, 2014. The EPA offered a separate 45-day comment period for 

the November 4, 2014 supplemental proposal, and that comment 

period closed on December 19, 2014. 

The EPA received more than 4.2 million comments on the 

proposed carbon pollution emission guidelines from a range of 

stakeholders that included, including state environmental and 

energy officials, local government officials, tribal officials, 

public utility commissioners, system operators, utilities, 

public interest advocates, and members of the public. The agency 
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received comments on many aspects of the proposal and many 

suggestions for changes that would address issues of concern.

III. Rule Requirements and Legal Basis 

A. Summary of Rule Requirements 

The EPA is establishing emission guidelines for states to 

use in developing plans to address greenhouse gas emissions from 

existing fossil fuel-fired electric generating units. The 

emission guidelines are based on the EPA’s determination of the 

“best system of emission reduction ... adequately demonstrated” 

(BSER) and include source category-specific CO2 emission 

performance rates, state-specific goals, requirements for state 

plan components, and requirements for the process and timing for 

state plan submittal and compliance. 

Under CAA section 111(d), the states must establish 

standards of performance that reflect the degree of emission 

limitation achievable through the application of the “best 

system of emission reduction” that, taking into account the cost 

of achieving such reduction and any non-air quality health and 

environmental impact and energy requirements, the Administrator 

determines has been adequately demonstrated. 

The EPA has determined that the BSER is the combination of 

emission rate improvements and limitations on overall emissions 

at affected EGUs that can be accomplished through any 
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combination of one or more measures from the following three 

sets of measures or building blocks: 

1. Reducing the carbon intensity of generation at 

individualImproving heat rate at affected coal-fired 

steam EGUs through heat rate improvements. 

2. Substituting increased generation from loweremitting existing natural gas combined cycle units for 

reduced generation from higher-emitting affected steam 

generating units. 

3. Substituting increased generation from new low- and 

zero-emitting RE generating unitscapacity for reduced 

generation from affected fossil fuel-fired generating 

units. 

Consistent with CAA section 111(d),) and other rules 

promulgated under this section, the EPA is taking a traditional, 

performance-based approach to establishing emission guidelines 

for affected sources and applying the BSER to two source 

subcategories of existing fossil fuel-fired EGUs -- fossil fuelfired electric utility steam generating units and stationary 

combustion turbines. The EPA is finalizing source subcategoryspecific emission performance rates that reflect the EPA’s 

application of the BSER. For fossil fuel-fired steam generating 
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units, we are finalizing a performance rate of 1,290305 lb

CO2/MWh of CO2. For stationary combustion turbines, we are 

finalizing a performance rate of 780771 lb CO2/MWh of CO2. The 

EPA has also translated the source subcategory-specific CO2

emission performance rates into equivalent statewide rate-based 

and mass-based CO2 goals and is providing those as an option for 

states to use. 

Under CAA section 111(d), each state must develop, adopt, 

and then submit its plan to the EPA. For its CAA section 111(d) 

plan, a state will determine whether to apply these emission 

performance rates to each affected EGU, individually or 

together, or to take an alternative approach and meet either an 

equivalent statewide rate-based goal or an equivalent statewide 

mass-based goal, as provided by the EPA in this rulemaking. 

For these final States with one or more affected EGUs will 

be required to develop and implement plans that set emission 

standards for affected EGUs. The CAA section 111(d) emission 

guidelines, that the term “state,” when usedEPA is promulgating

in this action apply to only the context of section 111(d) 

plans, encompasses the 5048 contiguous states, the District of 

Columbia, U.S. territories, and any Indian tribe that has been 

approved by the EPA pursuant to 40 CFR 49.9 as eligible to 

develop and implement a CAA section 111(d) plan. However, such a 
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“state” would not be obligated or potentially eligible to submit 

a CAA section 111(d) plan unless it has within its 

jurisdictional boundaries one or more affected EGUs that 

commenced construction on or before January 8, 2014. ..346Because 

Vermont and the District of Columbia do not have affected EGUs, 

they will not be required to submit a state plan. Because the 

EPA does not possess all of the information and analytical tools 

needed to quantify the BSER for the two non-contiguous states 

with otherwise affected EGUs (Alaska and Hawaii) and the two 

U.S. territories with otherwise affected EGUs (Guam and Puerto 

Rico), these emission guidelines do not apply to those areas, 

and those areas will not be required to submit state plans on 

the schedule required by this final action.

In developing its CAA section 111(d) plan, a state will 

have the option of choosing from two different approaches: 1) an 

“emission standards” approach, or 2) a “state measures” 

 

346 In the case of a tribe that has one or more affected EGUs in 

its area of Indian country, the tribe has the opportunity, but 

not the obligation, to establish a CO2 emission standard for each 

affected EGU located in its area of Indian country and a CAA 

section 111(d) plan for its area of Indian country. If the tribe 

chooses to establish its own plan, it must seek and obtain 

authority from the EPA to do so pursuant to 40 CFR 49.9. If it 

chooses not to seek this authority, the EPA has the 

responsibility to determine whether it is necessary or 

appropriate, in order to protect air quality, to establish a CAA 

section 111(d) plan for an area of Indian country where affected 

EGUs are located. 
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approach. With an emission standards approach, a state will 

apply all requirements for achieving the subcategory-specific CO2

emission performance rates or the state-specific CO2 emission 

goal to affected EGUs in the form of federally enforceable 

emission standards. With a state measures approach, a state plan 

would be comprised, at least in part, of measures implemented by 

the state that are not included as federally enforceable 

components of the plan, along with a backstop of federally 

enforceable emission standards for affected EGUs that would 

apply in the event the plan does not achieve its anticipated 

level of CO2 emission performance. 

The EPA is requiring states to make their initial plan 

submittals 13 months from the signature date of the rule and to 

make their final plan submittals no later than 3 years from the 

signature date of the rule. 

The EPA is requiring states to make their final plan 

submittals by September 6, 2016, or to make an initial submittal 

by this date in order to obtain an extension for making their 

final plan submittals no later than September 6, 2018, which is 

3 years from the signature date of the rule. In order to receive 

an extension, states, in the initial submittal, must address 

three required components sufficiently to demonstrate that a 

state is able to undertake steps and processes necessary to 
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timely submit a final plan by the extended date of September 6, 

2018. The first required component is identification of final 

plan approach or approaches under consideration, including a 

description of progress made to date. The second required 

component is an appropriate explanation for why the state 

requires additional time to submit a final plan beyond September 

6, 2016. The third required component for states to address in 

the initial submittal is a demonstration of how they have been 

engaging with the public, including vulnerable communities, and 

a description of how they intend to meaningfully engage with 

community stakeholders during the additional time (if an 

extension is granted) for development of the final plan. 

Affected EGUs must achieve the final emission performance 

rates or equivalent state goals by 2030 and maintain that level 

thereafter. The EPA is establishing an eight-year interim period 

over which states must achieve the full required reductions to 

meet the CO2 performance rates, and this begins in 2022. This 

eight-year interim period from 2022 through 2029, is separated 

into three steps, 2022-2024, 2025-2027, and 2028-2029, each 

associated with its own interim CO2 emission performance rates 

that states must meet, as explained in Section VI of this 

preamble. Affected EGUs must achieve the final emission 
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performance rates or equivalent statewide goals by 2030 and 

maintain that level thereafter.

The EPA is further establishing, as part of the guidelines, 

timetables for states to submit their plans. Each state must use 

the established electronic submittal system to provide the EPA 

its complete plan submittal by August 31, 2016. However, if a 

state needs additional time to provide the EPA with a complete 

plan submittal, the state must provide an initial plan submittal 

by August 31, 2016, that documents the reasons that more time is 

needed to provide a complete plan submittal and includes 

commitments to take concrete steps that will ensure that the 

state will submit a complete plan by August 31, 2018. 

For the final emission guidelines, the EPA is revising 

the list of components required in a final state plan 

submittal to reflect: 1) components required for all state 

plan submittals; 2) components required for the emission 

standards approach; and 3) components required for the 

state measures approach. The revised list of components 

also reflects the approvability criteria, which are no 

longer separate from the state plan submittal components. 

All state plans must include the following components:

• Description of the plan approach and geographic scope 

• Identification of state statethe state’s CO2 interim period 

goal (for 2022-2029), interim steps (interim step goal 1 
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for 2022-2024; interim step goal 2 for 2025-2027; interim 

step goal 3 for 2028-2029) and final CO2 emission goal of 

2030 and beyond 

• Demonstration that the plan submittal is projected to 

achieve the state’s CO2 emission goal347

• State recordkeeping and reporting requirements 

• Certification of hearing on state plan 

• Supporting documentation 

 State recordkeeping and reporting requirements 

• Certificatin of hearing on state plan 

 Supporting documentation 

Also, in all state plans, as part of the supporting 

documentation, statesa state must include a description of their 

required consultation with relevant ISOs/RTOs and/or 

planning/how they considered reliability authorities duringin 

developing its state plan development, including any 

recommendations and other comments provided by those 

authorities. 

Further, the EPA is requiring that states provide, in their 

initial plan submittal, a summary of how they have been engaging 

with community stakeholders and how they intend to meaningfully 

engage with community stakeholders during the additional time 

(if an extension is granted) for development of the final plan. 

In their report, states must show how they identified low income 

 

347 A state that chooses to set emission standards that are 

identical to the emission performance rates for both the interim 

period and in 2030 and beyond need not identify interim state 

goals nor include a separate demonstration that its plan will 

achieve the state goals. 
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and communities of color that they are conducting meaningful 

community engagement with in the state plan development process. 

For the final plan submittal, states must engage with all 

members of the public, including communities, during the 

complete plan development process pursuant to the public 

participation requirements of the framework regulations..

State plan submittals using the emission standards approach 

must also include: 

 Identification of each affected EGU; identification of 

federally enforceable emission standards for the affected 

EGUs; and monitoring, recordkeeping and reporting 

requirements. 

 Demonstrations that each emission standard iswill result in 

reductions that are quantifiable, non-duplicative, 

permanent, verifiable, and enforceable. 

State plan submittals using the state measures approach 

must also include: 

 Identification of each affected EGU; identification of 

federally enforceable emission standards for affected EGUs 

(if applicable); identification of backstop of federally 

enforceable emission standards; and monitoring, 

recordkeeping and reporting requirements. 

 Identification of each state measure and demonstration that 

each state measure iswill result in reductions that are

quantifiable, non-duplicative, permanent, verifiable, and 

enforceable. 

In addition to these requirements, each state plan must follow 

the EPA implementing regulations at 40 CFR 60.23. 
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 If a state with affected EGUs does not submit a plan or if 

the EPA does not approve a state’s plan, then under CAA section 

111(d)(2)(A), the EPA must establish a plan for that state. A 

state that has no affected EGUs must document this in a formal 

letternegative declaration submitted to the EPA by August 

31September 6, 2016. In the case of a tribe that has one or more 

affected EGUs in its area of Indian country,348 the tribe has the 

opportunity, but not the obligation, to establish a CAA section 

111(d) plan for its area of Indian country. If a tribe with one 

or more affected EGUs located in its area of Indian country does 

not submit a plan or does not receive EPA approval of a 

submitted plan, the EPA has the responsibility to establish a 

CAA section 111(d) plan for that area if it determines that such 

a plan is necessary or appropriate. 

 During and following implementation of its approved state

plan, each state must demonstrate to the EPA that its affected 

EGUs are meeting the interim and final performance requirements 

included in this final rule through monitoring and reporting 

 

348 The EPA is aware of at least four affected EGUs located in 

Indian country: two on Navajo lands, the Navajo Generating 

Station and the Four Corners Power Plant; one on Ute lands, the 

Bonanza Power Plant; and one on Fort Mojave lands, the South 

Point Energy Center. The affected EGUs at the first three plants 

are coal-fired EGUs. The fourth affected EGU is an NGCC 

facility. 
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requirements. State plan requirements and flexibilities are 

described more fully in Section VIII of this preamble.

B. Brief Summary of Legal Basis 

This rule is consistent with the requirements of CAA 

section 111(d) and the implementing regulations.349 As an initial 

matter, the EPA reasonably interprets the provisions identifying 

which air pollutants are covered under CAA section 111(d) to 

authorize the EPA to regulate CO2 from fossil fuel-fired EGUs. In 

addition, the EPA recognizes that CAA section 111(d) applies to 

sources that, if they were new sources, would be covered under a 

CAA section 111(b) rule. Concurrently with this rule, the EPA is 

finalizing a CAA section 111(b) rulemaking establishing 

standards of performance for CO2 emissions from new fossil fuel-

 

349 Under CAA section 111(d), there is no requirement that the EPA 

make a finding that the emissions from existing sources that are 

the subject of regulation cause or contribute significantly to 

air pollution which may reasonably be anticipated to endanger 

public health or welfare. As predicates to promulgating 

regulations under CAA section 111(d) for existing sources, the 

EPA must make endangerment and cause-or-contribute-significantly 

findings for emissions from the source category, and the EPA 

must promulgate regulations for new sources in the source 

category. In the CAA section 111(b) rule for CO2 emissions for 

new affected EGUs that the EPA is promulgating concurrently with 

this rule, the EPA discusses the endangerment and cause-orcontribute-significantly findings and explains why the EPA has 

already made them for the affected EGU source categories so that 

the EPA is not required to make them for CO2 emissions from 

affected EGUs, and, in the alternative, why, if the EPA were 

required to make those findings, it was making them in that 

rulemaking. 
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fired EGUs, from modified fossil fuel-fired EGUs, and from 

reconstructed fossil fuel-fired EGUs, and any of those sets of 

section 111(b) standards of performance provides the requisite 

predicate for this rulemaking. 

A key step in promulgating requirements under CAA section 

111(d)(1) is determining the “best system of emission reduction 

which ... the Administrator determines has been adequately 

demonstrated” (BSER) under CAA section 111(a)(1). It is clear by 

the terms of section 111(a)(1) and the implementing regulations 

for section 111(d) that the EPA is authorized to determine the 

BSER;350 accordingly, in this rulemaking, the EPA is determining 

the BSER. 

The EPA is finalizing the BSER for fossil fuel-fired EGUs 

based on building blocks 1, 2, and 3. Building block 1 includes 

operational improvements and equipment upgrades that the coalfired steam-generating EGUs in the state may undertake to 

improve their heat rate. It qualifies as part of the BSER 

because it improves the carbon intensity of the affected EGUs in 

generating electricity through actions the affected sources may 

undertake that are adequately demonstrated and whose cost is 

“reasonable.” Building blocks 2 and 3 include increases in low- 

 

350 The EPA is not re-opening that interpretation in this 

rulemaking. 
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or zero-emitting generation which substitute for generation from 

the affected EGUs and thereby reduce CO2 emissions from those 

sources. All of these measures are components of a “system of 

emission reduction” for the affected EGUs because they entail 

actions that the affected EGUs may themselves undertake that 

have the effect of reducing their emissions. Further, these 

measures meet the criteria in CAA section 111(a)(1) and the case 

law for the “best” system of emission reduction that is 

“adequately demonstrated” because they achieve the appropriate 

level of reductions, their cost is “reasonable,” they do not 

have adverse non-air quality health and environmentenvironmental

impacts or impose adverse energy requirements, and they are each 

well-established among affected EGUs. It should be emphasized 

that these measures are consistent with current trends in the 

electricity sector. 

Building blocks 2 and 3 includemay be implemented through a 

set of measures, including reduced generation from the fossil 

fuel-fired EGUs because. These measures do not, however, reduce 

the amount of electricity that is a step in the process of 

substituting lower-can be sold or zero-emitting generation for 

higher-emitting generationthat is available to end users. In 

addition, states should be expected to allow their affected EGUs 

to trade rate-based emission credits or mass-based emission 
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allowances (trading) because trading is well-established for 

this industry and has the effect of focusing costs on the 

affected EGUs for which reducing emissions is most costeffective. Because trading facilitates implementation of the 

building blocks and may help to optimize cost-effectiveness, 

trading is withina method of implementing the BSER as well. 

As a result, an affected EGU has a set of choices for 

achieving its emission standards. ItFor example, an affected 

coal-fired steam generating unit can achieve a rate-based 

standard through a set of actions that implement the building 

block 1 measures and that implement the building block 2 and 3

measures through a set of actions that range from purchasing 

full or partial interest in existing NGCC or new renewable 

energy assetsREassets to purchasing emission rate credits that 

represent the environmental attributes of increased NGCC 

generation or new renewable generation. In addition, the 

affected EGU may reduce its generation and thereby reduce the 

extent that it needs to implement the building blocks. In 

addition, theThe affected EGU may also purchase rate-based 

emission credits from other affected EGUs. If the state chooses 

to impose a mass-based emission standard, the affected EGUcoalfired steam generating unit may implement building block 1 

measures, purchase mass-based emission allowances from other 
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affected EGUs, or reduce its generation. In light of the 

available sources of lower- and zero-emitting replacement 

generation, this approach would achieve an appropriate level of 

emission reductions and maintain the reliability of the 

electricity system. 

With the promulgation of the emission guidelines, each 

state must develop and submit a plan to achieve the CO2 emission 

performance rates established by the EPA or the equivalent 

statewide rate-based or mass-based goal provided by the EPA in 

this rule. The EPA interprets CAA section 111(d) to allow states 

to establish standards of performance and provide for their 

implementation and enforcement through either the “emission 

standards” or the “state measures” plan type. In the case of the 

“emission standards” plan type, the emission standards establish 

standards of performance, and the other components of the plan 

provide for their implementation and enforcement. In the case of 

the “state measures” plan type, –the state submits a plan that 

relies upon measures that are only enforceable as a matter of 

state law that will, in conjunction with any emission standards 

of on affected EGUs, result in the achievement of the applicable 

performance in the form of rates or state goals by the affected 

EGUs. Under the state measures plan type, states must also 

submit a federally enforceable backstop and a mechanism that 
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would trigger implementation of the backstop; therefore, in a 

state measures plan, the standards of performance take the form 

of the backstop, the trigger mechanism provides for the 

implementation of such backstop, and the other required 

components of the plan also provide for implementation and 

enforcement of the standards of performance. 

 These two types of state plans and their respective 

approaches, which could be implemented on a single-state or 

multi-state basis, allow states to meet the statutory 

requirements of section 111(d) while accommodating the wide 

range of regulatory requirements and other programs that states 

have deployed or will deploy in the electricity sector that 

reduce CO2 emissions from affected EGUs. It should be noted that 

both state plan types allow the state flexibility in assigning 

the emission performance obligations to its affected EGUs in the 

form of standards of performance as long as the required 

emission performance level is met. Both plan types harness the 

efficiencies of emission reduction opportunities in the 

interconnected electricity system and are fully consistent with 

the principles of cooperative federalism that underlie the Clean 

Air Act generally and CAA section 111(d) particularly. That is, 

both plan types achieve the emission performance requirements 

through the vehicle of a state plan, and provide each state 
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significant flexibility to take local circumstances and state 

policy goals into account in determining how to reduce emissions 

from its affected sources, as long as the plan meets minimum 

federal requirements. 

Both state plan types, and the standards of performance for 

the affected EGUs that the states will establish through the 

state plan process, are consistent with the applicable CAA 

section 111 provisions. A state has discretion in determining 

the appropriate measures to rely upon for its plan. The state 

may adopt measures that assure the achievement of the requisite 

CO2 emission performance rate or state goal by the affected EGUs, 

and is not limited to the measures that the EPA identifies as 

part of the BSER. 

 In this rulemaking, the EPA establishes reasonable 

deadlines for state plan submission. Under CAA section 

111(d)(1), state plans must “provide for implementation and 

enforcement” of the standards of performance, and under CAA 

section 111(d)(2), the state plans must be “satisfactory” for 

the EPA to approve them. In this rulemaking, the EPA is 

finalizing the criteria that the state plans must meet under 

these requirements. 

 The EPA discusses its legal interpretation in more detail 

in other parts of this preamble and discussesprovides additional 
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information about certain issues in more detail in the Legal 

Memorandum included in the docket for this rulemaking. 

IV. Authority for this Rulemaking, Definition of Affected 

Sources, and Treatment of Source Categories 

A. EPA’s Authority under CAA Section 111(d) 

EPA’s authority for this rule is CAA section 111(d). CAA 

section 111(d) provides that the EPA will promulgate regulations 

under which each state will establish standards of performance 

for existing sources for any air pollutant that meets two 

criteria. First, CAA section 111(d) applies to air pollutants 

that are not regulated as a criteria pollutant under section 108 

or as a hazardous air pollutant (HAP) under CAA section 112. 42 

U.S.C. 7411(d)(1)(A)(i).351 Second, section 111(d) applies only 

to air pollutants for which the existing source would be 

regulated under section 111 if it were a new source. 42 U.S.C. 

7411(d)(1)(A)(ii). Here, carbon dioxide (CO2) meets both 

criteria: (1) it is not a criteria pollutant regulated under 

section 108 nor a HAP regulated under CAA section 112, and (2) 

CO2 emissions from new power plants (including newly constructed, 

modified and reconstructed power plants) are regulated under the 

 

351 Section 111(d) might be read to apply to HAP under certain 

circumstances. However, because carbon dioxide is not a HAP, 

this issue does not need to be resolved in the context of this 

rule. 
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CAA section 111(b) rule published todaythat is being finalized

along with this rule. 

B. CAA Section 112 Exclusion to CAA Section 111(d) Authority 

CAA section 111(d) contains an exclusion that limits the 

regulation under CAA section 111(d) of air pollutants that are 

regulated under CAA section 112. 42 U.S.C. 7411(d)(1)(A)(i). 

This “Section 112 Exclusion” in CAA section 111(d) was the 

subject of a significant number of comments based on two 

differing amendments to this exclusion enacted in the 1990 CAA 

Amendments. As discussed in more detail below, the House and the 

Senate each initially passed different amendments to the Section 

112 Exclusion and both amendments were ultimately passed by both 

houses and signed into law. In 2005, in connection with the 

Clean Air Mercury Rule (CAMR), the EPA discussed the agency’s 

interpretation of the exclusionSection 112 Exclusion in light of 

these two differing amendments and concluded that the two 

amendments were in conflict, and that the provision should be 

read as follows to give both amendments meaning, and should be 

interpreted as follows: where a source category has been 

regulated under CAA section 112, a CAA section 111(d) standard 

of performance cannot be established to address any HAP listed 

under CAA section 112(b) that may be emitted from that 
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particular source category. See 70 FR 15994, 16029-3032 (March 

29, 2005). 

 In June 2014, the EPA presented this previous 

interpretation along withas part of the proposed ruleproposal

and requested comment on it. The EPA received numerous comments 

on its previous interpretation, including comments on the proper 

interpretation and effect of each of the two differing 

amendments, and whether the Section 112 Exclusion should be read 

to mean that the EPA’s regulation of HAP from power plants under 

CAA section 112 bars the EPA from establishing CAA section 

111(d) regulations covering CO2 emissions from power plants. In 

particular, many comments focused on two specific issues. 

First, some commenters -- including some industry and state 

commenters that had previously endorsed the EPA’s interpretation 

of the Section 112 Exclusion in other contexts352 -- argued that 

the EPA’s 2005 interpretation was in error because it allowed 

 

352 For example, in the CAMR litigation (State of New Jersey v. 

EPA, No. 05-1097 (D.C. Cir.) ,.), the joint brief filed by a 

group of intervenors and an amicus (including six states and the 

West Virginia Department of Environmental Protection, and 

Utility Air Regulatory Group and nine other industry entities) 

stated that the EPA had interpreted section 111(d) in light of 

the two different amendments and that the EPA’s interpretation 

was “a reasoned way to reconcile the conflicting language and 

the Court should defer to the EPA’s interpretation.” Joint 

Brief of State Respondent-Intervenors, Industry RespondentIntervernors, and State Amicus, filed May 18, 2007, at 25. 
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the regulation of certain pollutants from source categories 

under CAA section 111(d) when those source categories were also 

regulated for different pollutants under CAA section 112. 

Second, some commenters argued that the EPA’s previous 

interpretation of the House amendment (as originally represented 

in 2005 at 70 FR at 16029-30) was in error because it improperly 

read that amendment as focusing on whether a source category was 

regulated under CAA section 112 rather than on whether the air 

pollutant was regulated under CAA section 112, and that improper 

reading lead to an interpretation that was inconsistent with the 

structure and purpose of the CAA. 

In light of the comments, the EPA has reconsidered its 

previous interpretation of the Section 112 Exclusion and, in 

particular, considered whether the exclusion precludes the 

regulation under CAA section 111(d) of CO2 from power plants 

given that power plants are regulated for certain HAP under CAA 

section 112. On this issue, the EPA has concluded that the two 

differing amendments are not properly read as conflicting. 

Instead, the House amendment and the Senate Amendment should 

each be read to mean the same in thisthe context presented by 

this rule: that the Section 112 Exclusion does not bar the 

regulation under CAA section 111(d) of any non-HAP from a source 

category, regardless of whether that source category may beis
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subject to standards for HAP under CAA section 112. In reaching 

this conclusion, the EPA has revised its previous interpretation 

of the House amendment, as discussed below. 

The EPA’s analysis is entitled to deference under the 

principles established in Chevron v. NRDC, 467 U.S. 837 (1984). 

See White Stallion Energy v. EPA, 748 F.3d 1222, 1235 (D.C. Cir. 

2014) (a revision to an agency interpretation is reviewed under 

the Chevron framework. Under that framework, the revised 

interpretation will be upheld if the court finds that it “is 

permissible under the statute, that there are good reasons for 

it, and that the agency believes it to be better.”) (quoting FCC 

v. Fox Television Stations, Inc., 556 U.S. 502, 515 (2009)).353 

The EPA’s revised interpretation is discussed below. 

1. Structure of the CAA and Pre-1990 Section 112 Exclusion 

The Clean Air Act sets out a comprehensive scheme for air 

pollution control, addressing three general categories of 

pollutants emitted from stationary sources: (1) criteria 

pollutants (which are addressed in sections 108-110); (2) 

hazardous pollutants (which are addressed under section 112); 

and (3) “pollutants that are (or may be) harmful to public 

 

353 Indeed, the Chevron case itself involved the EPA’s 

reevaluation of how to interpret an ambiguous statutory term. 

See 467 U.S. at 857-58 (EPA reevaluation of how to interpret the 

term “source”).
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health or welfare but are not or cannot be controlled under 

sections 108-110 or 112.” 40 Fed. Reg. 53,340FR 53340 (Nov. 17, 

1975). 

Six “criteria” pollutants are regulated under sections 108-

110. These are pollutants that the Administrator has concluded 

“cause or contribute to air pollution which may reasonably be 

anticipated to endanger public health or welfare;” “the presence 

of which in the ambient air results from numerous and diverse 

mobile or stationary sources;” and for which the Administrator 

has issued, or plans to issue, “air quality criteria. 42 U.S.C. 

§7408(a)(1). Once the EPA issues air quality criteria for such 

pollutants, the Administrator must propose primary National 

Ambient Air Quality Standards (NAAQS) for them, set at levels 

“requisite to protect the public health” with an “adequate 

margin of safety..” 42 U.S.C. § 7409(a)-(b). States must then 

adopt plans for implementing NAAQS. 42 U.S.C. § 7410. 

Hazardous air pollutants (HAP) are regulated under CAA 

section 112 and include the pollutants listed by Congress in 

section 112(b)(1) and other pollutants that the EPA lists under 

sections 112(b)(2) and (b)(3). CAA section 112 further provides 

that the EPA will publish and revise a list of “major” and 

“area” source categories of hazardous pollutantsHAP, and then 

establish emissions standards for hazardous air pollutants(HAP)
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emitted by sources within aeach listed category. 42 U.S.C. § 

7412(c)(1) & (2). 

 CAA section 111, 42 U.S.C. § 7411, is the third part of the 

CAA’s structure for regulating stationary sources. CAA 

sectionSection 111 has two main components. First, CAA section 

111(b) requires the EPA to promulgate federal “standards of 

performance” addressing new stationary sources that cause or 

contribute significantly to “air pollution which may reasonably 

be anticipated to endanger public health or welfare.” 42 U.S.C. 

§ 7411(b)(1)(A). Once the EPA has set new source standards 

addressing emissions of a particular pollutant, under CAA 

section 111(b), CAA section 111(d) provides that the EPA will 

promulgate regulations requiring states to establish standards 

of performance for existing stationary sources of the same 

pollutant. 42 U.S.C. § 7411(d)(1). 

Together, the criteria pollutant/NAAQS provisions in 

sections 108-110, the hazardous air pollutant provisions in 

section 112, and performance standard provisions in section 111 

constitute a comprehensive scheme to regulate air pollutants 

with “““no gaps in control activities pertaining to stationary 
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source emissions that pose any significant danger to public 

health or welfare.” S. Rep. No. 91-1196, at 20 (1970). 354 

The specific role of CAA section 111(d) in this structure 

can be seen in CAA subsection 111(d)(1)(A)(i), which provides 

that regulation under CAA section 111(d) regulation of 

pollutants is intended to cover pollutants that are not 

regulated under either the criteria pollutant/NAAQS provisions 

or the hazardous air pollutantsHAP regulated under section 112. 

Prior to 1990, this limitation was laid out in plain language, 

which stated that CAA section 111(d) regulation applied to “any 

air pollutant... for which air quality criteria have not been 

issued or which is not included on a list published under 

section [108(a)] or [112(b)(1)(A)].” This plain language 

demonstrated that section 111(d) is designed to regulate 

pollutants from existing sources that fall in the gap betweennot 

covered by the criteria pollutant provisions andor the hazardous 

air pollutant provisions. 

This gap-filling purpose can be seen in the early 

legislative history of the CAA. As originally enacted in the 

1970 CAA, the precursor to CAA section 111 (which was originally 

 

354 In subsequent CAA amendments, Congress has maintained this 

three-part scheme, but supplemented it with the Preservation of 

Significant Deterioration (PSD) program, the Acid Rain Program 

and the Regional Haze program. 
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section 114) was described as covering pollutants that would not 

be controlled by the criteria pollutant provisions or the 

hazardous air pollutant provisions. See S. Committee Rep. to 

accompany S. 4358 (Sept. 17, 1970), 1970 CAA Legis. Hist. at 420 

(“It should be noted that the emission standards for pollutants 

which cannot be considered hazardous (as defined in section 115 

[which later became section 112]) could be established under 

section 114 [later, section 111]. Thus, there should be no gaps 

in control activities pertaining to stationary source emissions 

that pose any significant danger to public health or welfare.”); 

Statement by S. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 

1970 CAA Legis. Hist. at 227 (“[T]he bill [in section 114] 

provides the Secretary with the authority to set emission 

standards for selected pollutants which cannot be controlled 

through the ambient air quality standards and which are not 

hazardous substances.”). 

2. The 1990 Amendments to the Section 112 Exclusion 

The Act was amended extensively in 1990. Among other 

things, Congress sought to accelerate the EPA’s regulation of 

hazardous pollutants under section 112. To that end, Congress 

established a lengthy list of hazardous air pollutantsHAP; set 

criteria for listing “source categories” of such pollutants; and 

required the EPA to establish standards for each listed source 
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category or subcategory’scategory’s hazardous pollutant 

emissions. 42 U.S.C. § 7412(a), (b)(1) & (2), &), (c) and

(d)(1). In the course of overhauling the regulation of hazardous 

air pollutants(HAP) under section 112, Congress needed to edit 

section 111(d)’s reference to section 112(b)(1)(A), which crossreferenced a provision of old section 112 that was to be 

eliminated –as part of the revisions to section 112(b)(1)(A).. 

To address the obsolete cross-reference to section 

7412(b)(1)(A), Congress passed two differing amendments – one 

from the HouseSenate and one from the SenateHouse – that were 

never reconciled in conference. The Senate amendment replaced 

the cross reference to old section 112(b)(1)(A) with a crossreference to new section 112. Pub. L. No. 101-549, § 302(a), 104 

Stat. 2399, 2574 (1990). The House amendment replaced the crossreference with the phrase “emitted from a source category which 

is regulated under section [112].” Pub. L. No. 101-549, § 

108(g), 104 Stat. 2399, 2467 (1990). The Senate amendment 

replaced the same text with a cross-reference to new section 

112. 355Pub. L. No. 101-549, § 302(a), 104 Stat. 2399, 2574 

 

355 Originally, when the House bill to amend the CAA was 

introduced in January 1989, it focused on amendments to control 

HAP. Of particular note, the amendments to section 112 included 

a provision that excluded regulation under section 112 of “[a]ny 

air pollutant which is included on the list under section 
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(1990). Both amendments were enacted into law, and are thus 

both are part of the current CAA. To determine how this this 

provision is properly applied in light of the two differing 

amendments, we first look at the Senate amendment, then at the 

House amendment, then discuss how the two amendments are 

properly read together. 

3. The Senate Amendment is Clear and Unambiguous 

 Unlike the ambiguous amendment to CAA section 111(d) in the 

House amendment (discussed below), the Senate amendment is 

 

108(a), or which is regulated for a source category under 

section 111(d).” H.R. 4, § 2 (Jan. 3, 1989), 1990 CAA Legist. 

Hist. at 4046. In other words, the Section 112 Exclusion in 

section 111(d) that was ultimately contained in the House 

amendment was originally crafted as what might be called a 

“Section 111(d) Exclusion” in section 112. This is significant 

because the “source category” phrasing in the original January 

1989 text with respect to section 111(d) makes sense, whereas 

the “source category” phrasing in the 1990 House amendment does 

not. When referring to the scope of what is regulated under 

section 111(d), it makes sense to frame that scope with respect 

to source categories, because section 111 regulation begins with 

the identification of source categories under section 

111(b)(1)(A). By contrast, regulation under section 112 begins 

with the identification of HAP under section 112(b); the listing 

of source categories under section 112(c) is secondary to the 

listing of HAP. From this history, and in light of this 

difference between the scope of what is regulated in sections 

111 and 112, it is reasonable to conclude that the “source 

category” phrasing is a legacy from the original 1989 bill—that 

is, when converting the 1989 text into the Section 112 Exclusion 

that we see in the 1990 House amendment, the legislative 

drafters continued to use phrasing based on “source category” 

notwithstanding that this phrasing created a mismatch with the 

way that the scope of section 112 regulation is determined. 
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straightforward and unambiguous. It maintained the pre-1990 

meaning of the Section 112 Exclusion by simply substituting 

“section 112(b)” for the prior cross-reference to “section 

112(b)(1)(A).” Pub. L. No. 101-549, § 302(a), 104 Stat. 2399, 

2574 (1990). So amended, section 111(d) mandates that the EPA 

require states to submit plans establishing standards for “any 

air pollutant . . . which is not included on a list published 

under section [108(a)] or section [112(b)].” Thus, the Section 

112 Exclusion resulting from the Senate amendment would preclude 

section 111(d) regulation of HAP emission but would not preclude 

the EPA from regulatingsection 111(d) regulation of CO2 emissions

from power plants notwithstanding that power plants are also 

regulated for HAP under CAA section 112 under the MATS rule. 

 Some commenters have argued that the Senate amendment 

should be given no effect, because only the House amendment is 

shown in the U.S. Code, and because the Senate amendments 

appeared under the heading “conforming amendments,” and for 

various other reasons. The EPA disagrees. The Senate amendment, 

like the House amendment, was enacted into law as part of the 

1990 CAA amendments, and must be given effect. 

 First, that the U.S. Code only reflects the House amendment 

does not change the fact that both amendments were signed into 

law as part of the 1990 Amendments, as shown in the Statutes at 
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Large. Pub. L. No. 101-549, §§ 108(g) and 302(a), 104 Stat. 

2399, 2467, 2574 (1990). Where there is a conflict between the 

U.S. Code and the Statutes at Large, the latter controls. See 1 

U.S.C. §§ 112 & 204(a); Stephan v. United States, 319 U.S. 423, 

426 (1943) (“the Code cannot prevail over the Statutes at Large 

when the two are inconsistent”); Five Flags Pipe Line Co. v. 

Dep’t of Transp., 854 F.2d 1438, 1440 (D.C. Cir. 1988) (“[W]here 

the language of the Statutes at Large conflicts with the 

language in the United States Code that has not been enacted 

into positive law, the language of the Statutes at Large 

controls.”). 

 Second, the “conforming” label is irrelevant. A 

“conforming” amendment may be either substantive or nonsubstantive. Burgess v. United States, 553 U.S. 124, 135 

(2008). And while the House Amendment contains more words, it 

also qualifies as a “conforming” amendment” under the definition 

in the Senate Legislative Drafting Manual, Section 126(b)(2) 

(defining “conforming amendments” as those “necessitated by the 

substantive amendments of provisions of the bill”). Here, both 

the House and Senate amendments were “necessitated by” Congress’ 

revisions to section 112 in the 1990 CAA Amendment, which 

included the deletion of old section 112(b)(1)(A). Thus, the 

House’s amendment is no less “conforming” than the Senate’s, and 
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the heading under which it was enacted (“Miscellaneous 

Guidance”) does not suggest any more importance than “Conforming 

Amendments.” In any event, courts gives full effect to 

conforming amendments, see Washington Hosp. Ctr. v. Bowen, 795 

F.2d 139, 149 (D.C. Cir. 1986), and so neither the Senate 

Amendment nor the House amendment can be ignored. 

Third, the legislative history of the Senate amendment 

supports the conclusion that the substitution of the updated 

cross-reference was not a mindless, ministerial decision, but 

reflected a decision to choose an update of the cross reference 

overinstead of the text that was inserted into the Section 112 

Exclusion by the House amendment. In mid-1989, the House and 

Senate introduced identical bills (H.R. 3030 and S. 1490, 

respectively) to provide for “miscellaneous” changes to the CAA. 

In both the Senate and House bills as they were introduced in 

mid-1989, the Section 112 Exclusion was to be amended by taking 

out “or 112(b)(1)(A)” and inserting “or emitted from a source 

category which is regulated under section 112.” H.R. 3030, as 

introduced, 101st Cong. § 108 (Jul. 27, 1989); S. 1490, as 

introduced, 101st Cong. § 108 (Aug. 3, 1989). See 1990 CAA 

Legis. Hist. at 3857 (noting that H.R. 3030 and S.1490, as 

introduced, were the same). Although S. 1490 was identical to 

H.R. 3030 when they were introduced, the Senate reported a 
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vastly different bill (S.1630) at the end of 1989. See S. 1630, 

as reported (Dec. 20, 1989), 1990 CAA Legis. Hist. at 7906. As 

reported and eventually passed, S. 1630 did not contain the text 

in the House amendment (“or emitted from a source category which 

is regulated under section 112”) and instead contained the 

substitution of cross references (changing “section 

112(b)(1)(A)” to “section 112(b)”) as a “conforming” 

amendment.)”). See S. 1630, as reported, 101st Cong. § 305, 1990 

CAA Legis. Hist. at 8153; S. 1630, as passed, § 305 (Apr. 3, 

1990), 1990 CAA Legis. Hist. at 4534. Though the EPA is not 

aware of any statements in the legislative history that 

expressly explain the Senate’s intent in making these changes to 

the Senate bill, the sequence itself supports the conclusion 

that the Senate’s substitution reflects a decision to retain the 

pre-1990 approach of using a cross-reference to 112(b) to define 

the scope of the Section 112 Exclusion. Whether the difference 

in approach between the final Senate amendment in S.1630 and the 

House amendment in H.R. 3030 creates a substantive difference or 

are simply two different means of achieving the same end depends 

on what interpretation one gives to the text in the House 

amendment, which we turn to next. 

4. The House Amendmentamendment
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a. The House Amendment is Ambiguous. StatutoryThe House 

amendment is ambiguous. Before looking at the specific text of 

the House amendment, it is helpful to review some principles of 

statutory interpretation. First, statutory interpretation 

begins with the text, but does not end there. As the D.C. 

Circuit Court has explained, “[t]he literal language of a 

provision taken out of context cannot provide conclusive proof 

of congressional intent.” Bell Atlantic Telephone Cos. v. 

F.C.C., 131 F.3d 1044, 1047 (D.C. Cir. 1977). See King v. 

Burwell, 2015 U.S. LEXIS 4248, *19(“[O]ftentimes the ‘meaning—or 

ambiguity—of certain words or phrases may only become evident 

when placed in context.’ Brown & Williamson, 529 U. S., at 132, 

120 S. Ct. 1291, 146 L. Ed. 2d 121. So when deciding whether the 

language is plain, we must read the words ‘in their context and 

with a view to their place in the overall statutory scheme.’ 

Id., at 133, 120 S. Ct. 1291, 146 L. Ed. 2d 121 (internal 

quotation marks omitted). Our duty, after all, is ‘to construe 

statutes, not isolated provisions.’ Graham County Soil and Water 

Conservation Dist. v. RatherUnited States ex rel. Wilson, 559 U. 

S. 280, 290, 130 S. Ct. 1396, 176 L. Ed. 2d 225 (2010) (internal 

quotation marks omitted).”). In addition, statutes should not be 

given a “hyperliteral” reading that is contrary to established 

canons of statutory construction and common sense. See RadLAX 
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Gateway Hotel v. Amalgamated Bank, 132 S.Ct. 2065, 20, 2070-71 

(2012), 2070-71 (2012). 

Further, a proper reading of statutory text “must employ all the 

tools of statutory interpretation, including text, structure, 

purpose, and legislative history.” Loving v. I.R.S., 742 F.3d 

1013, 1016 (D.C. Cir. 2014) (internal quotation omitted). See, 

also, Robinson v. Shell Oil Co., 519 U.S. 337, 341 (1997) 

(statutory interpretation involves consideration of “the 

language itself, the specific context in which that language is 

used, and the broader context of the statute as a whole.”). 

Moreover, one principle of statutory construction that has 

particular application here is that provisions in a statute 

should be read to be consistent, rather than conflicting, if 

possible. This principle was discussed in the recent case of 

Scialabba v. Cuellar De Osorio, 134 S. Ct. 2191, 2214 

(concurring opinion by Chief Justice Roberts and Justice 

Scalia), 2219-2220 (dissent by Justices Sotomayor, Breyer and 

Thomas)(2014). As Justice Sotomayor wrote (at 134 S. Ct. at 

2220): 

“We do not lightly presume that Congress has legislated in selfcontradicting terms. See A. Scalia & B. Garner, Reading Law: The 

Interpretation of Legal Texts 180 (2012) (“The provisions of a 

text should be interpreted in a way that renders them 

compatible, not contradictory. . . . [T]here can be no 

justification for needlessly rendering provisions in conflict if 

they can be interpreted harmoniously”). ***. . . Thus, time and 
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again we have stressed our duty to “fit, if possible, all parts 

[of a statute] into [a] harmonious whole.” FTC v. Mandel 

Brothers, Inc., 359 U.S. 385, 389, 79 S. Ct. 818, 3 L. Ed. 2d 

893 (1959); see also Morton v. Mancari, 417 U.S. 535, 551, 94 S. 

Ct. 2474, 41 L. Ed. 2d 290 (1974) (when two provisions “are 

capable of co-existence, it is the duty of the courts . . . to 

regard each as effective”). In reviewing an agency’s 

construction of a statute, courts “must,” we have emphasized, 

“interpret the statute ‘as a . . . coherent regulatory scheme’” 

rather than an internally inconsistent muddle, at war with 

itself and defective from the day it was written. Brown & 

Williamson, 529 U.S., at 133, 120 S. Ct. 1291, 146 L. Ed. 2d 

121.”.

As amended by the House, CAA section 111(d)(1)(A)(i) limits 

CAA section 111(d) to any air pollutant “for which air quality 

criteria have not been issued or which is not included on a list 

published under section 7408(a) of this title or emitted from a 

source category which is regulated under section 7412 of this 

title . . .” This statutory text is ambiguous and subject to 

numerous possible readings. Two possible readings are based on 

its literal text, but neither of those readings is reasonable 

and no one has advocated that either of those readings be 

adopted. Further, there are additional interpretations that 

arise from different readings of the ambiguous phrases and 

structure created by the House amendment. As discussed below, 

two of these additional interpretations are unreasonable, while 

three are reasonable. 

 First, the literal text of the House-amended version of CAA 

section 111(d) could be read literally as authorizing the 
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regulation of any pollutant that is not a criteria pollutant. 

This interpretation becomes apparentreading arises if one 

focuses on the use of “or” to join the three clauses: 

The Administrator shall prescribe regulations . . . under 

which each State shall submit to the Administrator a plan 

which establishes standards of performance for any existing 

source for any air pollutant [1] for which air quality 

criteria have not been issued or [2] which is not included 

on a list published under section 7408(a) of this title or

[3] emitted from a source category which is regulated under 

section 7412 of this title . . . . 

42 U.S.C. § 7411(d)(1) (emphasis and internal numbering added). 

Because the text contains the conjunction “or” rather than “and” 

between the three clauses, a literal reading could read the 

three clauses as alternatives, rather than requirements to be 

imposed simultaneously. In other words, onea literal reading of 

the literal language of section 111(d) provides that the 

Administrator may require states to establish standards for an 

air pollutant so long as either air quality criteria have not 

been established for that pollutant, or one of the remaining 

criteria is met. If this reading were applied to determine 

whether the EPA may regulate CO2promulgate section 111(d) 

regulations for CO2 from power plants under section 111(d),, the 

analysisresult would be (a)that CO2 from power plants coule be 

regulated under section 111(b) because air quality criteria have 

not been issued for CO2, (b) and therefore whether CO2 or power 
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plants are regulated under section 112 iswould be irrelevant, 

and (c) CO2 emissions from power plants may be regulated under 

section 111(d).. This interpretationreading, however, is not a 

reasonable reading of the statute because, among other reasons, 

it gives little or no meaning to the limitation covering 

hazardous air pollutants(HAP) that are regulated under CAA 

section 112 and thus is contrary to both the CAA’s comprehensive 

scheme created by the three sets of provisions (under which CAA 

section 111 is not intended to duplicate the regulation of 

pollutants regulated under section112) and the principle of 

statutory construction that text should not be construed such 

that a provision does not have effect. 

A second literal reading of CAA section 111(d) as revised 

by the House amendment arises fromfocuses on the lack of a 

negative before the third clause. That is, unlike the first and 

second clauses that each contain negative phrases (either “has 

not been issued” or “which is not included”), the third clause 

does not. One could presume that the negative from the second 

clause was intended to carry over, implicitly inserting another 

“which is not” before “emitted from a source category which is 

regulated under section [112].” But that is a presumption, and 

not the plain language of the statute. The text as amended by 

the House says that the EPA “shall” require standardsprescribe 
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regulations for “any air pollutant . . . emitted from a source 

category which is regulated under section [112].” 42 U.S.C. § 

7411(d)(1). Thus, CAA section 111(d)(1)(A)(i) could be read 

literally as requiring EPA to regulate providing for the 

regulation of emissions of pollutants if they are emitted from a 

source category under section 111(d) if that source category is 

regulated under CAA section 112. IfLike the first reading 

discussed above, this reading were applied to the question of 

the EPA’s authority for this rule, the result would be that the 

EPA not only has the authority to regulate authorize the 

regulation of CO2 emissions from existing power plants, but 

became obligated to do so once power plants were regulated under 

CAA section 112. Again111(d). But, this interpretationsecond 

reading is not reasonable because it would not only call for the 

regulation under CAA section 111(d) of pollutants that were not 

regulated under CAA section 112, but would also provide for the 

regulation of a source’s HAP emissions under CAA section 111(d) 

when those same emissions were also subject to standards under 

CAA section 112. Thus, this reading would be contrary to the 

comprehensive scheme of the statute under which Congress’s 

intent that CAA section 111(d) regulation is intended to fill 

the gap between the other programs by covering pollutants that 
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the other programs do not, andbut not duplicate the regulation 

of pollutants that the other programs cover. 

Turning now to the interpretation of the ambiguous phrases 

and structure created by the House amendment, ifIf one does 

presume that the “which is not” phrase is intended to carry over 

to the third clause, then CAA section 111(d) regulation under 

the House amendment would be limited to “any air pollutant...which 

is not... emitted from a source category which is regulated under 

section [112].” Even with this presumption, however, the House 

amendment contains further ambiguities with respect to the 

phrases “a source category” and “regulated under section 112,” 

and how those phrases are used within the structure of the 

provision limiting what air pollutants may be regulated under 

CAA section 111(d). 

The phrase “regulated under section 112” is ambiguous, 

first, because the sentence structure in the text does not make 

clear what that phrase is intended to modify. Young v. 

Community Nutrition Inst., 476 U.S. 974, 980-81 (1986) (“As 

enemies of the dangling participle well know, the English 

language does not always force a writer to specify which of two 

possible objects is the one to which a modifying phrase 

relates.”) Second, asThe phrase “regulated under section 112” is 

ambiguous. As the Supreme Court has explained in the context of 
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other statutes using a variation of the word “regulate,” an 

agency must consider what is being regulated. See Rush 

Prudential HMO, Inc. v. Moran, 536 U.S. 355, 366 (2002) (It is 

necessary to “pars[e] . . . the ‘what’” of the term 

“regulates.”); UNUM Life Ins. Co. of Am. v. Ward, 526 U.S. 358, 

363 (1999) (the term “‘regulates insurance’ . . . requires 

interpretation, for [its] meaning is not plain.”). Here, one 

possible reading is that the phase modifies the words “a source 

category” without regard to what pollutants are regulated under 

section 112, which then presents the issue of what meaning to 

give to the phrase “a source category” and leads to a third and 

fourth interpretation of the House amendment..” 

In this context, a third interpretation of the Section 112 

Exclusions arises if one reads “a source category” to mean “any” 

source category. Under this third interpretation of the House 

amendment, CAA section 111(d) regulation is limited to air 

pollutants that are not emitted by any source category for which 

the EPA has issued standards for HAP under CAA section 112. But 

this interpretation would read CAA section 111(d) out of the 

statute. Given the extensive list of source categories regulated 

under CAA section 112 and the breadth of the pollutants emitted 

by those categories collectively, literally all air pollutants 

would be barred from CAA section 111(d) regulation under this 
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interpretation, because any given air pollutant is emitted by at 

least one source category for which the EPA has issued standards 

for HAP under the mandate of CAA section 112. Based on the 

principle that statutes should be interpreted such that all 

parts of it have meaning, see, e.g., Mountain States Tel. & 

TelUnder this reading, and assuming the phrase “a source 

category” is read to mean the particular source category, the 

House amendment would. v. Pueblo of Santa Anna, 472 U.S. 237, 

249 (1985), the EPA concludes this is not a reasonable 

interpretation of the House amendment. 

A fourth interpretation would read the words “a source 

category” to mean the particular source category, again without 

regard to the scope of pollutants that are regulated under CAA 

section 112, and interpret the House amendment to preclude the 

regulation under CAA section 111(d) of a specific source 

category for any pollutant if that source category has been 

regulated for any HAP under CAA section 112.356 The effect of 

 

356 “A source category” could also be interpreted to mean “any 

source category.” Under this interpretation, CAA 111(d) 

regulation would be limited to air pollutants that are not 

emitted by any source category for which the EPA has issued 

standards for HAP under CAA section 112. This interpretation is 

not reasonable because it would effectively read CAA 111(d) out 

of the statute. Given the extensive list of source categories 

regulated under CAA 112 and the breadth of pollutants emitted by 

those categories collectively, literally all air pollutants 
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this reading would be to preclude the regulation of CO2 from 

power plants under CAA section 111(d) because power plants have 

been regulated for hazardous air pollutants(HAP) under CAA 

section 112. This is the interpretation that the EPA applied to 

the House amendment in connection with the CAMR rule in 2005, 

when looking at the question of whether HAP can be regulated 

under CAA section 111(d) for a source category that is not 

regulated for HAP under section 112, and some commentors have 

advocated for this interpretation here. But, after considering 

all of the comments and reconsidering this interpretation, the 

EPA has concluded that this interpretation of the Section 112 

Exclusion as amended by just the House amendment is not a 

reasonable reading because it would disrupt the comprehensive 

scheme for regulating existing sources created by the three sets 

of provisions covering criteria pollutants, hazardous air 

pollutants(HAP) and the other pollutants that fall outside of 

those two programs.357 and frustrate the role that section 111 

 

would be barred from CAA 111(d) regulation under this 

interpretation. 

357 In assessing any interpretation of section 111(d), EPA must 

consider how the three main programs set forth in the CAA work 

together. See UARG, 134 S. Ct. at 2442 (a “reasonable statutory 

interpretation must account for . . . the broader context of the 

statute as a whole”) (quotation omitted). 
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is intended to play.358 Specifically, under this fourth 

interpretation, the EPA could not both (a) regulate a source 

category’s emissions of hazardous air pollutantsHAP under CAA 

section 112, and (b) regulate that category’sthen promulgate 

regulations for other pollutants from that source category under 

CAA section 111(d).359 There is no reason to conclude that the 

House amendment was intended to abandon the existing structure 

and relationship between the three programs in this way. 

Indeed, Congress expressly provided that regulation under CAA 

section 112 was not to “diminish or replace the requirements of” 

the EPA’s regulation of non-hazardous pollutants under section 

7411. See 42 U.S.C. § 7412(d)(7). Further, consistent with CAA 

section 112’s direction that EPA list “all categories and 

 

358 In assessing any interpretation of section 111(d), EPA must 

consider how the three main programs set forth in the CAA work 

together. See UARG, 134 S. Ct. at 2442 (a “reasonable statutory 

interpretation must account for . . . the broader context of the 

statute as a whole”) (quotation omitted). 

359 Supporters of this interpretation have noted that the EPA 

could regulate power plants under both CAA section 111(d) and 

CAA section 112 if it regulated under section 111(d) first, 

before the Section 112 Exclusion is triggered. But that argument 

actually further demonstrates another reason why this 

interpretation is unreasonable. There is no basis for concluding 

that Congress intended to mandate that section 111(d) regulation 

occur first, nor is there any logical reason why the need to 

regulate under section 111(d) should be dependent on the timing 

of such regulation in relation to CAA 112 regulation of that 

source category.
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subcategories of major sources and area [aka, non-major] 

sources” of HAP and then establish CAA section 112 standards for 

those categories and subcategories, 42 U.S.C. §§ 7412(c)(1) and 

(c)(2), the EPA has listed and regulated over 140 categories of 

sources under CAA section 112. Thus, similar to the third 

reading above, this reading would prevent eviscerate the EPA’s 

authority under section 111(d) and prevent it from serving as 

the gap-filling provision within the comprehensive scheme of the 

CAA. For these reasons, and as further discussed [below/in the 

Response to Comments],Congress intended.360 In short, it is not 

 

360 Some commenters have stated that EPA could choose to regulate 

both HAP and non-HAP under section 111(d), and thus could 

regulate HAP without creating a gap. But this presumes that 

Congress intended EPA to have the choice of declining to 

regulate a section 112-listed source category for HAP under 

section 112, which is inconsistent with the mandatory language 

in section 112. See, e.g., section 112(d)(1)(“The Administrator 

shall promulgate regulations establishing emissions standards 

for each category or subcategory of major sources and area 

sources of hazardous air pollutants listed for regulation 

pursuant to subsection (c) of this section in accordance with 

the schedules provided in subsections (c) and (e) of this 

section.”). Moreover, given the prescriptive language that 

Congress added into section 112 concerning how to set standards 

for HAP, see section 112(d)(2) and (d)(3), it is unreasonable to 

conclude that Congress intended that the EPA could simply choose 

to ignore the provisions in section 112 and instead regulate HAP 

for a section 112 listed source category under section 111(d). 

Further, some supporters of this interpretation have 

suggested that EPA could regulate CO2 under section 112. But this 

suggestion fails to consider that sources emitting HAP are major 

sources if they emit 10 tons of any HAP. See CAA section 

112(a)(1). Thus, if CO2 were regulated as a HAP, and because 
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reasonable to interpret the CAA sectionSection 112 

exclusionExclusion in section 111(d) to mean that the existence 

of CAA section 112 standards covering hazardous pollutants from 

a source category would entirely eliminate regulation of nonhazardous emissions from that source category under section 

111(d).361

 

emissions of CO2 tend to be many times greater than emissions of 

other pollutants, a huge number of smaller sources would become 

regulated for the first time under the CAA. 

361 Some commenters have stated that EPA could chose to regulate 

both HAP and non-HAP under section 111(d), and thus could 

regulate HAP without creating a gap. But this presumes that 

Congress intended EPA to have the choice of declining to 

regulate a section 112-listed source category for HAP under 

section 112, which is inconsistent with the mandatory language 

in section 112. See, e.g., section 112(d)(1)(“The Administrator 

shall promulgate regulations establishing emissions standards 

for each category or subcategory of major sources and area 

sources of hazardous air pollutants listed for regulation 

pursuant to subsection (c) of this section in accordance with 

the schedules provided in subsections (c) and (e) of this 

section.”). Moreover, given the prescriptive language that 

Congress added into section 112 concerning how to set standards 

for HAP, see section 112(d)(2) and (d)(3), it is unreasonable 

to conclude that Congress intended that EPA could simply choose 

to ignore the provisions in section 112 and instead regulate HAP 

for a section 112 listed source category under section 111(d). 

Even if one were to determine that this interpretation were the 

proper reading of the House amendment that would not be the end 

of the analysis. Instead, that reading would create a conflict 

between the Senate amendment and the House amendment that would 

need to be resolved. In that event, the proper resolution of a 

conflict between the two amendments would be the analysis and 

conclusion discussed in the Proposed Rule’s legal memorandum 

(discussing EPA’s analysis in the CAMR rule at 70 FR 15994, 

16029-32): The two amendments must be read together so as to 

give some effect to each amendment and they are properly read 
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a. The EPA’s Interpretation of the House Amendment. Having 

concluded that the interpretations discussed above are not 

reasonable, the EPA now turns to what it has identified 

threeconcluded is the best, and sole reasonable interpretations, 

interpretation of the House amendment as it applies to the issue 

here. 

First, one could interpret The EPA’s interpretation of the 

House amendment as applied to meanthe issue presented in this 

rule is that the Section 112 Exclusion excludes the regulation 

of HAP under CAA section 112 if the source category at issue is 

regulated under CAA section 112, but does not exclude the 

regulation of other pollutants, regardless of whether that 

source category is subject to CAA section 112 standards. This 

interpretation reads the phrase “regulated under section 112” as 

modifying the words “source category” (as does the fourth 

interpretation discussed above) but also recognizes that the 

phrase “regulated under section 112” refers only to the 

regulation of HAP emissions. In other words, thisthe EPA’s

interpretation recognizes that source categories “regulated 

under section 112” are not regulated by CAA section 112 with 

 

together to provide that, where a source category is regulated 

under section 112, the EPA may not establish regulations 

covering the HAP emissions from that source category under 

section 111(d).
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respect to all pollutants, but only with respect to HAP. Thus, 

it is reasonable to interpret the House amendment of the Section 

112 Exclusion as only excluding the regulation of HAP emissions 

under CAA section 111(d) and only when that source category is 

regulated under CAA section 112. We note that this first 

reasonable interpretation of the House amendment alone is the 

same as the 2005 CAMR interpretation of the two amendments 

combined: where a source category has been regulated under CAA 

section 112, a CAA section 111(d) standard of performance cannot 

be established to address any HAP listed under CAA section 

112(b) that may be emitted from that particular source category. 

See 70 FR 15994, 16029-30 (March 29, 2005). 

Second, one could interpret the House amendment to mean 

that the Section 112 Exclusion always excludes the regulation of 

CAA section 112 pollutants, but does not exclude other 

pollutants, and the scope of the exclusion is the same 

regardless of whether the source category is subject to 

standards under CAA section 112. This interpretation of the 

House amendment reads the phrase “regulated under section 112” 

as modifying “air pollutant” rather than “source category” and 

reads the phrase “emitted by a source category” as having 

minimal import because it is the remnant of phrasing that was 

originally intended to be an exclusion within CAA section 112 
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for source categories regulated under section 111.362 A key 

distinction between this second reasonable interpretation and 

the first reasonable interpretation discussed above is that this 

second reasonable interpretation concludes that HAP can never be 

regulated under CAA section 111(d). 

 

362 Originally, when the House bill to amend the CAA was 

introduced in January 1989, it focused on amendments to control 

HAP. Of particular note, the amendments to CAA section 112 

included a provision that excluded regulation under section 112 

of “[a]ny air pollutant which is included on the list under 

section 108(a), or which is regulated for a source category 

under CAA section 111(d).” H.R. 4, § 2 (Jan. 3, 1989), 1990 CAA 

Legist. Hist. at 4046. In other words, the Section 112 Exclusion 

in CAA section 111(d) that was ultimately contained in the House 

amendment was originally crafted as what might be called a 

“Section 111(d) Exclusion” in CAA section 112. This is 

significant because the “source category” phrasing in the 

original January 1989 text with respect to CAA section 111(d) 

makes sense, whereas the “source category” phrasing in the 1990 

House amendment does not. When referring to the scope of what is 

regulated under section 111(d), it makes sense to frame that 

scope with respect to source categories, because CAA section 111 

regulation begins with the identification of source categories 

under CAA section 111(b)(1)(A). By contrast, regulation under CAA

section 112 begins with the identification of HAP under CAA 

section 112(b); the listing of source categories under section 

112(c) is secondary to the listing of HAP. From this history, 

and in light of this difference between the scope of what is 

regulated in CAA sections 111 and 112, it is reasonable to 

conclude that the “source category” phrasing is a legacy from 

the original 1989 bill—that is, when converting the 1989 text 

into the Section 112 Exclusion that we see in the 1990 House 

amendment, the legislative drafters continued to use phrasing 

based on “source category” notwithstanding that this phrasing 

created a mismatch with the way that the scope of CAA section 

112 regulation is determined. 
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Third, one could interpret the House amendment to mean that 

the Section 112 Exclusion excludes all of the CAA section 112 

pollutants that have actually been regulated for at least one 

source category under CAA section 112, but does not exclude 

other pollutants (that is, pollutants that are not listed under 

CAA section 112). This third reasonable interpretation reads the 

phrase “a source category” as meaning “any” source category 

listed under section 112 and the phrase “regulated under section 

112” in light of the fact that a source category is “regulated 

under 112” with respect to HAP and not other pollutants. Thus, 

under this third reasonable interpretation of the House 

amendment, the scope of the Section 112 Exclusion does not cover 

non-HAP. 

These three interpretations share a number of common 

reasons why they are reasonable and avoid the issues discussed 

above. 

There are a number of reasons why the EPA’s interpretation 

is reasonable and avoids the issues discussed above. 

First, all three of these reasonable interpretations 

readthe EPA’s interpretation reads the House amendment to the 

Section 112 Exclusion as determining the scope of what air 

pollutants are to be regulated under CAA section 111(d), as 

opposed to creating a wholesale exclusion for source 
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categories. The other text in subsections 111(d)(1)(A)(i) and 

(ii) modify the phrase “any air pollutant.” Thus, reading the 

Section 112 Exclusion to do also address the question of what 

air pollutants may be regulated under CAA section 111(d) is 

consistent with the overall nature of the text in which it 

appears.structure and focus of CAA section 111(d)(1)(A). 

Second, all three reasonable interpretations furtherthe 

EPA’s interpretation furthers – rather than undermineundermines

– the purpose of CAA section 111(d) within the long-standing 

structure of the CAA. That is, these interpretations 

supportthis interpretation supports the comprehensive structure 

for regulating various pollutants from existing sources under 

the criteria pollutant/NAAQS program under sections 108-110, the 

HAP program under section 112, and other pollutants under 

section 111(d), and avoids creating a gap in that structure. See 

King v. Burwell, 2015 U.S. LEXIS 4248, *28 (2015)(“A provision 

that may seem ambiguous in isolation is often clarified by the 

remainder of the statutory scheme . . . because only one of the 

permissible meanings produces a substantive effect that is 

compatible with the rest of the law.”) (quoting United Sav. 

Assn. of Tex. v. Timbers of Inwood Forest Associates, Ltd., 484 

U. S. 365, 371, 108 S. Ct. 626, 98 L. Ed. 2d 740 (1988)”) 
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Third, by avoiding the creation of gaps in the statutory 

structure, all three interpretations arethe EPA’s interpretation 

is consistent with the legislative history demonstrating that 

Congress’s intent in the 1990 CAA Amendments was to expand the 

EPA’s regulatory authority across the board, compelling the 

agency to regulate more pollutants, under more programs, more 

quickly.363 Conversely, the the EPA is aware of no statement in 

the legislative history indicating that Congress simultaneously 

sought to restrict the EPA’s authority under CAA section 111(d) 

or to create gaps in the comprehensive structure of the statute. 

If Congress had intended this amendment to make such a change, 

one would expect to see some indication of that in the 

legislative history. 

 

363 See S. Rep. No. 101-228 at 133 (“There is now a broad 

consensus that the program to regulate hazardous air pollutants 

. . . should be restructured to provide the EPA with authority 

to regulate industrial and area sources of air pollution . . . 

in the near term”), reprinted in 5 A Legislative History of the 

Clean Air Act Amendments of 1990 (“Legis. Hist.”) 8338, 8473 

(Comm. Print 1993); S. Rep. No. 101-228 at 14 (“The bill gives 

significant authority to the Administrator in order to overcome 

the deficiencies in [the NAAQS program]”) & 123 (“Experience 

with the mobile source provisions in Title II of the Act has 

shown that the enforcement authorities . . . need to be 

strengthened and broadened . . .”), reprinted in 5 Legis. Hist. 

at 8354, 8463; H.R. Rep. No. 101-952 at 336-36, 340, 345 & 347 

(discussing enhancements to Act’s motor vehicle provisions, the 

EPA’s new authority to promulgate chemical accident prevention 

regulations, the enactment of the Title V permit program, and 

enhancements to the EPA’s enforcement authority), reprinted in 5 

Legis. Hist. at 1786, 1790, 1795, & 1997. 
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Fourth, when applied in the context of this rule, all three 

of these reasonable interpretationsthe EPA’s interpretation of 

the House amendment areis consistent with the Senate amendment. 

Thus, these interpretations in this context avoidinterpretation 

avoids creating a conflict within the statute and fulfill that 

principle of statutory construction. See discussion above of 

Scialabba, 134 S. Ct. 2191 at 2220 (citing and quoting, among 

other authorities, A. Scalia & B. Garner, Reading Law: The 

Interpretation of Legal Texts 180 (2012) (“The provisions of a 

text should be interpreted in a way that renders them 

compatible, not contradictory. . . . [T]here can be no 

justification for needlessly rendering provisions in conflict if 

they can be interpreted harmoniously”)). 

In sum, when either of these three reasonable 

interpretations this interpretation of the House amendment is 

applied in the context of this rule, each interpretation reaches 

the samethe result: is that the EPA may promulgate CAA section 

111(d) regulations covering carbon dioxide emissions from 

existing power plants notwithstanding that power plants are 

regulated for their HAP emissions under CAA section 112. Thus, 

in the context of this rule, the EPA does not need to decide 

which of these three reasonable interpretations is better.
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5. The Two Amendments Are Easily Reconciled And Can Be Given Full 

Effect 

 Given that both the House and Senate amendments should be 

read individually as having the same meaning in the context 

presented in this rule, giving each amendment full effect is 

straight-forward: the Section 112 Exclusion in section 111(d) 

allowsdoes not foreclose the EPA to regulateregulation of nonHAP from a source category regardless of whether that source 

category is also regulated under CAA section 112. ThusAs applied 

here, the EPA has the authority to regulatepromulgate CAA 

section 111(d) regulations for CO2 from power plants 

notwithstanding that power plants are regulated for HAP under 

CAA section 112. 

C. Authority to Regulate EGUs 

In a separate, concurrent action, the EPA is also 

finalizing twoa CAA section 111(b) rulemakings, onerulemaking

that regulates CO2 emissions from new EGUs and another that 

regulates CO2 emissions from, modified, and reconstructed EGUs. 

The promulgation of either of these isstandards provides the 

requisite predicate for applicability of CAA section 111(d). 

 CAA section 111(d)(1) requires the EPA to promulgate 

regulations under which states must submit state plans 

regulating “any existing source” of certain pollutants “to which 
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a standard of performance would apply if such existing source 

were a new source.” A “new source” is “any stationary source, 

the construction or modification of which is commenced after the 

publication of regulations (or, if earlier, proposed 

regulations) prescribing a standard of performance under [CAA 

section 111] which will be applicable to such source.” It should 

be noted that these provisions make clear that a “new source” 

includes one that undertakes either new construction or a 

modification. It should also be noted that the EPA’s 

implementing regulations define “construction” to include 

“reconstruction,” which the implementing regulations go on to 

define as the replacement of components of an existing facility 

to an extent that (i) the fixed capital cost of the new 

components exceeds 50 percent of the fixed capital cost that 

would be required to construct a comparable entirely new 

facility, and (ii) it is technologically and economically 

feasible to meet the applicable standards. 

 Under CAA section 111(d)(1), in order for existing sources 

to become subject to that provision, the EPA must promulgate 

standards of performance under CAA section 111(b) to which, if 

the existing sources were new sources, they would be subject. 

Those standards of performance may include standards for sources 
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that undertake new construction, modifications, or 

reconstructions. 

The EPA is finalizing two rulemakingsa rulemaking under CAA 

section 111(b) for CO2 emissions from affected EGUs concurrently 

with this CAA section 111(d) rulemaking, which will provide the 

requisite predicate for applicability of CAA section 111(d).364

D. Definition of Affected Sources 

For the emission guidelines, an affected EGU is any fossil 

fuel-fired electric utility steam generating unit, (i.e., 

utility boiler or integrated gasification combined cycle (IGCC,) 

unit) or stationary combustion turbine that was in operation or 

had commenced construction as of January 8, 2014,365 and that 

meets the following criteria, which differ depending on the type 

of unit. To be an affected sourceEGU, such a unit, if it is a 

fossil fuel-fired electric utility steam generating unit (i.e., 

a utility boiler or IGCC, unit), must serve a generator capable 

 

364 In the past, the EPA has issued standards of performance under 

section 111(b) and emission guidelines under section 111(d) 

simultaneously. See “Standards of Performance for new Stationary 

Sources and Guidelines for Control of Existing Sources: 

Municipal Solid Waste Landfills – Final Rule,” 61 Fed. Reg.FR

9905 (March 12, 1996). 

365 Under Section 111(a) of the CAA, determination of affected 

sources is based on the date that the EPA proposes action on 

such sources. January 8, 2014 is the date the proposed GHG 

standards of performance for new fossil fuel-fired EGUs were 

published in the Federal Register (79 FR 1430).
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of selling greater than 25 MW to a utility power distribution 

system and have a base load rating greater than 260 GJ/h (250 

MMBtu/h) heat input of fossil fuel (either alone or in 

combination with any other fuel). If such a unit is a stationary 

combustion turbine, the unit must meet the definition of a 

combined cycle or combined heat and power combustion turbine, 

serve a generator capable of selling greater than 25 MW to a 

utility power distribution system, and have a base load rating 

of greater than 260 GJ/h (250 MMBtu/h). 

When considering and understanding applicability, the 

following definitions may be helpful. Simple cycle combustion 

turbine means any stationary combustion turbine which does not 

recover heat from the combustion turbine engine exhaust gases 

for purposes other than enhancing the performance of the 

stationary combustion turbine itself. Combined cycle combustion 

turbine means any stationary combustion turbine which recovers 

heat from the combustion turbine engine exhaust gases to 

generate steam that is used to create additional electric power 

output in a steam turbine. Combined heat and power (CHP) 

combustion turbine means any stationary combustion turbine which 

recovers heat from the combustion turbine engine exhaust gases 

to heat water or another medium, generate steam for useful 

purposes other than exclusively for additional electric 
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generation, or directly uses the heat in the exhaust gases for a 

useful purpose.

We note that certain affected EGUs are exempt from 

inclusion in a state plan. Affected EGUs that may be excluded 

from a state’s plan are (1) those units that (1) are subject to 

subpart TTTT as a result of commencing modification or 

reconstruction; (2) steam generating units or IGCC units that 

are currently and always have been subject to a federally 

enforceable permit limiting net-electric sales to one-third or 

less of its potential electric output or 219,000 MWh or less on 

an annual basis; (3) non-fossil units (i.e., units that are 

capable of combusting 50 percent or more non-fossil fuel) that 

have historically limited the use of fossil fuels to 10 percent 

or less of the annual capacity factor or are subject to a 

federally enforceable permit limiting fossil fuel use to 10 

percent or less of the annual capacity factor; (4) stationary 

combustion turbines that are not capable of combusting natural 

gas (i.e., not connected to a natural gas pipeline); (5) are a 

combined heat and power unitunits that are subject to a 

federally enforceable permit limiting, or have historically 

limited, annual net electric sales to a utility power 

distribution system to the product of the design efficiency and 

the potential electric output or 219,000 MWh (whichever is 
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greater) or less; (6) units that serve a generator along with 

other steam generating unit(s), IGCC(s), or stationary 

combustion turbine(s) where the effective generation capacity 

(determined based on a prorated output of the base load rating 

of each steam generating unit, IGCC, or stationary combustion 

turbine) is 25 MW or less; (7) are a municipal waste combustor 

unit subject to subpart Eb of Part 60; or (8) are a commercial 

or industrial solid waste incineration unitunits that isare

subject to subpart CCCC of Part 60.

The rationale for applicability of this final rule is 

multi-fold. We had proposed that affected EGUs were those 

existing source fossil fuel-fired EGUs that met the 

applicability criteria for coverage under the final GHG 

standards for new fossil fuel-fired EGUs being promulgated under 

section 111(b). However, we are finalizing that States need not 

include certain units that would otherwise meet the CAA section 

111(b) applicability in this CAA section 111(d) emission 

guidelines. These include simple cycle turbines, certain nonfossil units, and certain combined heat and power units. The 

final 111(b) standards include applicability criteria for simple 

cycle combustion turbines, for reasons relating to 

implementation and minimizing emissions from all future 

combustion turbines. However, for the following reasons none of 
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the building blocks would apply toresult in emission reductions 

from simple cycle turbines so we are not requiring that States 

including them in their CAA section 111(d) plans. 

First, even more than combined cycle units, simple cycle 

units have limited opportunities, compared to steam generating 

units, to reduce their heat rate. Further, we have not evaluated 

any opportunities that existing simple cycle have to reduce 

their heat rate. Therefore, nothing would be required of simple 

cycle units under building block 1. Most combustion turbines 

likely already follow the manufacturer’s recommended regular 

preventive/restorative maintenance for both reliable and 

efficiency reasons. These regularly scheduled maintenance 

practices are highly effective methods to maintain heat rates, 

and additional fleet-wide reductions from simple cycle 

combustion turbines are likely less than 2 percent. In addition, 

while approximately one-fifth of overall fossil fuel-fired 

capacity (GW) consists of simple cycle turbines, these units 

historically have operated at capacity factors of less than 5 

percent and only provide about 1 percent of the fossil fuelfired generation (GWh). Combustion turbine capacity can 

therefore only contribute CO2 emissions amounting to 

approximately 2 percent of total coal-steam CO2 emissions. Any 

single-digit percentage reduction in combustion turbine heat 
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rates would therefore provide less than 1 percent reduction in 

total fossil-fired CO2 emissions. 

Further, we are not aware of an approach to estimate any 

limited opportunities that existing simple cycle turbines may 

have to reduce their heat rate. Similar to coal-steam EGUs, we 

do not have the unit-specific detailed design information on 

existing individual simple cycle combustion turbines that is 

necessary for a detailed assessment of the heat rate improvement 

potential via best practices and upgrades for each unit. While 

the EPA could conduct a “variability analysis” of simple cycle 

historical hourly heat rate data (as was done for coal-steam 

EGUs), the various simple cycle models in use and the 

historically lower capacity factors of the simple cycle fleet 

(less run time per start, and more part load operation) would 

require a simple cycle analysis that includes more complexity 

and likely more uncertainty than in the coal-steam analysis. 

Therefore, we do not consider it feasible to estimate potential 

reductions due to heat rate improvements from simple cycle 

turbines, and even if it were, we have concluded those 

reductions would be negligible compared to the reductions from 

steam generating units. Hence, we do not consider building block 

1 as practically applicable to simple cycle units. 
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Second, the vast majority of simple cycle turbines serve a 

specific need – providing power during periods of peak electric 

demand (i.e., peaking units). The existing block of simple cycle 

turbines are the only units that are able to start fast enough 

and ramp to full load quickly enough to serve as peaking units. 

If these units were to be used under building block 2 to 

displace higher emitting coal-fired units, they would no longer 

be available to serve as peaking units. Therefore, building 

block 2 wouldcould not applybe applied to simple cycle units. 

combustion turbines without jeopardizing grid reliability. 

Third, many commenters on the CAA section 111(b) proposal 

stated that simple cycle turbines will be used to provide backup 

power to intermittent renewable sources of power such as wind 

and solar. Consequently, adding additional generation from 

intermittent renewable sources has the potential to actually 

increase emissions from simple cycle turbines. Therefore, 

applying building block 3 based on the capacity of simple cycle 

turbines would not apply toresult in emission reductions from

simple cycle combustion turbines. Finally, the EPA expects 

existing simple cycle turbines to continue to operate as they 

historically have operated, as peaking units. Including simple 

cycle turbines in CAA section 111(d) applicability would impact 

the numerical value of state goals, but it would not impact the 
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stringency of the plans. Such inclusion would increase burden 

but result in no environmental benefit. 

FinallyAdditionally, under CAA section 111(b) final 

applicability criteria, new dedicated non-fossil and industrial 

CHP units are not affected sources if they include permit 

restrictions on the amount of fossil fuel they burn and the 

amount of electricity they sell. Such units historically have 

had no regulatory mandate to include permit requirements 

limiting the use of fossil fuel or electric sales. We are 

exempting them from inclusion in CAA section 111(d) state plans 

in the interest of consistency with CAA section 111(b) and based 

on their historical fuel use and electric sales. 

We discuss changes in applicability of units in relation to 

state plans in Section VIII of this preamble. 

E. Combined Categories and Codification in the Code of Federal 

Regulations 

In this rulemaking, the EPA is combining the listing of 

sources from the two existing source categories for the affected 

EGUs, as listed in 40 CFR subpart Da and 40 CFR subpart KKKK,

into a single categorylocation, 40 CFR subpart UUUU, for 

purposes of addressing the CO2 emissions from existing affected 

EGUs. The EPA is also codifying all of the requirements for the 

affected EGUs in a new subpart UUUU of 40 CFR part 60 and 
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including all GHG emission guidelines for the affected sources – 

fossil fuel–fired electric utility steam generating units, as 

well as natural gas-fired stationary combustion turbines -- in 

that newly created subpart.366

We believe that combining the emission guidelines for 

affected sources into a new subpart UUUU is appropriate because 

the emission guidelines the EPA is establishing do not vary by 

type of source. Combining the two categorieslisting of sources 

into one location, subpart UUUU, will facilitate implementation 

of CO2 mitigation measures, such as shifting generation from 

higher to lower-carbon intensity generation among existing 

sources (e.g., shifting from utility boilers to NGCC units), and 

emission trading among sources in both categoriesthe source 

category. 

As discussed in the January 8, 2014 proposal for the CAA 

section 111(b) standards for GHG emissions from EGUs (79 FR 

1430), in 1971 the EPA listed fossil fuel-fired steam generating 

boilers as a new category subject to section 111 rulemaking, and 

in 1979 the EPA listed fossil fuel-fired combustion turbines as 

a new category subject to the CAA section 111 rulemaking. In the 

ensuing years, the EPA has promulgated standards of performance 

 

366 The EPA is not codifying any of the requirements of this 

rulemaking in subparts Da or KKKK. 
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for the two categories and codified those standards, at various 

times, in 40 CFR part 60 subparts D, Da, GG, and KKKK. 

In the January 8, 2014 proposal, the EPA proposed separate 

standards of performance for new sources in the two categories 

and proposed codifying the standards in the same Da and KKKK 

subparts that currently contain the standards of performance for 

conventional pollutants from those sources. In addition, the EPA 

co-proposed combining the two categories into a single category 

solely for purposes of the CO2 emissions from new construction of 

affected EGUs, and codifying the proposed requirements in a new 

40 CFR part 60 subpart TTTT. For the final standards of 

performance for new construction of affected EGUs, the EPA is 

codifying the final requirements in a new 40 CFR part 60 subpart 

TTTT. 

In this rulemaking, the EPA is combining the two listed source 

categories into a single source category for purposes of the 

emission guidelines for the CO2 emissions from existing affected 

EGUs. Because the two source categories are pre-existing and the 

EPA would not be subjecting any additional sources to 

regulation, the combined source category is not considered a new 

source category that the EPA must list under CAA section 

111(b)(1)(A). As a result, this final rule does not list a new 

source category under section 111(a)(1)(A), nor does this final 
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rule revise either of the two source categories – steam-fossil 

fuel–fired electric utility steam generating boilersunits and

stationary combustion turbines – that the EPA has already listed 

under that provision. Thus, the EPA is not required to make a 

finding that the combined source category causes or contributes 

significantly to air pollution which may reasonably be 

anticipated to endanger public health or welfare. 

V. The Best System of Emission Reduction and Associated Building 

Blocks 

 In the June 2014 proposal, the EPA proposed to determine 

that the best system of emission reduction adequately 

demonstrated (BSER) for reducing CO2 emissions from existing EGUs 

was a combination of measures –- (1) increasing the operational 

efficiency of existing coal-fired steam EGUs, (2) substituting 

increased generation at existing NGCC units for generation at 

existing steam EGUs, (3) substituting generation from low- and 

zero-carbon generating capacity for generation at existing 

fossil fuel-fired EGUs, and (4) increasing demand-side energy 

efficiency to reduce the amount of fossil fuel-fired generation 

–- which we categorized as four “building blocks.” As an 

alternative to the proposed building blocks 2, 3, and 4, the EPA 

also identified reduced generation in the amount of those 

building blocks as part of the BSER. These measures are not the 
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only approaches EGUs can take to reduce CO2, but are those that 

the EPA felt best met the statutory criteria. We solicited 

comment on all aspects of our BSER determination, including a 

broad array of other approaches. We have considered thoroughly 

the extensive comments submitted on a variety of topics related 

to the BSER and the individual building blocks, along with our 

own continued analysis, and we are finalizing the BSER based on 

the first three building blocks, with certain refinements. 

 Consistent with the approach taken in the proposed rule, in 

determining the BSER we have taken account of the global 

natureunique characteristics of CO2 pollution, particularly its 

global nature, huge quantities, and the limited means for 

controlling it; and the unique characteristics of the source 

category, particularly the exceptional degree of 

interconnectedness among individual affected sourcesEGUs and the 

longstanding practice of coordinating planning and operations 

across multiple sources, reflecting the fact that each EGU’s 

function is interdependent with the function of other EGUs. Each 

building block is a proven approach for reducing emissions from 

the affected source category that is appropriate in this 

pollutant- and industry-specific context. Each building blockThe 

BSER also encompasses a variety of measures or actions that 

individual affected sources mayEGUs could take to implement the 
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building blocks, including (i) direct investment in efficiency 

improvements and in lower- and zero-carbon generation, (ii) 

cross-investment in these activities through mechanisms such as 

emissions trading or other multi-unit complianceapproaches, 

where the state-established standards of performance to which 

sources are subject incorporate such approaches, and (iii)

reduction of higher-carbon generation. 

 With attention to emission reduction costs, electricity 

rates, and the importance of ensuring continued reliability of 

electricity supplies, the individual building blocks and the 

overall BSER have been defined not at the maximum possible 

degree of stringency but at a reasonable degree of stringency 

designed to appropriately balance consideration of the various 

BSER factors. Additional, non-building block -specific aspects 

of the BSER quantification methodology discussed below are 

similarly conservativemindful of these considerations. This 

approach to determination of the BSER provides compliance 

headroom that ensures that the emission limitations reflecting 

the BSER are achievable by the source category., but 

nevertheless, as required by the CAA, will result in meaningful 

reductions in CO2 emissions from this sector. The wide range of 

actions encompassed in the building blocks, and a further wide 

range of possible emissions-reducing actions not included in the 
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BSER but nevertheless available to help with compliance, ensure 

that the BSER isthose emission limitations are achievable by 

individual affected sourcesEGUs as well. 

 The final BSER reflectsincorporates certain changes from 

the proposed rule, reflecting the EPA’s consideration of 

comments receivedresponding to the approaches outlined in the 

proposal and our own further analysis. The principal changes are 

the exclusion from the BSER of emission reductions achievable 

through demand-side energy efficiency and through nuclear 

generation; a revised approach to determination of emission 

reductions achievable through increased renewable energyRE

generation, based on an alternate approach on which we solicited 

comment in the proposed rule; a consistent approach to 

determination of emission reductions achievable through all the 

building blocks that better reflects the regional nature of the 

electricity system and entails separate analyses for the 

Eastern, Western, and Texas Interconnections; and a revised 

interim goal period of 2022 to 2029 (instead of the proposed 

interim period of 2020 to 2029). These changes to the BSER and 

the building blocks are discussed in more detail later in this 

section of the preamble. 

 Also, to address concerns identified in the proposal and 

the October 30, 2014 Notice of Data Availability and in response 
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to associated comments, in the final rule we have represented 

the emission limitations achievable through the BSER in the form 

of uniform CO2 emission performance rates for each of two 

affected source subcategories: steam generating units and 

stationary combustion turbines. However, like the proposed rule, 

the final rule also provides weighted-average state-specific 

goals that a state may choose as an alternative tomethod for 

complying with its obligation to set standards of performance 

for its affected EGUs -– an alternative, that is, to adopting

the nationwide subcategory-based CO2 emission performance rates. 

as the standard of performance for its affected EGUs. The change 

toreformulation of the emission limitations as uniform CO2

emission performance rates is discussed in this section and in 

section VI of the preamble, and the relation of the performance 

rates to the state-specific goals and states’ section 111(d) 

plan options is discussed in sections VII and VIII of the 

preamble. 

 Section V.A. describes our determination of the final BSER, 

including a discussion of the associated emissions performance 

level, and provides the rationale for our determination. In 

section V.B. we address certain legal issues in greater detail, 

including key issues raised in comments. Sections V.C. through 

V.E. contain more detailed discussions of the three individual 
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building blocks included in the final BSER. Further information 

can be found in the Legal Memorandum for the CPP Final Rule, the 

GHG Mitigation Measures TSD for the CPP Final Rule, the CO2

Emission Performance Rate and Goal Computation TSD for the CPP 

Final Rule, the Rate-based Program Accounting TSD for the CPP 

Final Rule, and the Response to Comments document, and, about 

certain topics, the Legal Memorandum for the Clean Power Plan 

Final Rule, all of which are available in the docket. 

A. The Best System of Emission Reduction 

 This section sets forth our determination of the BSER for 

reducing CO2 emissions from existing EGUs, including a discussion 

of the associated emissions performance level, and the rationale 

for that determination. In section V.A.1., we describe the legal 

framework for determination of the BSER in general. Section 

V.A.2. summarizes the determination of the BSER for this rule. 

In section V.A.3., we discuss changes from the proposal. Section 

V.A.4. provides more detail on our determination of the BSER, 

including our determinations regarding the individual elements 

of the BSER, viewed from as applied to the perspectivetwo 

subcategories of the overall category of affected sources.fossil 

steam units and combustion turbines. In section V.A.5.., we 

discuss the BSER from a second perspective, comprising the range 

of explain the specific actions that individual affected 
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sourcesEGUs in the two subcategories may take to implement the 

building blocks and thereby achieve the EPA-identified source 

subcategory-specific emission performance levelsrates that

reflect the BSER and that, in turn, form the basis for the 

standards of performance that states must set. Because these 

actions implement the building blocks, they may be understood as 

part of the BSER. In this discussion, we recognize that states 

can choose to set sources’ standards of performance in different 

forms and that the form of the standard affects how various 

types of actions can be used to comply with the standard. In 

section V.A.6.., we discuss the substantial compliance 

flexibility provided by additional measures, not included in the 

BSER, that individual affected sourcesEGUs can use to achieve 

their standards of performance. Finally, section V.A.7. 

addresses the severability of the building blocks. 

1. Legal requirements for BSER in the emission guidelines 

a. Introduction. In the June 2014 proposal for this rule, we 

described the principal legal requirementrequirements for 

standards of performance under CAA section 111(d)(1) and (a)(1). 

We based our description in part on our discussion of the legal 

requirements for standards of performance under CAA section 

111(b) and (a)(1), which we included in the January 2014 

proposal for standards of performance for CO2 emissions from new 
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fossil fuel-fired EGUs. In the latter proposal, we noted that 

the D.C. Circuit has handed down numerous decisions that 

interpret CAA section 111(a)(1), including its component 

elements, and we reviewed that case law in detail.367

We received comments on our proposed interpretation, and in 

light of those comments, in this final rule, we are clarifying 

our interpretation in certain respects. We discuss our 

interpretation below.368 

b. CAA requirements and court interpretation.369 Section 

 

367 79 FR 1430, 1462 (January 8, 2014). 368

 We also discuss our interpretation of the requirements for 

standards of performance and the BSER under section 111(b), for 

new sources, in the section 111(b) rulemaking that the EPA is 

finalizing simultaneously with this rule. and in the Legal 

Memorandum for this rule. Our interpretations of these 

requirements in the two rules are generally consistent except to 

the extent that they reflect distinctions between new and 

existing sources. For example, as discussed in the section 

111(b) rule, the legislative history indicates that Congress 

intended that the BSER for new industrial facilities, which were 

expected to have lengthy useful lives, would include the most 

advanced pollution controls available, but Congress had a 

broader conception of the BSER for existing facilities. 

369 Our interpretation of the CAA provisions at issue is guided 

by Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842-43 (1984). In 

Chevron, the U.S. Supreme Court set out a two-step process for 

agency interpretation of statutory requirements: the agency 

must, at step 1, determine whether Congress’s intent as to the 

specific matter at issue is clear, and, if so, the agency must 

give effect to that intent. If congressional intent is not 

clear, then, at step 2, the agency has discretion to fashion an 

interpretation that is a reasonable construction of the statute.
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111(d)(1) directs the EPA to promulgate regulations establishing 

a section 110-like procedure under which states submit state 

plans that establish “standards of performance” for emissions of 

certain air pollutants from sources which, if they were new 

sources, would be regulated under section 111(b), and that 

implement and enforce those standards of performance. 

The term “standard of performance” is defined to mean— 

a standard for emissions of air pollutants which reflects 

the degree of emission limitation achievable through the 

application of the best system of emission reduction which 

(taking into account the cost of achieving such reduction 

and any nonair quality health and environmental impact and 

energy requirements) the Administrator determines has been 

adequately demonstrated. 

Section 111(a)(1). 

These provisions authorize the EPA to determine the BSER 

for the affected sources and, based on the BSER, to establish 

emission guidelines that identify the minimum amount of emission 

limitation that a state, in its state plan, must impose on its 

sources through standards of performance. Consistent with these 

CAA requirements, the EPA’s regulations require that the EPA’s 

guidelines reflect-- 

the degree of emission reduction achievable through the 

application of the best system of emission reduction which 

(taking into account the cost of such reduction) the 
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Administrator has determined has been adequately 

demonstrated.370 

The EPA’s approach in this rulemaking is to determine the 

BSER on a source categorysubcategory-wide basis, to determine 

the emission limitation that results from applying the BSER to 

the sources in the subcategory, and then to establish emission 

guidelines for the states that incorporate those emission 

limitations. The EPA expresses these emission limitations in the 

form of theemission performance levelsrates, and they must be 

achievable by the source category. However, thesubcategory 

through the application of the BSER. 

Following the EPA’s promulgation of emission guidelines, 

each state must determine the standards of performance for its 

sources, which the EPA’s regulations call “designated 

facilities.”371 A state has broad discretion in doing so. CAA 

section 111(d)(1) requires the EPA’s regulations to “permit the 

State in applying the standards of performance to its sources. 

That a standard of performance to any particular source ... to 

 

370 40 C.F.R. §CFR 60.21(e). This definition was promulgated as 

part of the EPA’s CAA 111(d) implementing regulations and was 

not updated to reflect the textual changes adopted by Congress 

in 1977. That said, Congress recognized that those changes 

“merely make[] explicit what was implicit in the previous 

language.” H.R. Rep. No. 95-294, at 190 (May 12, 1977). 

371 40 CFR 60.24(b)(3). 
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take into consideration, among other factors, the remaining 

useful life of the ... source....”372 In addition, under CAA 

section 116, the state is authorized to set a standard of 

performance for any particular source that is more stringent 

than the emission limit contained in the EPA’s emission 

guidelines.373 Thus, for any particular source, a state may apply 

a standard of performance that is either more stringent or less 

stringent than the EPA’s performance level in the emission 

guidelines, as long as, in total, the state’s sources achieve at 

least the same degree of emission limitation as included in the 

EPA’s emission guidelines.374 The states must include the 

 

372 The EPA’s regulations, promulgated prior to enactment of the 

“remaining useful life” provision of section 111(d)(1), provide: 

“Unless otherwise specified in the applicable subpart on a caseby-case basis for particular designated facilities, or classes 

of facilities, States may provide for the application of less 

stringent emission standards or longer compliance schedules than 

those otherwise required” by the corresponding emission 

guideline. 40 CFR 60.24(f). Some of the factors that a state may 

consider for this case-by-case analysis include the “cost of 

control resulting from plant age, location, or basic process 

design” and the “physical impossibility of installing necessary 

control equipment,” among other factors “that make application 

of a less stringent standard or final compliance time 

significantly more reasonable.” Id. 373 In addition, CAA section 116 authorizes the state to set 

standards of performance for all of its sources that, together, 

are more stringent than the EPA’s emission guidelines. 

374 In addition, under CAA section 116, the state is authorized 

to set a standard of performance for any particular source that 

is more stringent than the BSER, and for all of its sources that 

is more stringent than the EPA’s performance level. Further, the 
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standards of performance in their state plans and submit the 

plans to the EPA for review.375 Under CAA section 111(d)(2)(A), 

the EPA approves state plans as long as they are “satisfactory.” 

The states must include the standards of performance in 

their state plans and submit the plans to the EPA for review.376

Section 111(d)(2) authorizes the EPA to approve state plans as 

long as they are “satisfactory.” Under the EPA’s regulations, 

state plans must include emission standards and compliance 

schedules for all “designated facilities” within the state, and 

may, “[o]n a case-by-case basis for particular designated 

facilities, or classes of facilities, ... provide for the 

application of less stringent emission standards or longer 

compliance schedules than those otherwise required” by the 

corresponding emission guideline.377 This variance provision, 

promulgated in 1976, in conjunction with CAA section 111(d)’s 

 

state may consider remaining useful life and other factors in 

applying a standard of performance to a source, as discussed 

below. 

375 40 CFR 60.23. 376 40 C.F.R. § 60.23. 377 40 C.F.R. § 60.24(f). Some of the factors that a state may 

consider for this case-by-case analysis include the “cost of 

control resulting from plant age, location, or basic process 

design” and the “physical impossibility of installing necessary 

control equipment,” among other factors “that make application 

of a less stringent standard or final compliance time 

significantly more reasonable.” Id.
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“remaining useful life” provision, allows the states to vary the 

emission reduction obligations for their sources. 

As noted in the January 2014 proposal and discussed in more 

detail above under section II.G, Congress first included the 

definition of “standard of performance” when enacting CAA 

section 111 in the 1970 Clean Air Act Amendments (CAAA), amended 

it in the 1977 CAAA, and then amended it again in the 1990 CAAA 

to largely restore the definition as it read in the 1970 CAAA. 

It is in the legislative history for the 1970 and 1977 CAAA that 

Congress primarily addressed the definition as it read at those 

times and that legislative history provides guidance in 

interpreting this provision.378 In addition, although the D.C. 

 

378 In the 1970 CAAA, Congress defined “standard of performance,” 

under §111(a)(1), as: 

a standard for emissions of air pollutants which 

reflects the degree of emission limitation achievable 

through the application of the best system of emission 

reduction which (taking into account the cost of 

achieving such reduction) the Administrator determines 

has been adequately demonstrated. 

In the 1977 CAAA, Congress revised the definition to 

distinguish among different types of sources, and to require 

that for fossil fuel-fired sources, the standard (i) be based 

on, in lieu of the “best system of emission reduction ......

adequately demonstrated,” the “best technological system of 

continuous emission reduction ...... adequately demonstrated;” and 

(ii) require a percentage reduction in emissions. In addition, 

in the 1977 CAAA, Congress expanded the parenthetical 

requirement that the Administrator consider the cost of 

achieving the reduction to also require the Administrator to 
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Page 383 of 2153

Circuit has never reviewed a section 111(d) rulemaking, the 

Court has reviewed section 111(b) rulemakings on numerous 

occasions during the past 40 years, handing down decisions dated 

from 1973 to 2011,379 through which the Court has developed a 

body of case law that interprets the term “standard of 

performance.” 

c. Key elements of interpretation. The emission guidelines 

promulgated by the Administrator must include emission 

limitations that are “achievable” by the source category by 

application of a “system of emission reduction” that is 

“adequately demonstrated” and that the EPA determines to be the 

 

consider “any nonair quality health and environment impact and 

energy requirements.” 

In the 1990 CAAA, Congress again revised the definition, 

this time repealing the requirements that the standard of 

performance be based on the best technological system and 

achieve a percentage reduction in emissions, and replacing those 

provisions with the terms used in the 1970 CAAA version of 

§111(a)(1) that the standard of performance be based on the 

“best system of emission reduction ...... adequately 

demonstrated.” This 1990 CAAA version is the current definition, 

which is applicable at present. Even so, because parts of the 

definition as it read under the 1977 CAAA were retained in the 

1990 CAAA, the explanation in the 1977 CAAA legislative 

history, and the interpretation in the case law, of those parts 

of the definition in the case law remain relevant to the 

definition as it reads today. 

379 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375 (D.C. Cir. 

1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, (D.C. 

Cir. 1973); Portland Cement Ass’n v. EPA, 665 F.3d 177 (D.C. 

Cir. 2011). See also Delaware v. EPA, No. 13-1093 (D.C. Cir. May 

1, 2015). 
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“best” that is “adequately demonstrated,” “taking into account ... 

” the factors of “cost ... nonair quality health and environmental 

impact and energy requirements.” The D.C. Circuit has stated 

that in determining the “best” system, the EPA must also take 

into account “the amount of air pollution”380 reduced and the 

role of “technological innovation.”381 The Court has emphasized 

that the EPA has discretion in weighing those various factors.382, 

383

Before turning to each of these elements below, we discuss 

ourOur overall approach to determining the BSER and emission 

guidelines more generally., which incorporates the various 

elements, is as follows: In developing an emission guideline, we 

 

380 See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 

1981). 

381 See Sierra Club v. Costle, 657 F.2d at 347. 382 See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 

Cir. 1999). 

383 Although CAA section 111(a)(1) may be read to state that the 

factors enumerated in the parenthetical are part of the 

“adequately demonstrated” determination, the D.C. Circuit’s case 

law appears to treat them as part of the “best” determination. 

See Sierra Club v. Costle, 657 F.2d at 330 (recognizing that CAA 

section 111 gives the EPA authority “when determining the best 

technological system to weigh cost, energy, and environmental 

impacts”). Nevertheless, it does not appear that those two 

approaches would lead to different outcomes. See, e.g., Lignite 

Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 1999) 

(rejecting challenge to the EPA’s cost assessment of the “best 

demonstrated system”). In this rule, the EPA treats the factors 

as part of the “best” determination, but, as noted, even if the 

factors were part of the “adequately demonstrated” 

determination, our analysis and outcome would be the same. 
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Page 385 of 2153

generally engage in an analytical approach that is similar to 

what we conduct under CAA section 111(b) for new sources. First, 

we identify “system[s] of emission reduction systems” that have 

been “adequately demonstrated” for a particular source category. 

Second, we determine the “best” of these systems after 

evaluating the amount of reductions, costs, any nonair health 

and environmental impacts, and energy requirements., and, in the 

alternative, the advancement of technology (that is, we apply a 

formulation of the BSER with the above noted factors, and then, 

in the alternative, we apply a formulation of the BSER with 

those same factors plus the advancement of technology). And 

third, we select an achievable emission limit –- here, the 

emission performance standardrates -- based on the BSER. 384 In 

contrast to subsection (b), however, subsection (d)(1) assigns 

to the states, not the EPA, the obligation of setting standards 

of performance for the affected sources. As discussed below in 

the following subsection, in examining the range of reasonable 

options for states to consider in setting standards of 

performance under these guidelines, we identified a number of 

 

384 See, e.g., Oil and Natural Gas Sector: New Source Performance 

Standards and National Emission Standards for Hazardous Air 

pollutants Reviews, 77 FR 49490, 49494 (Aug. 16, 2012) 

(describing the three-step analysis in setting a standard of 

performance). 
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considerations, including the interconnected operations of the 

affected sources and the characteristics of the CO2 pollutant. 

The remainder of this subsection discusses the various 

elements in our general analytical approach. 

(1) System of emission reduction. 

As we discuss below, the CAA does not define the phrase 

“system of emission reduction.” The ordinary, everyday meaning 

of “system” is a set of things or parts forming a complex whole; 

a set of principles or procedures according to which something 

is done; an organized scheme or method; and a group of 

interacting, interrelated, or interdependent elements.385 With 

this definition, the phrase “system of emission reduction” takes 

a broad meaning: a set of measures that work together to reduce 

emissions. The EPA interprets this phrase to carry an important 

limitation: because the emission guidelines for the existing 

sources must reflect “the degree of emission limitation 

achievable through the application of the best system of 

emission reduction ... adequately demonstrated,” the system must 

 

385 Oxford Dictionary of English (3rd ed.) (2010), available at

http://www.oxforddictionaries.com/us/definition/american_english

/system; see also American Heritage Dictionary (5th ed.) (2013), 

available at 

http://www.yourdictionary.com/system#americanheritage; and The 

American College Dictionary (C.L. Barnhart, ed. 1970) (“an 

assemblage or combination of things or parts forming a complex 

or unitary whole”). 
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be limited to measures that can be implemented -– “appl[ied]” -- 

by the sources themselves, that is, as a practical matter, by 

actions taken by the owners or operators of the sources. As we 

discuss below, this definition is sufficiently broad to include 

the building blocks. 

(2) “Adequately demonstrated.” 

Under section 111(a)(1), in order for a “system of emission 

reduction” to serve as the basis for an “achievable” emission 

limitation, the Administrator must determine that the system is 

“adequately demonstrated.” This means, according to the D.C. 

Circuit, that the system is “one which has been shown to be 

reasonably reliable, reasonably efficient, and which can 

reasonably be expected to serve the interests of pollution 

control without becoming exorbitantly costly in an economic or 

environmental way.”386 It does not mean that the system “must be 

in actual routine use somewhere.”387 Rather, the Court has said, 

“[t]he Administrator may make a projection based on existing 

technology, though that projection is subject to the restraints 

 

386 Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. 

Cir. 1973), cert. denied, 416 U.S. 969 (1974). 387 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted) (discussing the Senate and House 

bills and reports from which the language in CAA section 111 

grew). 
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of reasonableness and cannot be based on ‘crystal ball’ 

inquiry.”388 Similarly, the EPA may “hold the industry to a 

standard of improved design and operational advances, so long as 

there is substantial evidence that such improvements are 

feasible.”389 Ultimately, the analysis “is partially dependent on 

‘lead time,’” that is, “the time in which the technology will 

have to be available.”390 Unlike for CAA section 111(b) standards 

that are applicable immediately after the effective date of 

their promulgation, under CAA section 111(e), compliance with 

CAA section 111(d) standards may be set sometime in the future. 

This is due, in part, to the period of time for states to submit 

state plans and for the EPA to act on them. 

(3) “Best.” 

In determining which adequately demonstrated system of 

emission reduction is the “best,” the EPA considers the 

following factors: 

(a) Costs. 

Under CAA section 111(a)(1), the EPA is required to take 

 

388

 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted). 

389 Sierra Club v. Costle, 657 F.2d 298, 364 (1981). 390

 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted). 
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into account “the cost of achieving” the required emission 

reductions. As described in the January 2014 proposal,391 in 

several cases the D.C. Circuit has elaborated on this cost 

factor and formulated the cost standard in various ways, stating 

that the EPA may not adopt a standard the cost of which would be 

“exorbitant,”392 “greater than the industry could bear and 

survive,”393 “excessive,”394 or “unreasonable.”395 These 

formulations appear to be synonymous, and for convenience, in 

this rulemaking, we will use reasonableness as the standard, so 

that a control technology may be considered the “best system of 

emission reduction ... adequately demonstrated” if its costs are 

reasonable, but cannot be considered the best system if its 

 

391 79 FR 1430, 1464 (January 8, 2014). 392 Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 

1999). 

393 Portland Cement Ass’n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 

1975). 

394 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981). 395 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981). 
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costs are unreasonable.396, 397 

The D.C. Circuit has repeatedly upheld the EPA’s 

consideration of cost in reviewing standards of performance. In 

several cases, the Court upheld standards that entailed 

significant costs, consistent with Congress’s view that “the 

 

396 These cost formulations are consistent with the legislative 

history of section 111. The 1977 House Committee Report noted: 

In the [1970] Congress [sic: Congress’s] view, it was 

only right that the costs of applying best practicable 

control technology be considered by the owner of a 

large new source of pollution as a normal and proper 

expense of doing business. 

1977 House Committee Report at 184. Similarly, the 1970 Senate 

Committee Report stated: 

The implicit consideration of economic factors in 

determining whether technology is “available” should 

not affect the usefulness of this section. The 

overriding purpose of this section would be to prevent 

new air pollution problems, and toward that end, 

maximum feasible control of new sources at the time of 

their construction is seen by the committee as the 

most effective and, in the long run, the least 

expensive approach. 

S. Comm. Rep. No. 91-1196 at 16. 

397 We received comments that we do not have authority to revise 

the cost standard as established in the case law, e.g., 

“exorbitant,” “excessive,” etc., to a “reasonableness” standard 

that the commenters considered less protective of the 

environment. We agree that we do not have authority to revise 

the cost standard as established in the case law, and we are not 

attempting to do so here. Rather, our description of the cost 

standard as “reasonableness” is intended to be a convenient term 

for referring to the cost standard as established in the case 

law. 
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costs of applying best practicable control technology be 

considered by the owner of a large new source of pollution as a 

normal and proper expense of doing business.”398 See Essex 

Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir. 

1973);399 Portland Cement Association v. Ruckelshaus, 486 F.2d 

375, 387-88 (D.C. Cir. 1973); Sierra Club v. Costle, 657 F.2d 

298, 313 (D.C. Cir. 1981) (upholding standard imposing controls 

on SO2 emissions from coal-fired power plants when the “cost of 

the new controls ... is substantial”).400 

As discussed below, the EPA may consider costs on both a 

source-specific basis and a sector-wide, regional, or nationwide 

basis. 

(b) Non-air health and environmental impacts. 

Under CAA section 111(a)(1), the EPA is required to take 

into account “any nonair quality health and environmental 

 

398 1977 House Committee Report at 184. 399 The costs for these standards were described in the 

rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 

5769 (March 21, 1972). 

400 Indeed, in upholding the EPA’s consideration of costs under 

other provisions requiring consideration of cost, courts have 

also noted the substantial discretion delegated to the EPA to 

weigh cost considerations with other factors. Chemical Mfr’s 

Ass’n v. EPA, 870 F. 2d 177, 251 (5th Cir. 1989); Association of 

Iron and Steel Inst. v. EPA, 526 F. 2d 1027, 1054 (3d Cir. 

1975); Ass’n of Pacific Fisheries v. EPA, 615 F. 2d 794, 808 

(9th Cir. 1980). 
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Page 392 of 2153

impact” in determining the BSER. As the D.C. Circuit has 

explained, this requirement makes explicit that a system cannot 

be “best” if it does more harm than good due to cross-media 

environmental impacts.401

(c) Energy considerations. 

Under CAA section 111(a)(1), the EPA is required to take 

into account “energy requirements.” As discussed below, the EPA 

may consider energy requirements on both a source-specific basis 

and a sector-wide, region-wide, or nationwide basis. Considered 

on a source-specific basis, “energy requirements” entails, for 

example, the impact, if any, of the system of emission reduction 

on the source’s own energy needs. 

(d) Amount of emissions reductions. 

In the proposed rulemakings for this rule and the 

associated section 111(b) rule, we noted that although the 

definition of “standard of performance” does not by its terms 

identify the amount of emissions from the category of sources or 

the amount of emission reductions achieved as factors the EPA 

must consider in determining the “best system of emission 

reduction,” the D.C. Circuit has stated that the EPA must do so. 

 

401 Portland Cement v. EPA, 486 F. 2d at 384; Sierra Club v. 

Costle, 657 F. 2d at 331; see also Essex Chemical Corp. v. 

Ruckelshaus, 486 F. 2d at 439 (remanding standard to consider 

solid waste disposal implications of the BSER determination). 
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Page 393 of 2153

See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) 

(“we can think of no sensible interpretation of the statutory 

words “best ... system” which would not incorporate the amount 

of air pollution as a relevant factor to be weighed when 

determining the optimal standard for controlling ... 

emissions”).402 The fact that the purpose of a “system of 

emission reduction” is to reduce emissions, and that the term 

itself explicitly incorporates the concept of reducing 

emissions, supports the Court’s view that in determining whether 

a “system of emission reduction” is the “best,” the EPA must 

consider the amount of emission reductions that the system would 

yield. Even if the EPA were not required to consider the amount 

of emission reductions, the EPA has the discretion to do so, on 

grounds that either the term “system of emission reduction” or 

the term “best” may reasonably be read to allow that discretion. 

 (e) Sector- or nationwide component of factors in 

 

402 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was 

governed by the 1977 CAAA version of the definition of “standard 

of performance,” which revised the phrase “best system of 

emission reduction” to read, “best technological system.” of 

continuous emission reduction.” As noted above, the 1990 CAAA 

deleted “technological,”” and “continuous” and thereby returned 

the phrase to how it read under the 1970 CAAA. The court’s 

interpretation of thisthe 1977 CAAA phrase in Sierra Club v. 

Costle to require consideration of the amount of air emissions 

remains valid for the 1990 CAAA phrase “best system of emission 

reduction.” 
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determining the BSER. 

As discussed in the January 2014 proposal for the section 

111(b) rulemaking and the proposal for this rulemaking, another 

component of the D.C. Circuit’s interpretations of CAA section 

111 is that the EPA may consider the various factors it is 

required to consider on a national or regional level and over 

time, and not only on a plant-specific level at the time of the 

rulemaking.403 The D.C. Circuit based this interpretation – which 

it made in the 1981 Sierra Club v. Costle case, which concerned 

the NSPS for new power plants -- on a review of the legislative 

history, stating, 

[T]he Reports from both Houses on the Senate and House 

bills illustrate very clearly that Congress itself was 

using a long-term lens with a broad focus on future 

costs, environmental and energy effects of different 

technological systems when it discussed section 111.404 

The Court has upheld EPA rules that the EPA “justified ... in 

terms of the policies of the Act,” including balancing long-term 

national and regional impacts: 

The standard reflects a balance in environmental, 

economic, and energy consideration by being 

sufficiently stringent to bring about substantial 

reductions in SO2 emissions (3 million tons in 1995) 

yet does so at reasonable costs without significant 

energy penalties.... By achieving a balanced coal 

 

403 79 FR 1430, 1465 (January 8, 2014) (citing Sierra Club v. 

Costle, 657 F.2d at 351). 404 Sierra Club v. Costle, 657 F.2d at 331 (citations omitted) 

(citing legislative history).
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demand within the utility sector and by promoting the 

development of less expensive SO2 control technology, 

the final standard will expand environmentally 

acceptable energy supplies to existing power plants 

and industrial sources. 

By substantially reducing SO2 emissions, the standard 

will enhance the potential for long term economic 

growth at both the national and regional levels.405

(1In this rule, the EPA is considering costs and 

energy implications on the basis of (i) their sourcespecific impacts and (ii) a sector-wide, regional, or 

national basis, both separately and in combination with 

each other. 

(4) Achievability of the emission limitation in the 

emission guidelines. 

Before discussing the requirement under section 111(d) that 

the emission limitation in the emission guidelines must be 

“achievable,” it is useful to discuss the comparable requirement 

under section 111(b) for new sources. For new sources, CAA 

section 111(b)(1)(B) and (a)(1) provides that the EPA must 

establish “standards of performance,” which are standards for 

 

405 Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 Fed. 

Reg.FR at 33,58333583/3 - 33,584-33584/1). In the January 2014 

proposal, we explained that although the D.C. Circuit decided 

Sierra Club v. Costle before the Chevron case was decided in 

1984, the D.C. Circuit’s decision could be justified under 

either Chevron step 1 or 2. 79 FR 1430, 1466 (January 8, 2014). 
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emissions that reflect the degree of emission limitation that is 

“achievable” through the application of the BSER. For existing 

sources, section 111(d)(1) requires the EPA to establish 

requirements for state plans that must include “standards of 

performance.” Through long-standing regulations406 and consistent 

practice, the EPA has interpreted this provision to require the 

EPA to promulgate emission guidelines that determine the BSER 

for a source category and that identify the amount of emission 

limitation achievable by application of the BSER. 

Although section 111(d)(1) and (a)(1) are not explicit on 

whether the emission limitation must be achievable by each 

source in the source category, the EPA has promulgated these 

emission guidelines on the basis that each source can achieve 

the limitation, even though the State retains discretion to 

apply standards of performance to individual sources that are 

more or less stringent. By comparison, in a rulemaking for new 

sources under section 111(b), the EPA must promulgate the 

“standards of performance” directly, and the first element of 

the definition of “standard of performance” is that the emission 

limitation reflected in the “standard for emissions” that the 

EPA promulgates must be “achievable” based on application of the 

 

406 40 CFR 60.21(e). 
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BSER. 79 FR 1430, 1463 (January 8, 2014). Moreover, again, for 

new sourcesAccording to the D.C. Circuit, a standard of 

performance is “achievable” if a technology can reasonably be 

projected to be available to an individual source at the time it 

is constructed that will allow it to meet the standard.407 In 

this rulemaking, we are taking the same approach for the 

emission limitation that the EPA identifies in the emission 

guidelines. 

AccordingMoreover, according to the D.C. CircuitCourt, 

”[a]n achievable standard is one which is within the realm of 

the adequately demonstrated system’s efficiency and which, while 

not at a level that is purely theoretical or experimental, need 

not necessarily be routinely achieved within the industry prior 

to its adoption.”408 To be achievable, a standard “must be 

capable of being met under most adverse conditions which can be 

reasonably be expected to recur and which are not or cannot be 

taken into account in determining the ‘costcosts’ of 

compliance.’”.”409 To show a standard is achievable, the EPA must 

 

407 Sierra Club v. Costle, 657 F.2d 298, 364, n. 276 (D.C. Cir. 

1981).

408 Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 (D.C. 

Cir. 1973), cert. denied, 416 U.S. 969 (1974). 409 Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 433, n.46 (D.C. Cir. 

1980). 
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Page 398 of 2153

“(1) identify variable conditions that might contribute to the 

amount of expected emissions, and (2) establish that the test 

data relied on by the agency are representative of potential 

industry-wide performance, given the range of variables that 

affect the achievability of the standard.”410

The D.C. Circuit established these standards for 

achievability in cases concerning CAA section 111(b) new source 

standards of performance. There is no case law under CAA section 

111(d). Assuming that those standards for achievability apply 

under section 111(d), in this rulemaking, we are taking a 

similar approach for the emission limitation that the EPA 

identifies in the emission guidelines. For existing sources, 

section 111(d)(1) requires the EPA to establish requirements for 

state plans that, in turn, must include “standards of 

performance.” Through long-standing regulations411 and consistent 

practice, the EPA has interpreted this provision to require the 

 

410 Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981) 

(citing Nat’l Lime Ass’n v. EPA, 627 F.2d 416 (D.C. Cir. 1980). 

In considering the representativeness of the source tested, the 

EPA may consider such variables as the “‘feedstock, operation, 

size and age’ of the source.” Nat’l Lime Ass’n v. EPA, 627 F.2d 

416, 433 (D.C. Cir. 1980). Moreover, it may be sufficient to 

“generalize from a sample of one when one is the only available 

sample, or when that one is shown to be representative of the 

regulated industry along relevant parameters.” Nat’l Lime Ass’n 

v. EPA, 627 F.2d 416, 434, n.52 (D.C. Cir. 1980). 411 40 C.F.R. §CFR 60.21(e). 
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EPA to promulgate emission guidelines that determine the BSER 

for a source category and that identify the amount of emission 

limitation achievable by application of the BSER. 

(2) System of emission reduction. As we discuss below, the 

CAA does not define the phrase “system of emission reduction.” 

The ordinary, everyday meaning of “system” is “a set of things 

working together as parts of a mechanism or interconnecting 

network; a complex whole.”412 With this definition, the phrase 

“system of emission reduction” takes a broad meaning: a set of 

things that work together to reduce emissions. The EPA 

interprets this phrase to carry an important limitation: Because 

the emission guidelines for the existing sources must reflect 

“the degree of emission limitation achievable through the

application of the best system of emission reduction ... 

adequately demonstrated,” the system must be limited to things 

that can be implemented – “appl[ied]” -- by the sources 

themselves, that is, as a practical matter, by actions taken by 

the owners or operators of the sources. As we discuss below, 

 

412

Oxford Dictionary of English (3rd ed.) (published 2010, online 

version 2013) 

http://www.oxfordreference.com.mutex.gmu.edu/view/10.1093/acref/

9780199571123.001.0001/acref-9780199571123. 
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Page 400 of 2153

this definition is sufficiently broad to include the building 

blocks. 

(3The EPA has promulgated these emission guidelines on the 

basis that the existing sources can achieve the limitation, even 

though the state retains discretion to apply standards of 

performance to individual sources that are more or less 

stringent. 

(a) Technical feasibility of the best system of emission 

reduction. . 

As indicated in the proposed rulemakings for this rule and 

the associated section 111(b) rule, the requirement that the 

emission limitation in the emission guidelines be “achievable” 

based on the “best system of emission reduction ... adequately 

demonstrated” indicates that the technology or other measures 

that the EPA identifies as the BSER must be technically 

feasible. See 79 FR 1430, 1463 (January 8, 2014). At least in 

some cases, in determining whether the emission limitation is 

achievable, it is useful to analyze the technical feasibility of 

the system of emission reduction, and we do so in this 

rulemaking. 

(4) Amount of emissions reductions. In the proposed 

rulemakings for this rule and the associated section 111(b) 

rule, we noted that although the definition of “standard of 
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Page 401 of 2153

performance” does not by its terms identify the amount of 

emissions from the category of sources or the amount of emission 

reductions achieved as factors the EPA must consider in 

determining the “best system of emission reduction,” the D.C. 

Circuit has stated that the EPA must do so. See Sierra Club v. 

Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) (“we can think of no 

sensible interpretation of the statutory words “best ... system” 

which would not incorporate the amount of air pollution as a 

relevant factor to be weighed when determining the optimal 

standard for controlling ... emissions”).413 The fact that the 

purpose of a “system of emission reduction” is to reduce 

emissions, and that the term itself explicitly incorporates the 

concept of reducing emissions, supports the Court’s view that in 

determining whether a “system of emission reduction” is the 

“best,” the EPA must consider the amount of emission reductions 

that the system would yield. Even if the EPA were not required 

 

413 Sierra Club v. Costle, 657 F.2d 298 (D.C. Cir. 1981) was 

governed by the 1977 CAAA version of the definition of “standard 

of performance,” which revised the phrase “best system of 

emission reduction” to read, “best technological system of 

continuous emission reduction.” As noted above, the 1990 CAAA 

deleted “technological” and “continuous” and thereby returned 

the phrase to how it read under the 1970 CAAA. The court’s 

interpretation of the 1977 CAAA phrase in Sierra Club v. Costle

to require consideration of the amount of air emissions remains 

valid for the 1990 CAAA phrase “best system of emission 

reduction.” 
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to consider the amount of emission reductions, the EPA has the 

discretion to do so, on grounds that either the term “system of 

emission reduction” or the term “best” may reasonably be read 

under Chevron step 2 to allow that discretion. 

(5) Costs. Under CAA section 111(a)(1), the EPA is required 

to take into account “the cost of achieving” the required 

emission reductions. As described in the January 2014 

proposal,414 in several cases the D.C. Circuit has elaborated on 

this cost factor and formulated the cost standard in various 

ways, stating that the EPA may not adopt a standard the cost of 

which would be “exorbitant,”415 “greater than the industry could 

bear and survive,”416 “excessive,”417 or “unreasonable.”418 These 

formulations appear to be synonymous, and for convenience, in 

this rulemaking, we will use reasonableness as the standard, so 

that a control technology may be considered the “best system of 

emission reduction ... adequately demonstrated” if its costs are 

reasonable, but cannot be considered the best system if its 

 

414 79 FR 1430, 1464 (January 8, 2014). 415 Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 

1999). 

416 Portland Cement Ass’n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 

1975). 

417 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981). 418 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981). 
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costs are unreasonable.419 

The D.C. Circuit has never invalidated a standard of 

performance on grounds that it was too costly. In several cases, 

the Court upheld standards that entailed significant costs, 

consistent with Congress’s view that “the costs of applying best 

practicable control technology be considered by the owner of a 

large new source of pollution as a normal and proper expense of 

doing business.”420 See Essex Chemical Corp. v. Ruckelshaus, 486 

 

419 These cost formulations are consistent with the legislative 

history of section 111. The 1977 House Committee Report noted: 

In the [1970] Congress [sic: Congress’s] view, it was 

only right that the costs of applying best practicable 

control technology be considered by the owner of a 

large new source of pollution as a normal and proper 

expense of doing business. 

1977 House Committee Report at 184. Similarly, the 1970 Senate 

Committee Report stated: 

The implicit consideration of economic factors in 

determining whether technology is “available” should 

not affect the usefulness of this section. The 

overriding purpose of this section would be to prevent 

new air pollution problems, and toward that end, 

maximum feasible control of new sources at the time of 

their construction is seen by the committee as the 

most effective and, in the long run, the least 

expensive approach. 

S. Comm. Rep. No. 91-1196 at 16. 

420 1977 House Committee Report at 184. 
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F.2d 427, 440 (D.C. Cir. 1973);421 Portland Cement Association v. 

Ruckelshaus, 486 F.2d 375, 387-88 (D.C. Cir. 1973); Sierra Club 

v. Costle, 657 F.2d 298, 313 (D.C. Cir. 1981) (upholding 

standard imposing controls on SO2 emissions from coal-fired power 

plants when the “cost of the new controls ... is 

substantial”).422 

As discussed below, the EPA may consider costs on both a 

source-specific basis and a sector-wide, regional, or nationwide 

basis. 

(6) Non-air health and environmental impacts. Under CAA 

section 111(a)(1), the EPA is required to take into account “any 

nonair quality health and environmental impact” in determining 

the BSER and whether it is adequately demonstrated. This 

requirement makes explicit what was implicit in the initial 

version of section 111: a system cannot be “best” if it does 

 

421 The costs for these standards were described in the 

rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 

5769 (March 21, 1972). 

422 Indeed, in upholding the EPA’s consideration of costs under 

other provisions requiring consideration of cost, courts have 

also noted the substantial discretion delegated to the EPA to 

weigh cost considerations with other factors. Chemical Mfr’s 

Ass’n v. EPA, 870 F. 2d 177, 251 (5th Cir. 1989); Association of 

Iron and Steel Inst. v. EPA, 526 F. 2d 1027, 1054 (3d Cir. 

1975); Ass’n of Pacific Fisheries v. EPA, 615 F. 2d 794, 808 

(9th Cir. 1980). 
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more harm than good due to cross-media environmental impacts.423

(7) Energy considerations. Under CAA section 111(a)(1), the 

EPA is required to take into account “energy requirements.” As 

discussed below, the EPA may consider energy requirements on 

both a source-specific basis and a sector-wide, region-wide, or 

nationwide basis. Considered on a source-specific basis, “energy 

requirements” entails, for example, the impact, if any, of the 

system of emission reduction on the source’s own energy needs. 

(8) Sector- or nationwide component of factors in 

determining the BSER. As discussed in the January 2014 proposal, 

another component of the D.C. Circuit’s interpretations of CAA 

section 111 is that the EPA may consider the various factors it 

is required to consider on a national or regional level and over 

time, and not only on a plant-specific level at the time of the 

rulemaking.424 The D.C. Circuit based this conclusion on a review 

of the legislative history, stating, 

The Conferees defined the best technology in terms of 

“long-term growth,” “long-term cost savings,” effects on 

the “coal market,” including prices and utilization of coal 

reserves, and “incentives for improved technology.” Indeed, 

 

423 Portland Cement v. EPA, 486 F. 2d at 384; Sierra Club v. 

Costle, 657 F. 2d at 331; see also Essex Chemical Corp. v. 

Ruckelshaus, 486 F. 2d at 439 (remanding standard to consider 

solid waste disposal implications of the BSER determination). 

424

 79 FR 1430, 1465 (January 8, 2014) (citing Sierra Club v. 

Costle, 657 F.2d at 351). 
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the Reports from both Houses on the Senate and House bills 

illustrate very clearly that Congress itself was using a 

long-term lens with a broad focus on future costs, 

environmental and energy effects of different technological 

systems when it discussed section 111.425

The Court has upheld EPA rules that the EPA “justified ... in 

terms of the policies of the Act,” including balancing long-term 

national and regional impacts: 

The standard reflects a balance in environmental, 

economic, and energy consideration by being 

sufficiently stringent to bring about substantial 

reductions in SO2 emissions (3 million tons in 1995) 

yet does so at reasonable costs without significant 

energy penalties.... By achieving a balanced coal 

demand within the utility sector and by promoting the 

development of less expensive SO2 control technology, 

the final standard will expand environmentally 

acceptable energy supplies to existing power plants 

and industrial sources. 

By substantially reducing SO2 emissions, the standard 

will enhance the potential for long term economic 

growth at both the national and regional levels.426

As with the final rule under section 111(b) that is 

associated with this rule, the EPA is considering costs and 

energy implications on the basis of both their sourcespecific impacts and a sector-wide, regional, or national 

 

425 Sierra Club v. Costle, 657 F.2d at 331 (citations omitted) 

(citing legislative history).

426 Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 FR at 

33583/3-33584/1). In the January 2014 proposal, we explained 

that although the D.C. Circuit decided Sierra Club v. Costle

before the Chevron case was decided in 1984, the D.C. Circuit’s 

decision could be justified under either Chevron step 1 or 2. 79 

FR 1430, 1466 (January 8, 2014). 
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basis. 

(9) “Adequately demonstrated.” Under section 111(a)(1), in 

order for a system of emission reduction to qualify as the 

“best” and to serve as the basis for an “achievable” emission 

limitation, the Administrator must determine that the system is 

“adequately demonstrated.” This means, according to the D.C. 

Circuit, that the system is “one which has been shown to be 

reasonably reliable, reasonably efficient, and which can 

reasonably be expected to serve the interests of pollution 

control without becoming exorbitantly costly in an economic or 

environmental way.”427 It does not mean that the system “must be 

in actual routine use somewhere.”428 Rather, the court has said, 

“[t]he Administrator may make a projection based on existing 

technology, though that projection is subject to the restraints 

of reasonableness and cannot be based on ‘crystal ball’ 

inquiry.”429 Similarly, the EPA may “hold the industry to a 

standard of improved design and operational advances, so long as 

 

427 Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. 

Cir. 1973), cert. denied, 416 U.S. 969 (1974). 428 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 

(D.C. Cir. 1973) (citations omitted) (discussing the Senate and 

House bills and reports from which the language in CAA section 

111 grew). 

429 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted). 
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there is substantial evidence that such improvements are 

feasible.”430 Ultimately, the analysis “is partially dependent on 

‘lead time,’” that is, “the time in which the technology will 

have to be available.”431 Unlike for CAA section 111(b) standards 

that are immediately applicable, compliance with CAA section 

111(d) standards may be set sometime in the future. 

(10(5) Expanded use and development of technology. 

The D.C. Circuit has long held that Congress intended for 

CAA section 111 to create incentives for new technology and 

therefore that the EPA is required to consider technological 

innovation as one of the factors in determining the “best system 

of emission reduction.” See Sierra Club v. Costle, 657 F.2d at 

346-47. The Court has grounded its reading in the statutory 

text.432 In addition, the Court’s interpretation finds firm 

support in the legislative history.433 The legislative history 

 

430 Sierra Club v. Costle, 657 F.2d 298, 364 (1981). 431 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted). 

432 Sierra Club v. Costle, 657 F. 2d at 346 (“Our interpretation 

of section 111(a) is that the mandated balancing of cost, 

energy, and nonair quality health and environmental factors 

embraces consideration of technological innovation as part of 

that balance. The statutory factors which EPA must weigh are 

broadly defined and include within their ambit subfactors such 

as technological innovation.”). 

433 See S. Rep. No. 91-1196 at 16 (1970) (“Standards of 

performance should provide an incentive for industries to work 
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identifies three different ways that Congress designed CAA 

section 111 to authorize standards of performance that promote 

technological improvement: (i) the development of technology 

that may be treated as the “best system of emission reduction . 

. .... adequately demonstrated;” under section 111(a)(1);434 (ii) 

the expanded use of the best demonstrated technology;435 and 

(iii) the development of emerging technology.436 Even if the EPA 

were not required to consider technological innovation as part 

of its determination of the BSER, it would be reasonable for the 

EPA to consider it, either because technological innovation may 

be considered an element of the term “best,” or because the term 

“best system of emission reduction” is ambiguous as to whether 

technological innovation may be considered, and it is reasonable 

 

toward constant improvement in techniques for preventing and 

controlling emissions from stationary sources”); S. Rep. No. 95-

127 at 17 (1977) (cited in Sierra Club v. Costle, 657 F.2d at 

346 n. 174) (“The section 111 Standards of Performance ... 

sought to assure the use of available technology and to 

stimulate the development of new technology”). 

434 See Portland Cement Ass’n v.Ruckelshaus, 486 F.2d 375, 391 

(D.C. Cir. 1973) (the best system of emission reduction must 

“look[] toward what may fairly be projected for the regulated 

future, rather than the state of the art at present”). 

435 See 1970 Senate Committee Report No. 91-1196 at 15 (“The 

maximum use of available means of preventing and controlling air 

pollution is essential to the elimination of new pollution 

problems”). 

436 See Sierra Club v. Costle, 657 F.2d at 351 (upholding a 

standard of performance designed to promote the use of an 

emerging technology). 
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for the EPA to interpret it to authorize consideration of 

technological innovation in light of Congress’s emphasis on 

technological innovation. 

In any event, as discussed below, the EPA may justify the 

control technologiesmeasures identified in this rule as the BSER 

even without considering the factor of incentivizing 

technological innovation or development. 

(11) Agency6) EPA discretion. 

The D.C. Circuit has made clear that the EPA has broad 

discretion in determining the appropriate standard of 

performance under the definition in CAA section 111(a)(1), 

quoted above. Specifically, in Sierra Club v. Costle, 657 F.2d 

298 (D.C. Cir. 1981), the Court explained that “section 111(a) 

explicitly instructs the EPA to balance multiple concerns when 

promulgating a NSPS,”437 and emphasized that “[t]he text gives 

the EPA broad discretion to weigh different factors in 

setting the standard.”438 In Lignite Energy Council v. EPA, 

198 F.3d 930 (D.C. Cir. 1999), the Court reiterated: 

Because section 111 does not set forth the weight that 

 

437 Sierra Club v. Costle, 657 F.2d at 319. 438 Sierra Club v. Costle, 657 F.2d at 321; see also New York v. 

Reilly, 969 F. 2d at 1150 (because Congress did not assign the 

specific weight the Administrator should assign to the statutory 

elements, “the Administrator is free to exercise [her] 

discretion” in promulgating an NSPS). 
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should be assigned to each of these factors, we have 

granted the agency a great degree of discretion in 

balancing them.... EPA's choice [of the ‘best system’] 

will be sustained unless the environmental or economic 

costs of using the technology are exorbitant.... EPA 

[has] considerable discretion under section 111.439 

d. Approach to the source category and subcategorizing. Section 

111 requires the EPA first to list source categories that may 

reasonably be expected to endanger public health or welfare and 

then to regulate new sources within each such source category. 

Section 111(b)(2) grants the EPA discretion whether to 

“distinguish among classes, types, and sizes within categories 

of new sources for the purpose of establishing [new source] 

standards,” which we refer to as “subcategorizing.” Section 

111(d)(1), in conjunction with section 111(a)(1), simply 

requires the EPA to determine the BSER, does not prescribe the 

method for doing so, and is silent as to whether the EPA may 

 

439

Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 

1999) (paragraphing revised for convenience). See New York v. 

Reilly, 969 F.2d 1147, 1150 (D.C. Cir. 1992) (“Because Congress 

did not assign the specific weight the Administrator should 

accord each of these factors, the Administrator is free to 

exercise his discretion in this area.”); see also NRDC v. EPA, 

25 F.3d 1063, 1071 (D.C. Cir. 1994) (EPA did not err in its 

final balancing because “neither RCRA nor EPA’s regulations 

purports to assign any particular weight to the factors listed 

in subsection (a)(3). That being the case, the Administrator 

was free to emphasize or deemphasize particular factors, 

constrained only by the requirements of reasoned agency 

decisionmaking.”). 
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subcategorize. The EPA interprets this provision to authorize 

the EPA to exercise discretion as to whether and, if so, how to 

subcategorize. In addition, the regulations under CAA section 

111(d) provide -- 

The Administrator will specify different emission 

guidelines or compliance times or both for different 

sizes, types, and classes of designated facilities 

when costs of the control, physical limitations, 

geographical location, or similar factors make 

subcategorization appropriate.440

 

 As with any of its own regulations, the EPA has authority 

to interpret or revise these regulations. 

 Of course, regardless of whether the EPA subcategorizes 

within a source category for purposes of determining the BSER 

and the emissions performance level for the emission guideline, 

as part of its section 111(d) plan, a state retains great 

flexibility in assigning standards of performance to its 

affected EGUs. Thus, the state may, if it wishes, impose 

different emission reduction obligations on different sources, 

as long as the overall level of emission limitation is at least 

as stringent as the emission guidelines. 

2. The BSER for this Rule –-– Overview 

 

440 40 CFR 60.22(b)(5). 
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a. Summary. This section describes the EPA’s overall approach to 

establishing the BSER. This rule, promulgated under CAA section 

111(d), establishes emission guidelines for states to use in 

establishing standards of performance for affected EGUs, and the 

BSER is the central determination that the EPA must make in 

doing so. In understandingformulating the EPA’s basis for 

guidelines. In order to establish the BSER, it is useful to view 

the BSER from two complementary perspectives. The first 

perspective considers we have considered the subcategory of the 

steam affected EGUs as a whole, and the subcategory of the 

combustion turbine affected EGUs as a whole, treats and have 

identified the BSER for each subcategory as the measures 

identified by the EPA that the sources, viewed together and 

operating under the standards of performance established for 

them by the states, can implement to reduce their emissions to 

an appropriate amount, and that meet the other requirements for 

the BSER including, for example, cost reasonableness. For 

convenience, this may be referred to as the source-category 

perspective because it views the BSER on a category- or 

subcategory-wide basis.441 After identifying the BSER in this 

 

441 In this rulemaking, our determination that the costs are 

reasonable means that the costs meet the cost standard in the 

case law no matter how that standard is articulated, that is, 
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manner, the EPA determines the performance levels –- in this 

case, the CO2 emission performance rates –- for the steam 

generators and for the combustion turbines. 

The second perspective considers the affected EGUs 

individually, and treatsIn establishing the BSER asthe EPA also 

considered the set of actions that an EGU, operating under a 

standard of performance established by its state, may take to 

achieve the applicable performance rate, if the state adopts 

that rate as the standard of performance and applies it to the 

EGUs in its jurisdiction, or to achieve the equivalent massbased limit, and that meet the other requirements for the BSER. 

For convenience, this may be referred to as the individualsource perspective. 

Under either perspective, the EPA determinesThese actions 

implement the BSER as encompassing the same set of actions, but 

the two perspectives serve to elucidate the EPA’s reasoning.and 

may therefore be understood as part of the BSER. 

An

 example illustrating the relationship between the sourcemeasures determined to constitute the BSER for the source 

 

whether the cost standard is articulated through the terms that 

the case law uses, e.g., “exorbitant,” “excessive,” etc., or 

through the term we use for convenience, “reasonableness”. 
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category and individual-source perspectives for this rulethe 

actions that may be undertaken by individual sources that are 

therefore also part of the BSER is the substitution of nonzeroemitting generation for CO2-emitting generation. This measure 

involves two distinct actions: increasing the amount of nonzeroemitting generation and reducing the amount of CO2-emitting 

generation. From the perspective of the source- category

perspective, the two actions are halves of a single balanced 

endeavor, but from the individual-source perspective of any 

individual affected EGU, the two actions are separable, and a 

particular affected EGU may decide to implement either or both 

of the actions. Further, an individual source may choose to 

invest directly in actions at its own facility or an affiliated 

facility or to cross-invest in actions at other facilities on 

the interconnected electricity system. 

To reiterate the overall context for the BSER: Inin this 

rule, the EPA determined the BSER, and applied it to the 

category of affected sourcesEGUs to determine the performance 

levels –- that is, the CO2 emission performance rates -- for 

steam generators and for combustion turbines. States must impose 

emission limits standards of performance on their sources that

implement the CO2 emission performance rates, or, as an 

alternative method of compliance, in total, achieve the 
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sameequivalent emissions performance level that the CO2 emission 

performance rates would achieve if applied directly to each 

source as the standard or emissions limitation it must meet.442

Each state has flexibility in how it assigns the emission 

limitations to its affected EGUs –- and in fact, the state can 

be more stringent than the guidelines require –- but one of the 

state’s choices is to assignconvert the CO2 emission performance 

rates or the mass equivalents thereof tointo standards of 

performance –- which may incorporate emissions trading –- for

each of its affected EGUs. If a state does so, then the affected 

EGUs may achieve their emission limits by taking the actions 

that qualify as the BSER. Since the BSER and, in this case its 

constituent elements, reflect the critical criteria of 

feasibility, reasonable cost, and other BSER criteria, the BSER 

assures that there is at least one pathway –- the CO2 emission 

performance rates or mass equivalents -- for the state and its 

affected EGUs to take that achieves the requisite level of 

emission reductions, while, again, assuring that the affected 

EGUs can achieve those emission limits at reasonable cost and 

consistent with the other factors for the BSER. 

 

442 The approaches that states may take in their plans are 

discussed in section VIII. 
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This section describes the EPA’s process and basis for 

determining the BSER for the purpose of determining the CO2

emission performance rates.443 As noted above, the BSER 

determined through this process can be described from two 

perspectives. Viewed from the source-category perspective, 

theThe EPA is identifying the BSER as a well-established set of 

measures that EGUs have been used by EGUs for many years to 

achieve various business and policy purposes, and have been used 

in recent years for the specific purpose of reducing theirEGUs’

CO2 emissions, and that are appropriate to the global nature 

offor carbon pollution (given its global nature and large 

quantities, and the limited means to control it) and afforded by 

the highly integrated nature of the utility power sector. We 

evaluated these measures with a view to the states’ obligation 

to establish standards of performance and included in our BSER 

determination consideration of the range of options available 

for states to employ in establishing those standards of 

performance. These measures include: (i) increasing the 

operational efficiency ofimproving heat rate at existing coalfired steam EGUs on average by a specified percentage (building 

 

443 Other sections in this preamble describe how EPA calculated 

the CO2 emission performance rates based on the BSER. 
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block 1); (ii) substituting increased generation from existing 

NGCC units for reduced generation at existing steam EGUs in 

specified amounts (building block 2); and (iii) substituting 

increased generation from new zero-carbonemitting RE generating 

capacity for reduced generation at existing fossil fuel-fired 

EGUs in specified amounts (building block 3). It should be noted 

that building block 2 incorporates reduced generation from steam 

EGUs on a source category-wide basis and building block 3 

incorporates reduced generation from all fossil fuel-fired EGUs

on a source category-wide basis..444 Further, as discussed below, 

given the global nature of carbon pollution and the highly 

integrated utility power sector, each of the building blocks 

incorporates various mechanisms for facilitating crossinvestment by individual affected EGUs in emission rate 

improvements or emission reduction activities at other 

locationlocations on the interconnected electricity system. The 

range of mechanisms includes bilateral investment of various 

kinds,; the issuance and purchaseacquisition of emission rate 

credits representing the emissions-reducing effects of specific 

activities, where available under state plans; and more general 

 

444 The building block measures are not designed to reduce 

electricity generation overall; they are focused on maintaining 

the same level of electricity generation, but through less 

polluting processes. 
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emissions trading using rate-based credits or mass-based 

allowances, and other multi-unit compliance approaches such (as 

averaging or bubblingdiscussed in section V.A.2.f. below), where 

the affected EGUs are operating under standards of performance 

that incorporate emissions trading.445

Viewed from the individual-source perspective, the EPA is 

identifying the BSER as a menu of actions -- all of which fall 

within theThe set of measures identified as the BSER fromfor the 

source- category perspective --encompasses a menu of actions 

that are part of the BSER and that individual affected EGUs may 

implement in different amounts and combinations in order to 

achieve their emission limits at reasonable cost. This menu 

includes actions that: (i) affected coal-fired steam EGUs can 

implement to improve their heat rates; (ii) affected steam EGUs 

can implement to increase generation from lower-emitting 

existing NGCC units in specified amounts,; (iii) all affected 

EGUs can implement to increase generation from new low- or zerocarbon generation sources in specified amounts,; (iv) all 

affected EGUs can implement to reduce their generation in 

specified amounts,; and (v) all affected EGUs operating under a 

standard of performance that incorporates emissions trading can 

 

445 Conditions for the use of these mechanisms under various 

state plans are discussed in section VIII. 
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implement by means of purchasing rate-based emission credits or 

mass-based emission allowances from other affected EGUs through 

trading, since the effect of the purchase would be the same as 

achieving the other listed actions through direct means, and 

(vi) all affected EGUs can implement through other multi-unit 

compliance approaches such as averaging or bubbling.446 

Importantly, viewed from either the source-category 

perspective or the individual-source perspectiveImportantly, 

affected EGUs also have available numerous other measures that 

are not included in the BSER but that could materially help the 

EGUs achieve their emission limits and thereby provide 

compliance flexibility. Examples include, among numerous other 

approaches, investment in demand-side energy efficiency, cofiring with natural gas (for coal-fired steam EGUs), and 

investment in new generating units using low- or zero-carbon 

generating technologies other than those that are part of 

building block 3. 

b. The EPA’s review of measures for determining the BSER. The 

EPA described in the proposal for this rule the analytical 

process by which the EPA determined the BSER for this source 

category. The EPA is finalizing large parts of that analysis, 

 

446 Again, conditions for the use of these mechanisms under 

various state plans are discussed in section VIII. 
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but the EPA is also refining that analysis based on comments 

andas informed by the information and data discussed by 

commenters and our further evaluation. What follows is the EPA’s 

final determination. 

As described in the proposal, to determine the BSER, the 

EPA began by considering the characteristics of CO2 pollution and 

the utility power sector. The characteristics of CO2 pollution 

are discussed at length in the proposed rule and in section II 

above. The salient facts include the pollutant’s global nature, 

which makes the specific location of emission reductions 

unimportant; the need to make large reductions in order to 

protect human health and the environment; and fact that the 

utility power sector is the single largest source category by a 

considerable margin. Not surprisingly, whenever the EPA begins 

the regulatory process under section 111, it initially 

undertakes these same inquiries and then proceeds to fashion the 

rule to fit the industry. For example, in 1979, the EPA 

finalized new standards of performance to limit emissions of SO2

from new, modified, and reconstructed EGUs.447 In assessing the 

 

447 The need for new standards was due in part to findings that 

in 1976, steam electric generating units were responsible for 

“65 percent of the SO2 ... emissions on a national basis.” 44 FR 

33580, 33587 (June 11, 1979). The EPA explained that [u]nder the 

current performance standards for power plants, national SO2
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final SO2 standard, the EPA carried out extensive analyses of a 

range of alternative SO2 standards “to identify environmental, 

economic, and energy impacts associated with each of the 

alternatives considered at the national and regional levels.”448

In identifying the best system underlying the final standard, 

the EPA evaluated “coal cleaning and the relative economics of 

FGD [flue gas desulfurization] and coal cleaning” together as 

the “best demonstrated system for SO2 emission reduction.”449 The 

EPA also took into account the unique features of power 

transmission along the interconnected grid and the unique 

commercial relationships that rely on those features.450

 

emissions are projected to increase approximately 17 percent 

between 1975 and 1995. Impacts will be more dramatic on a 

regional basis.” Id. Thus, “[o]n January 27, 1977, EPA announced 

that it had initiated a study to review the technological, 

economic, and other factors needed to determine to what extent 

the SO2 standard for fossil-fuel-fired steam generators should be 

revised.” Id. at 33587-33588. 448 44 FR 33580, 33582 (June 11, 1979). 449 44 FR 33580, 33593. The EPA considered an investigation by 

the U.S. Department of the Interior regarding the amount of 

sulfur that could be removed from various coals by physical coal 

cleaning. Id. at 33593. 450 See 44 FR 33580, 33597-33600 (taking into account “the amount 

of power that could be purchased from neighboring interconnected 

utility companies” and noting that “[a]lmost all electric 

utility generating units in the United States are electrically 

interconnected through power transmission lines and switching 

stations” and that “load can usually be shifted to other 

electric generating units”). 
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The characteristics of the utility power sector are also 

discussed at length in the proposal and in section II 

above.Similarly, in 1996, the EPA finalized section 111(b) 

standards and 111(d) emission guidelines to ensure that certain 

municipal solid waste (MSW) landfills controlled landfill gases 

to the level achievable through application of the BSER.451 EPA’s 

identification of this BSER was critically influenced by the 

“unique emission pattern of landfills.”452 Unlike “typical 

stationary source[s],” which only generate emissions while in 

operation, MSW landfills can “continue to generate and emit a 

significant quantity of emissions” long after the facility has 

closed or otherwise stopped accepting waste.453 In recognition of 

this salient and unique characteristic of landfills, the EPA set 

 

451 61 FR 9905, 9905 (March 12, 1996). In the rule, the EPA 

referred to the BSER for both new and existing MSW landfills as 

“the best demonstrated system of continuous emission reduction,” 

as well as the “BDT”—short for “best demonstrated technology.” 

See, e.g., id. at 9905–07, 9913–14. 452 61 FR 9905, 9908; see 56 FR 24468, 24478 (May 30, 1991) 

(explaining at proposal that because landfill-gas emission rates 

“gradually increase” from zero after the landfill opens, and 

“gradually decrease” from peak emissions after closure, the 

EPA’s identification of the BSER for landfills inherently 

requires a determination of “when controls systems must be 

installed and when they may be removed”). 

453 See U.S. EPA, Municipal Solid Waste Landfills, Volume 1: 

Summary of the Requirements for the New Source Performance 

Standards and Emission Guidelines for Municipal Solid Waste 

Landfills, Docket No. EPA-453R/96-004 at 1-3 (February 1999). 
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the BSER based on an emission-reducing system of gas collection 

and control that remained in place as long as emissions remained 

above a certain threshold -- even after the regulated landfill 

had permanently closed.454 The EPA acknowledged that for some 

landfills, it could take 50 to 100 years for emissions to drop 

below the cutoff.455

For this rule, we discuss at length in the proposed rule 

and in section II above the unique characteristics of CO2

pollution. The salient facts include the global nature of CO2, 

which makes the specific location of emission reductions 

unimportant; the enormous quantities of CO2 emitted by the 

utility power sector, coupled with the fact that CO2 is 

relatively unreactive, which make CO2 much more difficult to 

mitigate by measures or technologies that are typically utilized 

within an existing power plant; the need to make large 

reductions of CO2 in order to protect human health and the 

environment; and the fact that the utility power sector is the 

single largest source category by a considerable margin. 

We also discuss at length in the proposal and in section II 

above the unique characteristics of the utility power sector.

Topics of that discussion include the physical properties of 

 

454 61 FR 9905, 9907–08. 455 61 FR 9905, 9908. 
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electricity and the integrated nature of the electricity system. 

Here, we reiterate and emphasize that the utility power sector 

is unique in the extent to which it must balance supply and 

demand on a real-time basis, with limited electricity storage 

capacity to act as a buffer. In turn, the need for real-time 

synchronization across each interconnection has led to a 

uniquely high degree of coordination and interdependence in both 

planning and real-time system operation among the owners and 

operators of the facilities comprised within each of the three 

large electrical interconnections covering the contiguous 48 

states. Given these unique characteristics, it is not surprising 

that the North American power system has been characterized as a 

“complex machine.”456 The core function of providing reliable 

electricity service is carried out not by individual electricity 

generating units but by the complex machine as a whole. 

Important subsidiary functions such as management of costs and 

management of environmental impacts are also carried out to a 

great extent on a multi-unit basis rather than an individualunit basis. Generation from one generating unit can be and 

routinely is substituted for generation from another generating 

 

456 S. Massoud Amin, “Securing the Electricity Grid, 40,” The 

Bridge 1, Spring 2010, at 13, 14 (2010);; Phillip F. Schewe, The 

Grid: A Journey Through the Heart of Our Electrified World 1 

(2007). 
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unit in order to keep the complex machine operating while 

observing the machine’s technical, environmental, and other 

constraints and managing its costs. 

The EPA also reviewed broad trends within the utility power 

sector.457 It is evident that, in the recent past, coal-fired 

electricity generation has been reduced, and projected future 

trends are for continued reduction. By the same token, loweremitting NGCC generation and renewable generation have 

increased, and projected future trends are for continued 

increases.458 A survey of integrated resource plans (IRPs), 

included in the docket, shows that fossil fuel-fired EGUs have 

are taking actions to reduce emissions of both non-GHG air 

pollutants and GHGs.459 Some fossil fuel-fired EGUs are investing 

in lower- or zero-emitting generation. In fact, our review 

indicates that the great majority of fossil fuel-fired 

generators surveyed are including new renewable energyRE

resources in their planning. In addition, some fossil fuel-fired 

EGUs are using those measures to replace their higher-emitting 

 

457 These trends are discussed in more detail in sections V.D. 

and V.E. below. 

458 Demand-side energy efficiency measures have also increased, 

and the projected future trends are for continued increase. 

459 The IRPs typically also indicate planned investment in 

demand-side energy efficiency. See memo entitled “Review of 

Electric Utility Integrated Resource Plans” (May 7, 2015) 

available in the docket.
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generation. Some fossil fuel-fired generators appear to be 

reducing their higher-emitting generation without fully 

replacing it themselves. These measures in aggregate result in 

the replacement of higher-emitting generation with lower- or 

zero-emitting generation, reflecting the integrated nature of 

the electricity system. 

The EPA examined state and company programs intended at 

least in part to reduce CO2 from fossil fuel-fired power plants. 

These programs include GHG performance standards established by 

states including California, New York, Oregon, and Washington; 

utility planning approaches carried out by companies in Colorado 

and Minnesota; and renewable portfolio standards (RPS) 

established in more than 25 states.460 They also include marketbased initiatives, such as the Regional Greenhouse Gas 

Initiative (RGGI) and the GHG emissions trading program 

established by the California Global Warming Solutions Act, and 

conservation and demand reduction programs. 

We also examined federal legislative and regulatory 

programs, as well as state programs currently in operation, that 

address pollutants other than CO2 emitted by the power sector. 

These programs include, among others, the CAA Title IV program 

 

460 See 79 FR 34848-34850. 
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to reduce SO2 and NOX, the MATS program to reduce mercury and air 

toxic emissions, and the CSAPR program to reduce SO2 and NOX.461

This analysis demonstrated that, among other measures, the 

application of control technology, fuel-switching, and 

improvements in the operational efficiency of EGUs all resulted 

in reductions in a range of pollutants. These programs also 

demonstrate that replacement of higher-emitting generation with 

lower-emitting generation -- including generation shifts between 

coal-fired EGUs and natural gas-fired EGUs –- and zero-emitting 

generation such asshifts between fossil fuel-fired EGUs and

renewable energy, generation –- also reducereduces emissions. 

Some of these programs also include emissions trading among the 

power plants. 

In this rule, when evaluating the types and amounts of 

measures that the source category can take to reduce CO2

emissions, we have appropriately taken into account the global 

nature of the pollutant and the high degree to which each 

individual affected EGU is integrated into a “complex machine” 

that makes it possible for generation from one generating unit 

to be replaced with generation from another generating unit for 

the purpose of reducing generation from CO2–emitting generating 

 

461 Many of these programs are discussed in section V.B.II. 
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units. We have also taken into account the trends away from 

higher-carbon generation toward lower- and zero-carbon 

generation. These factors strongly support consideration of 

emission reduction approaches that focus on the machine as a 

whole –- that is, the overall source category –- by shifting 

generation from dirtier to cleaner sources in addition to 

emission reduction approaches that focus on improving the 

emission rates of individual sources. 

The factors just discussed that support consideration of 

emission reduction measures at the source-category level 

likewise strongly support consideration of mechanisms such as 

emissions trading and other multi-unit compliance approaches, 

especially since, as discussed in section VIII, the states will 

have every opportunity to design their section 111(d) plans to 

allow the affected EGUs in their respective jurisdictions to 

employ emissions trading or other multi-unit compliance 

approaches to achieve the standards of performance established 

in those plans, and we believe. In short, as discussed in more 

detail in section V.A.2.f. below, it is highly likelyentirely 

feasible for states to establish standards of performance that 

incorporate emissions trading, and it is reasonable to expect

that states will do so. These approaches lower overall costs, 

add flexibility, and make it easier for individual sources to 
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address pollution control objectives. To the extent that the 

purchase of an emissions credit or allowance represents the 

purchase of surplus emission reductions by an emitting source, 

emissions trading represents, in effect, the investment in 

pollution control by the purchasing source, notwithstanding that 

the control activity may be occurring at another source. As 

noted above, the utility power sector has a long history of 

using the “complex machine” to address objectives and 

constraints of various kinds. When afforded the opportunity to 

address environmental objectives on a multi-unit basis, the 

industry has done so. Congress and the EPA have selected 

emissions trading approaches when addressing regional pollution 

from the utility power sector contributing to problems such as 

acid precipitation and interstate transport of ozone and 

particulate matter. Similarly, states have selected market-based 

approaches for their own programs to address regional and global 

pollutants. The industry has readily adapted to that form of 

regulation, taking advantage of the flexibility and 

incorporating those programs into the planning and operation of 

the “machine.” These multi-unit mechanisms are an inherent 

aspect of the way in which the machine is managed to address 

constraints at the source-category level, and they can therefore 

be considered an inherent aspect of emission reduction measures 
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available at the source-category level to address a global 

pollutant such as CO2. Although the choice of which particular 

multi-unit compliance mechanisms to allow is a matter to be 

determined primarily by the states in carrying out their 

obligations to set standards of performance through their 

section 111(d) plans, a plan that did not allow the use of any 

such mechanisms would be so contrary to the integrated nature of 

the industry and so disadvantageous to a state’s own individual 

sources that we, again, view any such plan as extremely unlikely 

and not a possibility that we would be obligated to view as 

constraining the appropriate analysis of the BSER. Further 

reinforcing our conclusion that such an outcome is 

unlikelyFurther reinforcing our conclusion that reliance on 

trading is appropriate is the extensive interest in using such 

mechanisms that states and utilities demonstrated through their 

formal comments and in discussions during the outreach process.

The role of emissions trading is discussed further in section 

V.A.2.f. below.

This entire review has made clear that there are numerous 

measures that, alone or in various combinations, merit analysis 

for inclusion in the BSER. The review has also made clear that 

the global natureunique characteristics of CO2 pollution and the 

unique, interconnected nature ofand interdependent manner in 
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which affected EGUs and other generating sources operate within

the electricity sector make certain types of measures and 

mechanisms available and appropriate for consideration as the 

BSER for this rule that would not be appropriate for other 

pollutants and other industrial sectors. For purposes of this 

discussion, the measures can be categorized in terms of the 

essential characteristics of the four building blocks described 

in the proposal: Measuresmeasures that (i) reduce the CO2

emission rate at the unit,; (ii) substitute generation from 

existing lower-emitting fossil fuel-fired units for generation 

from higher-emitting fossil fuel-fired units,; (iii) substitute 

generation from new low- or zero-emitting generating capacity, 

especially renewable energy, for generation from fossil fuelfired units,; and (iv) increase demand-side energy efficiency to 

avoid generation from fossil fuel-fired units. In the proposal, 

we described our evaluations of various measures in each of 

these categories. In this rule, with the benefit of comments, we 

have refined our evaluation of which specific measures should 

comprise the first three building blocks, and, for reasons 

discussed below, we have determined that the fourth building 

block, demand-side energy efficiency, should not be included in 

the BSER in these guidelines. 
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The measures are discussed more fully below, but it should 

be noted here that because of the integrated nature of the 

utility power sector, -- in which individual EGUs’ operations 

intrinsically depend on the operations of other generators --

coupled with the sector’s high degree of planning and 

reliability safeguards, the measures in the second and third 

categories, (which involve generation shifts to lower- and 

zero-emitting sources,) may occur inthrough several different 

waysactions from the perspective of an individual- source

perspective, all of which are equivalent from the perspective of 

the source- category perspectiveas a whole. First, a higheremitting fossil unit may invest in cleaner generation without 

reducing its own generation, which, in the presence of 

requirements for the source category as a whole to reduce CO2

emissions, would result in less demand for, and therefore 

reductions in generation by, other higher-emitting units. 

Second, a higher-emitting fossil unit may reduce its generation, 

which, in the presence of requirements for the source category 

as a whole to reduce CO2 emissions, would result in increased 

demand for, and therefore increased amounts of, cleaner 

generation. Third, a higher-emitting fossil unit may do both of 

these things, directly replacing part of its generation with 
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investments in lower- or zero-emitting generation.462 In 

addition, for measures in all of the categories, multiple 

mechanisms exist by which an individual affected sourceEGU may 

make these investments, ranging from bilateral investments, to 

purchase of credits representing the emissions-reducing benefits 

of specific activities, to purchase of general rate-based 

emissions credits or mass-based emission allowances, to other 

multi-unit compliance approaches such as averaging or bubbling. 

. As discussed below, mechanisms involving tradable credits or 

allowances are well within the realm of consideration for the 

standards of performance states can choose to apply to their 

EGUs and hence, are entirely appropriate for EPA to consider in 

evaluating these measures in the course of making its BSER 

determination.

c. State establishment of standards of performance and source 

compliance. Before identifying in detail the measures that the 

BSER comprises, it is useful to describe the process by which 

the states establish the standards of performance with which the 

affected EGUs must comply, and the implications offor the 

sources’ needsources that will be operating subject to comply 

for identifying the BSER.those standards of performance. As part 

 

462 The same is true for demand-side energy efficiency measures. 
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of the EPA’s emission guidelines in this rule, and based on the 

BSER, the EPA is identifying CO2 emission performance rates 

and,that reflect the BSER and, pursuant to subsection 111(d)(1), 

requiring states to establish standards of performance for 

affected EGUs in order to implement those rates. States, of 

course, could simply impose those rates on each affected EGU in 

their respective jurisdictions, but we are also offering states 

alternative approaches to carrying out their obligations. For 

purposes of defining these alternatives and facilitating states’ 

efforts to formulate compliance plans encompassing maximum 

flexibilities, we are aggregating themthe performance rates into 

goals for each state. As discussed below, aThe state, in turn, 

is charged withhas the option of setting specific standards of 

performance for its EGUs such that the emission limitations from 

the EGUs operating under those standards of performance together 

meet the performance rates or the state goal. To do this, the 

state must adopt a plan that establishes the EGUs’ standards of 

performance and that implements and enforces those standards. 

AEach state has significant flexibility in several 

respects. For example, as mentioned, a state may impose 

standards of performance on its steam EGU sources and on its 

combustion turbine sources representingthat simply reflect the 

respective CO2 emission performance rates for those subcategories 
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set in the emission guidelines. Alternatively, a state may 

impose standards with differing degrees of stringency on various 

sources, and, in fact, may be more stringent overall than its 

state goal requires. In addition –- and most importantly for 

purposes of describing the BSER -- a state may set standards of 

performance eitheras mass limits (e.g., tons of CO2 per year) 

rather than as emission rates (e.g., lbs of CO2 per MWh) or mass 

limits (e.g., tons of CO2 per year). Under a mass limit approach, 

each affected EGU must retire an allowance for each ton of CO2

emitted.). Moreover, a state may make 

thosethe limits tradable or authorize other multi-unit 

compliance mechanisms (subject to conditions described in 

section VIII below).), whether the limits are rate-based or 

mass-based. The form of the emission limits, whether emission 

rate limits or mass limits, has implications for what specific 

actions that are part of the BSER the individual affected EGUs 

may take to achieve those limits –- that is, the measures that 

comprise the BSER from the individual-source perspective –- as 

well as what specific non-BSER measures are available to the 

individual affected EGUs for compliance flexibility. For 

example, if an individual source chooses to adopt building block 

3 by both investing in lower- or zero-emitting generation and 

reducing its own generation, both those actions will be 
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accounted for in its emission rate and both will therefore help 

the source meet its rate-based limit. If the same individual 

source takes the same actions but is subject to a mass-based 

limit, the action of reducing its generation will directly count 

in helping the source meet its own mass-based limit but the 

action of investing in cleaner generation will not. However, the 

investment in lower-or zero-emitting generation by that source 

and other sources collectively will help the overall source 

category achieve the emission limits consistent with the BSER 

and in doing so will make it easier for that source and other 

sources collectively to meet their mass-based limits. 

In instances where a state establishes standards of 

performance that incorporate emissions trading, the tradable 

credits or allowances can serve as a medium through which 

affected EGUs can invest in any emission reduction measure. 

d. Identification of the BSER measures – the source-category 

perspective.. We firstnow discuss the evaluation of potential 

measures for inclusion in the BSER fromfor the source- category 

perspectiveas a whole. 

(1) Measures that reduce individual affected EGUs’ CO2

emission rates. 

As described in the proposal, the measures that the 

affected EGUs could implement to improve their CO2 emission rates 
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includedinclude a set of measures that the EPA determined would 

result in improvements in heat rate at coal-fired steam EGUs in 

the amount of 6 percent on average, and the EPA proposed that 

this set of measures qualifies as a component of the BSER. As 

described below, inIn this final rule, the EPA concludes that 

those measures do qualify as a component of the BSER, although, 

. However, as described in section V.C. below, based on 

responsive comments and further evaluation, the EPA is narrowing 

the set of has refined its approach to quantifying the emission 

reductions achievable through heat rate improvements and no 

longer includes a separate increment of emission reductions 

attributable to equipment upgrades. Also, rather than evaluating 

the emission reductions available from these types of measures 

that qualifyon a nationwide basis as a component ofin the BSER 

andproposal, the EPA has quantified the emission reductions 

achievable through application of the measuresbuilding block 1

on a regional basis, consistent with the EPA’s proposals to 

better reflect the regional nature of the interconnected 

electrical system and the treatment of the other building blocks 

in this final rule, rather than the nationwide basis used for 

building block 1 in the proposed rule.. As a result of these 

refinements, the EPA is reducingidentifying the amount of 

emission reductionsheat rate improvements achievable on average 
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from heat rate improvement measures atby coal-fired steam EGUs 

toas 4.3 percent for the Eastern Interconnection, 2.1 percent 

for the Western Interconnection, and 2.3 percent for the Texas 

Interconnection. The refinements are based, in significant part, 

on the numerous comments we received on our proposed approaches, 

especially those from states and utilities.

 These heat rate improvement measures include best practices 

such as improved staff training, boiler chemical cleaning;,

cleaning air preheater coils, and use of various kinds of 

software, as well as equipment upgrades such as turbine 

overhauls. These are measures that the owner/operator of an 

affected coal-fired steam EGU may take that would have the 

effect of reducing the amount of CO2 the source emits per MWh. As 

a result, these measures would help the source achieve an 

emission limit expressed as either an emission rate limit or as 

a mass limit. We note again that in the context both of the 

integrated electricity system and of available and anticipated 

state approaches to setting standards of performance, emissions 

trading or other multi-unit compliance approaches could be used 

as mechanisms through which one affected sourceEGU could invest 

in heat rate improvements at another sourceEGU. We discussnote

this aspect below in describing the actions an individual-source 
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perspective of affected EGU can take to implement the BSER and 

discuss it in more detail in section V.A.2.f. 

These heat rate improvements are a low-cost option that fit 

the criteria for the BSER, but alone,except that they lead to 

only small emission reductions for the source category.463 Given 

the magnitude of the environmental problem and projections by 

climate scientists that much larger emission reductions are 

needed from fossil fuel-fired EGUs to address climate change, 

the EPA looked at additional measures to reduce emission rates. 

This reflects our conclusion that, given the availability of 

other measures capable of much greater emission reductions, the

emission reductions limited to this set of heat rate improvement

measures would not meet one of the considerations critical to 

the BSER determination –- the quantity of emissions reductions 

resulting from the application of these measures is too small 

for these measures to be the BSER to theby themselves for this

source category. 

 

463 As further discussed below, if heat rate improvements at 

coal-fired steam EGUs were implemented in isolation, without 

other measures to reduce CO2 emissions, the heat rate 

improvements could lead to increases in competitiveness and 

utilization of the coal-fired EGUs – a so-called “rebound 

effect” - causing increases in CO2 emissions that could partially 

or even entirely offset the CO2 emission reductions achieved 

through the reductions in the amount of CO2 emissions per MWh of 

generation. 
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Specifically, as described in the proposal, the EPA also 

considered co-firing (including 100 percent conversion) with 

natural gas, a measure that presented itself in part because of 

the recent increase in availability and reduction in price of 

natural gas, and the industry’s consequent increase in reliance 

on natural gas.464 The EPA also considered implementation of 

carbon capture and storage (CCS).465 The EPA found that some of 

these co-firing and CCS measures are technically feasible and 

within price ranges that the EPA has found to be cost effective 

in the context of other GHG rules, that a segment of the source 

category may implement these measures, and that the resulting 

emission reductions could be potentially significant. 

However, these co-firing and CCS measures are more 

expensive than other available measures. for existing sources.

This is because the integrated nature of the electricity system 

affords significantly lower cost options, ones that fossil fuelfired power plants throughout the United States and in foreign 

nations are already using to reduce their CO2 emissions. 

 

464 The EPA further addressed co-firing in the NODA.October 30, 

2014 Notice of Data Availability. 79 FR 64549-51. 465 CCS is also sometimes referred to as carbon capture and 

sequestration. 
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The less expensive options include shifting generation to 

existing NGCC units -- an option that has become particularly 

attractive in light of the increased availability and lower 

prices of natural gas -- as well as shifting generation to new 

renewable energy generating units.466 A comparison of the costs 

of converting an existing coal-fired boiler to burn 100 percent 

natural gas compared to the cost of shifting generation to an 

existing NGCC unit illustrates this point. Because an NGCC unit 

burns natural gas significantly more efficiently than an 

affected steam EGU does, the cost of shifting generation from 

the steam EGU to an existing NGCC unit is significantly cheaper 

in most cases than more aggressive emission rate reduction 

measures at the steam EGU. As a result, as a practical matter, 

were the EPA to include co-firing and CCS in the BSER and 

promulgate performance standards accordingly, few EGUs would 

likely comply with their emission standards through co-firing 

and CCS; rather, the EGUs would rely on the lower cost options 

of substituting lower- or zero-emitting generation or, as a 

related matter, reducing generation.467

The 

 

466 Similarly, demand-side energy efficiency measures are lowcost measures. 

467 Many EGUs would also rely on demand-side energy efficiency 

measures. 
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EPA also considered heat rate improvement opportunities at 

oil- and gas-fired steam EGUs and NGCC units and found that the 

available emission reductions would likely be more expensive or 

too small to merit consideration as a material component of the 

BSER. 

 Thus, in reviewing the entire range of control options, it 

became clear that controlling CO2 from affected EGUs at levels 

that are commensurate with the sector’s contribution to GHG 

emissions and thus necessary to mitigate the dangers presented 

by climate change, could depend in part, but not primarily, on 

measures that improve efficiency at the power plants. Rather, 

most of the CO2 controls need to come in the form of those other 

measures that are available to the utility power sector thanks 

specifically to the integrated nature of the electricity system, 

and that involve, in one form or another, replacement of higher 

emitting generation with lower- or zero-emitting generation. 

Although the presence of lower-cost options that achieve 

the emission reduction goals mean that the EPA is not 

identifying either natural gas co-firing or CCS at coal-fired 

steam EGUs, or heat rate improvements at other types of EGUs, as 

part of the BSER, those controls remain measures that some 

affected EGUs may be expected to implement and that as a result, 

will provide reductions that those affected EGUs may rely on to 
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achieve their emission limits or may sell, through emissions 

trading, to other affected EGUs to achieve emission limits (to 

the extent permitted under the relevant section 111(d) plans). 

Another example of a non-BSER measure that an affected EGU in 

certain circumstances could choose to implement is the 

conversion of waste heat from electricity generation into useful 

thermal energy. The EPA further discusses the potential use of 

these non-BSER measures for compliance flexibility below. Other 

measures to reduce emissions that some sources may implement, 

but that the EPA is not identifying as part of the BSER for 

various reasons, and that are also further discussed below, 

include biomass co-firing and conversion of an affected EGU’s 

waste heat to useful thermal energy. 

The EPA’s quantification of the CO2 emission reductions 

achievable through heat rate improvements as a component of the 

BSER (building block 1) is discussed in section V.C. of this 

preamble and in the GHG Mitigation Measures TSD for the CPP 

Final Rule. 

(2) Measures available because of the integrated 

electricity system. 

To achievedetermine the needed emissionBSER that meets the 

expectations and requirements of the CAA, including the 

achievement of meaningful reductions of CO2, the EPA turned next 
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to the set of measures that presented themselves as a result of 

the fact that the operations of individual affected EGUs are 

interdependent on and integrated nature of thewith one another 

and with the overall electricity system. Those are the measures 

in the categories represented in the proposal by building blocks 

2, 3, and 4. This section discusses the components of the BSER 

that relate to building blocks 2 and 3, which the EPA is 

finalizing as components of the BSER. This section also 

discusses the measures comprising the proposed building block 4, 

which the EPA is not including in the BSER in this final rule. 

It bears reiterating that the extent to which the 

operations of individual affected EGUs are integrated nature of 

thewith one another and with the overall electricity system is a 

highly salient and unique attribute of this source category. 

Because of this integration, the individual sources in the 

source category operate through a network that physically 

connects them to each other and to their customers, an 

interconnectedness that is essential to their operation under 

the status quo and by all indications is projected to be 

augmented further on a continual basis in the future to address 

fundamental objectives of reliability assurance and cost 

reduction. In analyzing BSER from a source-category 

perspectiveThis physical interconnectedness exists to serve a 
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set of interlocking regimes that, to a substantial extent, 

determine, if not dictate, any given EGU’s operations on a 

nearly moment-to-moment basis. In analyzing BSER from the 

perspective of the overall source category, because the affected 

EGUs are connected to each other operationally, a combination of 

dispatching and investment in lower- and zero-emitting 

generation allows the replacement of higher-emitting generation 

with lower-emitting and zero-emitting generation (measures in 

building blocks 2 and 3), and thereby reduces emissions while 

continuing to serve load. 

 As noted above, substitution of higher-emitting generation 

for lower- or zero-emitting generation may include reduced 

generation, depending on the specific action taken by the 

individual EGU. Likewise, when incorporated into standards of 

performance, emissions trading or other multi-unit compliance 

mechanisms may be readily used as mechanisms for implementing 

these building blocks. We discuss these aspects below in 

describing the actions that individual-source perspective of 

sources may take to implement the BSER.building blocks. 

 (a) Substituting generation from lower-emitting affected 

EGUs for reduced generation from higher-emitting affected EGUs

(building block 2). . 
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In the proposal, the EPA observed that substantial CO2

emission reductions could be achieved at reasonable cost by 

increasing generation from existing NGCC units and 

commensurately reducing generation from steam EGUs. Because NGCC 

units produce much less CO2 per MWh of generation than steam EGUs 

–- typically less than half as much CO2 as coal-fired steam EGUs, 

which account for most generation from steam EGUs –- this 

generation shift reduces CO2 emissions. We also noted that 

because NGCC units can generate as much as 46 percent more 

electricity from a given quantity of natural gas than a steam 

unit can, generation shifting from coal-fired steam EGUs to 

existing NGCC units is a more cost-effective strategy for 

reducing CO2 emissions from the source category than converting 

coal-fired steam EGUs to combust natural gas or co-firing coal 

and natural gas in steam EGUs. We proposed to find that shifting 

generation consistent with a 70 percent target utilization rate 

(based on nameplate capacity) for NGCC units was feasible and 

should be a component of the BSER. 

FurtherAs described in section V.D. below, analysis 

reflecting consideration of the many comments we received on the 

EPA’s proposal with respect to this issue supports the inclusion 

of generation shifting from higher-emitting to lower-emitting 

EGUs as a component of the BSER. Shifting of generation among 
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EGUs is an everyday occurrence within the integrated operations 

of the utility power sector that is used to ensure that 

electricity is provided to meet customer demands in the most 

economic manner consistent with system constraints. Generation 

shifting to lower-emitting units has been recognized as an 

approach for reducing emissions in other EPA rules such as 

CSAPR. 

The EPA’s analysis continues to show that the magnitude of 

emission reductions included in the proposed rule from 

generation shifting is achievable. SomeIn response to our 

request for comment on the proposed target utilization rates, 

some commenters stated that summer capacity ratings are a more 

appropriate basis upon which to compute a target utilization 

than nameplate capacity ratings used at proposal. AccordinglyWe 

agree, and accordingly, using the same data on historical 

generation as at proposal, we have reanalyzed feasible NGCC 

utilization levels expressed in terms of summer capacity ratings 

and have found that a 75 target utilization rate based on summer 

capacity ratings is feasible. 

The EPA is finalizing a determination that generation shift 

from higher-emitting affected EGUs to lower-emitting affected 

EGUs is a component of the BSER (building block 2). Our 

quantification of the associated emission reductions is 
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discussed in section V.D. of this preamble and in the GHG 

Mitigation Measures TSD for the CPP Final Rule. 

(b) Substituting increased generation from new low- or 

zero-carbon generating capacity for reduced generation from 

affected EGUs (building block 3). . 

Reducing generation from fossil fuel-fired EGUs and 

replacing it with generation from lower- or zero-emitting EGUs 

is another method for reducing CO2 emissions from the utility 

power sector. In the proposal, the EPA identified renewable 

energy (RE) generating capacity and nuclear generating capacity 

as potential sources of lower- or zero-CO2 generation that could 

replace higher-CO2 generation from affected EGUs. 

(i) Increased generation from new RE generating capacity. 

The EPA’s survey of trends and actions already being taken 

in the utility power sector indicated that RE generating 

capacity and generation have grown rapidly in recent years, in 

part because of the environmental benefits of shifting away from 

fossil fuel-fired generation and in part because of improved 

economics of RE generation relative to fossil fuel-fired 

generation. It is clear that increasing the amount of new RE 

generating capacity and allowing the increased RE generation to 

replace generation from fossil fuel-fired EGUs can reduce CO2

emissions from the affected source category. Accordingly, we 
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proposed to include replacement of defined quantities of fossil 

generation by RE generation in the BSER. 

With the benefit of comments, theThe EPA is finalizing the 

determination that substitution of RE generation from new RE 

generating capacity is a component of the BSER but, with the 

benefit of comments responding to the EPA’s proposals on 

regionalization and techno-economic analytic approaches, the EPA

has adjusted the approach for determining the quantities of RE 

generation. As part of the adjustment in approach, we have also 

refocused the quantification solely on generation from new RE 

generating capacity rather than total (new and existing) RE 

generating capacity as in the proposal. Our quantification of 

the RE generation component of the BSER is discussed in section 

V.E. of the preamble and in the GHG Mitigation Measures TSD for 

the CPP Final Rule. 

(ii) Increased and preserved generation from nuclear 

generating capacity. 

In the June 2014 proposal, the EPA also identified the 

replacement of generation from fossil fuel-fired EGUs with 

generation from nuclear units as a potential approach for 

reducing CO2 emissions from the affected source category. We 

proposed to include two elements of nuclear generation in the 

BSER: an element representing projected generation from nuclear 
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units under construction,; and an element representing preserved 

generation from existing nuclear generating capacity at risk of 

retirement, and we took comment on all aspects of these 

proposals. 

Like generation from new RE generating capacity, generation 

from new nuclear generating capacity can clearly replace fossil 

fuel-fired generation and thereby reduce CO2 emissions. However, 

there are also important differences between these types of lowor zero-CO2 generation. Investments in new nuclear capacity are 

very large, “lumpy,” capital-intensive investments and the 

building of nuclear facilities historically has been subject to 

delays and that require substantial risks of non-completion, 

both of which tend to raise costs.lead times. By comparison, 

investments in new RE generating capacity are relatively small 

and low-risk. Based on the small number of new nuclear 

generating projects, it is difficult to ascertain a trend of 

increasing individually smaller and require shorter lead times. 

Also, important recent trends evidenced in RE development, such 

as rapidly growing investment and rapidly decreasing costs, are 

not as clearly evidenced in nuclear generation in the industry. 

These differences create greater uncertainty regarding the 

achievability and cost of generation from new nuclear . We view 

these factors as distinguishing the under-construction nuclear 
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units from RE generating capacity as a replacement, indicating 

that the new nuclear capacity is likely of higher cost and 

therefore less appropriate for fossil fuel-fired generation, two 

important factorsinclusion in determination of the BSER. 

Accordingly, as described in section V.A.3., the EPA is not 

finalizing increased generation from newunder-construction

nuclear capacity as a component of the BSER. 

The EPA is likewise not finalizing the proposal to include 

a component representing preserved existing nuclear generation 

in the BSER. On further consideration, we believe it is 

inappropriate to base the BSER on elements that will not reduce 

CO2 emissions from affected EGUs below current levels. Existing 

nuclear generation helps make existing CO2 emissions lower than 

they would otherwise be, but will not further lower CO2 emissions 

below current levels. Accordingly, as described in section 

V.A.3., the EPA is not finalizing preservation of generation 

from existing nuclear capacity as a component of the BSER. 

(iii) Generation from new NGCC units. 

 New NGCC units –- that is, units that had not commenced 

construction as of January 8, 2014, the date of publication of 

the proposed CO2 standards of performance for new EGUs under 

section 111(b) –- are not subject to the standards of 

performance that will be established for existing sources under 
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section 111(d) plans based on the BSER determined in this final 

rule. In the June 2014 proposed emission guidelines for existing 

EGUs, the EPA solicited comment on whether to include this 

measure in the BSER. Commenters raised numerous concerns, and 

after consideration of the comments, we are not including 

replacement of generation from affected EGUs through the 

construction of new NGCC capacity in the BSER. In this section, 

we discuss the reasons for our approach. 

 The EPA did not include reduced generation from affected 

EGUs achieved through construction and operation of new NGCC 

capacity in the proposed BSER because we expected that the CO2

emission reductions achieved through such actions would, on 

average, be more costly than CO2 emission reductions achieved 

through the proposed BSER measures. However, our determination 

not to include new construction and operation of new NGCC 

capacity in the BSER in this final rule rests primarily on the 

achievable magnitude of emission reductions rather than costs. 

 Unlike emission reductions achieved through the use of any 

of the building blocks, emission reductions achieved through the 

use of new NGCC capacity require the construction of additional 

CO2-emitting generating capacity, a consequence that is 

inconsistent with the long-term need to continue reducing CO2

emissions beyond the reductions that will be achieved through 
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this rule. New generating assets are planned and built for long 

lifetimes –- frequently 40 years or more –-that are likely 

longer than the expected remaining lifetimes of the steam EGUs 

whose CO2 emissions would initially be displaced be the 

generation from the new NGCC units. The new capacity is likely 

to continue to emit CO2 throughout these longer lifetimes, absent 

decisions to retire the units before the end of their planned 

lifetimes or to install CCS technology in the future at 

substantial additional cost. Because of the likelihood of CO2

emissions for decades, the overall net emission reductions 

achievable through the construction and operation of new NGCC 

are less than for the measures including in the BSER, such as 

increased generation at existing NGCC capacity, which would be 

expected to reach the end of its useful life sooner than new 

NGCC capacity, or construction and operation of zero-emitting RE 

generating capacity. We view the production of long-term CO2

emissions that otherwise would not be created as inconsistent 

with the BSER requirement that we consider the magnitude of 

emissions reductions that can be achieved. For this reason, we 

are not including replacement of generation from affected EGUs 

through the construction and operation of new NGCC capacity in 

the final BSER. 
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 Commenters also raised a concern with the interrelation of 

section 111(b) and section 111(d). New NGCC capacity is 

distinguished from the other non-BSER measures discussed above 

by the fact that its CO2 emissions would be subject to the CO2

standards for new EGUs being established under section 111(b). 

Section 111 creates an express distinction between the sources 

subject to section 111(b) and the sources subject to section 

111(d), and commenters expressed concern that to allow section 

111(b) sources to play a direct role in setting the BSER under 

section 111(d) would be inconsistent with congressional intent 

to treat the two sets of sources separately. Section VIII of 

this preamble includes a discussion of ways to address new NGCC 

capacity in the context of different types of section 111(d) 

plans. 

(c) Increasing demand-side energy efficiency to avoid 

generation and emissions from fossil fuel-fired EGUs. 

The final category of approaches for reducing generation 

and CO2 emissions from affected EGUs that the EPA considered in 

the proposal involves increasing demand-side energy efficiency. 

When demand-side energy efficiency is increased, energy 

consumers need less electricity in order to provide the same 

level of electricity-dependent services – e.g., heating, 

cooling, lighting, and use of motors and electronic devices. 
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Through the integrated electricity system, including the 

connection of customers to affected EGUs through the electricity 

grid, reduced demand for electricity, in turn, leads to reduced 

generation and reduced CO2 emissions. Our examination of actions 

and trends underway in the utility power sector confirmed that 

investments in demand-side energy efficiency programs are being 

implemented widely across the sector and that investments are 

increasing. We proposed to include avoidance of defined 

quantities of fossil fuel-fired generation through increased 

demand-side energy efficiency as a component of the BSER 

(proposed building block 4). However, we also took comment on 

which building blocks should comprise the BSER and on our 

determination as to whether each building block met the various 

statutory factors.

Commenters expressed a wide range of views on the proposed 

reliance on demand-side energy efficiency in the BSER. Some 

commenters strongly supported the proposal, with suggestions for 

improvements, while some commenters strongly opposed the 

proposal and took the position that it exceeded the EPA’s legal 

authority. We do not address the merits of these comments here 

because, for the reasons discussed in section V.AB.3.e.c.(8)

below, we are not finalizing the proposal to include avoided 

generation achieved through demand-side energy efficiency as a 
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component of the BSER. However, we note that most commenters 

also supported the use of demand-side energy efficiency for 

compliance whether or not it is used in determining the BSER, 

and we are allowing demand-side energy efficiency to be used for 

that purpose. (We also emphasize that the emission limitations 

reflective of the BSER are achievable even if aggregate 

generation is not reduced through demand-side energy 

efficiency.)

(3) Further analysis to quantify the BSER. 

While the discussion above summarizes how and why the 

components of the BSER were determined in terms of qualitative 

characteristics, it still leaves a wide range of potential 

stringencies for the BSER. As explained in sections V.C., V.D., 

and V.E. below, discussing building blocks 1, 2, and 3 

respectively, the EPA has determined a reasonable level of 

stringency for each of the building blocks rather than the 

maximum possible level of stringency. We have taken this 

approach in part to ensure that there is “headroom” within the 

BSER measures that increasesprovides greater assurance of the 

achievability of the BSER for the source category and for 

individual sources. We note that a feature ofWe believe this 

approach is permissible under the method by which we have 

quantified the degreeCAA. Another aspect of emission limitation 
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achievable through application of the BSER to the two source 

subcategories -– namely, the use of the least stringent CO2

emission performance rate quantifiedour methodology for a given 

source subcategory for any of the three major Interconnections 

as the computing the CO2 emission performance rates, further 

described in section V.A.3.f. and section VI, is that the CO2

emission performance rate for applicable to a given source 

subcategory in all three interconnections reflects the emission 

rate achievable by that source subcategory through application 

of the building blocks in the interconnection where that 

achievable emission rate is the highest (i.e., least 

stringent).468 This aspect of our methodology not only ensures 

that the nationwide CO2 emission performance rates are achievable 

by affected EGUs in all three Interconnections469 –-

 

468 Specifically, the annual CO2 emission performance rates 

applicable to steam EGUs in all three interconnections are the 

annual emission rates achievable by that subcategory in the 

Eastern Interconnection through application of the building 

blocks. Similarly, the annual CO2 emission performance rates 

applicable to stationary combustion turbines in all three 

Interconnections are the annual emission rates achievable by 

that subcategory in the Texas Interconnection for years from 

2022 to 2026, and in the Eastern Interconnection for years from 

2027 to 2030, through application of the building blocks. 

Additional information is provided in the CO2 Emission 

Performance Rate and State Goal Computation TSD in the docket. 

469 Specifically, the respective CO2 emission performance rates 

quantified for the steam EGU subcategory and for the stationary 

combustion turbine subcategory in the Eastern Interconnection 
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interconnections but also provides additional headroom within 

the BSER for sourcesaffected EGUs in the two 

Interconnectionsinterconnections that did not set the CO2

emission performance rates ultimately used. Additional headroom 

within the BSER is available through the use of emissions 

trading or other multi-unit compliance approaches, because the 

final rule does not limit the use of these mechanisms to sources 

within the same Interconnectionsinterconnections. In fact, in 

response to proposals that emerged from the comment record and 

direct engagement with states and stakeholders reflecting their 

strong interest in pursuing multi-state approaches, the 

guidelines include mechanisms for implementing standards of 

performance that fosterincorporate interstate trading, as 

discussed in section VIII. (In addition, as further discussed 

below, the rule also permits section 111(d) plans to allow the 

use of non-BSER measures for compliance in certain 

circumstances, increasing both compliance flexibility and the 

assurance that the emission limitations reflecting application 

of the BSER are achievable.) 

 

are being applied to those subcategories in the Western and 

Texas Interconnections as well. This aspect of the BSER 

quantification methodology is discussed below in section V.A.3 

and section VI. 
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Further, the sets of measures in each of these individual 

building blocks, in the stringency assigned in this rule, meet 

the criteria for the BSER. That is, they each achieve the 

appropriate level of reductions, are of reasonable cost, do not 

impose energy penalties on the affected EGUs and do not result 

in non-air quality pollutants, and have acceptable cost and 

energy implications on a source-by-source basis and for the 

energy sector as a whole. In addition, as explained below, each 

is adequately demonstrated. Importantly, past industry practice 

and current trends strongly support each of the building blocks, 

as do federal and state pollution control programs that require 

or result in similar measures. 

For example, all of the measures in building blocks 2 and 3 

have been implemented for decades, initially for reasons 

unrelated to pollution control, then in recent years in order to 

control non-GHG air pollutants, and more recently, for purposes 

of CO2-emission control by states and companies. Moreover, 

Congress itself recognized in enacting the acid rain provisions 

of CAA Title IV that renewable energy measures reduce CO2 from 

affected EGUs. In addition, the EPA has relied on the measures 

in building blocks 2 and 3 in other rules. It should also be 

noted that combinations of the building blocks also meet the 

criteria for the BSER, as described below. 
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e. Identification ofIt should also be noted that building 

blocks 2 and 3 also meet the criteria for the BSER measures – 

the in combination with one another and with building block 1, 

as described below. 

e. Actions that individual-source perspective. affected EGUs 

could take to apply or implement the building blocks. We now 

turn to a summary of the evaluation of potential BSER measures 

from theor actions that individual-source perspective. EGUs 

could take to apply or implement the building blocks and that 

are therefore, in that sense, part of the BSER. 

 (1) Improvement in CO2 emission rate at the unit. 

An affected EGU may take steps to improve its CO2 emission 

rate as discussed above underfor the source- category 

perspective. Although the only actions in this category 

identified for inclusion inas a whole. As discussed in section 

V.C., the BSER are record makes clear that coal-fired steam EGUs 

can make, and have made, heat rate improvements at coal-fired 

steam EGUs, if a particular affected EGU found that its 

circumstances made some other actions in the category relatively 

attractive –- for example, heat rate improvements at other types 

of EGUs, co-firing of natural gas, or retrofit of CCS –- the EGU 

could pursue those improvements.to a greater or lesser degree, 

resulting in reductions in CO2 emissions. The resulting 
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improvementsimprovement in thean EGU’s CO2 emission rate would 

help the EGU achieve an emission limit imposed in the form of an 

emission rate, and would also help. If the EGU achieve anEGU’s

emission limit is imposed in the form of a mass limit 

ifstandard, the heat rate improvement would also lower the EGU’s 

mass emissions provided that the EGU held the EGU did not 

increaseamount of its generation constant or increased its 

generation by a largersmaller percentage than the percentage of 

its efficiency improvement. Under a mass-based standard that 

incorporates emission trading, an EGU that improves its heat 

rate improvement.would need fewer emission allowances for each 

MWh of generation whatever level of generation it chose to 

produce. 

(2) Actions to implement measures in building blocks 2 and 

3. 

Viewing the BSER from the perspective of an individualsource perspective, because of EGU, there are several ways that 

affected EGUs can access the measures in building blocks 2 and 

3, thanks to the integrated nature of the electricity system, 

coupled with the system’s high degree of planning and 

reliability mechanisms, there are several ways that affected 

EGUs can access the measures in building blocks 2 and 3.. The 

affected EGUs can: (a) invest in lower- or zero-emitting 
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generation, which will lead to reductions in higher-emitting 

generation at other units in the integrated system; (b) reduce 

their generation, which in the presence of emission reduction 

requirements applicable to the source category as a whole will 

have the effect of increasing demand for, and thereby 

incentivizingincentivize investment in, the measures in the 

building blocks elsewhere in the integrated system; or (c) both 

invest in the measures in the building blocks and reduce their 

own generation, effectively replacing their generation with 

cleaner generation.470 The availability of these options is 

further enhanced where the individual EGU is operating under a 

standard of performance that incorporates emissions trading.

(a) Investment in measures in building blocks 2 and 3. 

An affected EGU may take the following actions to invest in 

the measures in building blocks 2 and 3: For building block 2, 

the owner/operator of a steam EGU may increase generation at an 

existing NGCC unit it already owns, or one that it purchases or 

invests in. In addition, the owner/operator may, through a 

bilateral transaction with an existing NGCC unit, pay the unit 

to increase generation, and purchaseacquire the CO2-reducing 

 

470 These same methods are available for demand-side energy 

efficiency measures. 
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effects of that increased generation as emission rate creditsin 

the form of a credit, as discussed below. 

Similarly, for building block 3, an owner/operator of an 

affected EGU may build, or purchase an ownership interest in, 

new renewable energy generating capacity and purchaseacquire the 

CO2-reducing effects of that increased generation. Alternatively, 

an owner/operator may, through bilateral transactions, purchase 

the CO2-reducing effects of that increased generation from 

renewable generation providers., again, in the form of a credit. 

In case of an investment in either building block 2 or 

building block 3 by a unit subject to a rate-based form of CO2

performance standard, the section 111(d) planit would need to 

provide –- and we expect that states would do so in theirbe 

reasonable for state plans -- a mechanism by which theto 

authorize affected unit could account for the emissions-reducing 

benefit of the investment when computing its emission rate for 

purposes of determining compliance with the performance 

standard. The mechanism could involve use ofEGUs to use an 

approved and validated instrument such as an “emission rate 
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credit” (ERC) representing the emissions-reducing benefit of the 

investment or could involve an approved averaging arrangement.471 

When combined with reduced generation, either at the 

affected EGU or elsewhere in the interconnected system, the 

types of actions listed above would be fully equivalent to 

building blocks 2 and 3 when viewed from the source-category 

perspective. Therefore, of the menu of these actions, including 

reduced generation, is appropriate for inclusion in the BSER. 

That is, if a state assigns tooverall source category. Thus, a 

source could achieve a standard of performance that is the same 

asidentical to the applicable CO2 emission performance rate in 

the EPA emission guidelines, or the mass limit equivalent, the 

source could achieve the limit through implementation of the 

actions described above for building blocks 2 and 3, along with 

the actions described further above for building block 1. 

By the same token, for the demand-side energy measures that 

the EPA proposed as building block 4, an owner/operator of an 

affected EGU may implement demand-side energy efficiency 

programs directly or hire contractors or energy service 

companies to do so, and claim the resulting emission rate 

 

471 Criteria for issuance of valid emission rate credits and for 

tracking credits after issuance are discussed in section VIII 

below and in the Rate-based Program Accounting TSD for the CPP 

Final Rule..
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credits. The owner/operator may also engage in bilateral 

transactions with distribution utilities that already implement 

demand-side energy efficiency programs and pay them to implement 

such a program.472 When combined with reduced generation, either 

at the affected EGU or elsewhere in the interconnected system, 

these types of actions would be fully equivalent to proposed 

building block 4 when viewed from a source-category perspective. 

As noted elsewhere, the EPA has determined not to include 

proposed building block 4 in the BSER in this final rule. 

However, the measures in building block 4 would still be 

available for compliance purposes to the extent permitted under 

state plans, and the list of actions above indicates the range 

of ways through which affected EGUs could access this resource. 

The EPA anticipates that in instances where section 111(d) 

plans provide for the use of instruments such as emission rate 

credits as a mechanism to facilitate use of these measures, 

 

472 For affected EGUs subject to a rate-based form of CO2 

performance standard, the section 111(d) plan would need to 

provide a mechanism by which the affected unit could account for 

the emissions-reducing benefit of the investment when computing 

its emission rate for purposes of determining compliance with 

the performance standard. This mechanism could be similar to the 

mechanism required with respect to investments in building 

blocks 2 and 3, although use of demand-side energy efficiency 

measures involves some additional considerations as well. 

Further discussion can be found in section VIII below and in the 

Rate-based Program Accounting TSD for the CPP Final Rule. 
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organized markets will develop so that owner/operators of 

affected EGUs that have invested in measures eligible for the 

issuance of emission rate credits will be able to sell those 

credits and other affected EGUs will be able to purchase them. 

Such markets have developed for other instruments used for 

emissions trading purposes. For example, liquid markets for SO2

allowances developed rapidly following the implementation of 

Title IV of the 1990 Clean Air Act Amendments establishing the 

Acid Rain Program. Members of Congress and industry had 

expressed concern during the legislative debate that the lack of 

a liquid SO2 allowance market would create challenges for 

affected sources that needed to acquire allowances to meet their 

compliance obligations. Congress added statutory provisions to 

ensure that, should a market not develop, sources could purchase 

needed allowances directly from the EPA. In fact, these 

provisions went unused because a liquid market for allowances 

did develop very quickly. Sources engaged in allowance 

transactions directly with other sources as they sought to lower 

compliance costs. Market intermediaries offered services to 

sources to match allowance buyers and sellers and helped sources 

understand their compliance options. Trade associations worked 

with members to develop standardized contracts and other tools 

to facilitate allowance transactions, thereby reducing 
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transaction costs. Similar developments have occurred in statelevel renewable portfolio standard programs.473

If states choose to allow through their section 111(d) 

plans a mechanismmechanisms or standards of performance

involving instruments such as emission rate credits –- and, as 

indicated above,(ERCs), the record strongly indicatesEPA 

believes that they can be expected to -- there is no reason to 

expect a shortage of would be an ample supply of such credits, 

for several reasons. First, as discussed in sections V.D. and 

V.E., the EPA has established the stringencies for building 

blocks 2 and 3 at levels that are reasonable and not at the 

maximum achievable levels, providing headroom for investment in 

the measures in these building blocks beyond the amounts 

reflected in the CO2 emission performance rates reflecting 

application of the BSER. In addition, if emission limits are set 

at the CO2 emission performance rates, affected sourcesEGUs in 

the Western and Texas Interconnectionstwo of the three 

 

473 The emergence of markets under the Acid Rain Program and 

other environmental programs where trading has been permitted, 

as well as state and industry support for the development of 

markets under states’ section 111(d) plans, is discussed in a 

recent report by the Advanced Energy Economy Institute. AEE 

Institute, Markets Drive Innovation – Why History Shows that the 

Clean Power Plan Will Stimulate a Robust Industry Response (July 

2015), available at https://www.aee.net/aeei/initiatives/epa111d.html#epa-reports-and-white-papers. 
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interconnections on average do not need to implement the 

building blocks to their full available extent in order to 

achieve their emission limits (because the performance rates for 

sources in these regionseach source category are set at the less 

stringentemission rates determined to be reasonable for 

achievable by that source subcategory through application of the 

BSER to sourcesbuilding blocks in the Eastern 

Interconnection.interconnection where that achievable emission 

rate is the highest), providing further opportunities in those 

interconnections to generate surplus emission reductions that 

could be used as the basis for issuance of ERCs. Further, to the 

extent that section 111(d) plans take advantage of the latitude 

the final rule’s flexibility to allow the use of multistateguidelines provide for states to set standards of 

performance incorporating emissions trading or other multi-unit 

compliance approacheson an interstate basis among 

sourcesaffected EGUs in different 

Interconnectionsinterconnections, all sources can take advantage 

of the headroom available in other 

Interconnectionsinterconnections. As a result, significant 

amounts of existing NGCC capacity and potential for renewable 

energy remain available to serve as the basis for issuance of 

creditsERCs for all affected EGUs in both source subcategories 
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to rely on to achieve their emission limits. BecauseBecause we 

recognize the ready availability to states of standards of 

performance that incorporate emissions trading –- and because 

such standards can easily encompass interstate trading -- this 

rule includes by express design a variety of options that states 

and utilities can select to pursue interstate compliance regimes 

that mirror the interconnected operation of the electricity 

system. As a result, the EPA believes that it is reasonable to 

anticipate as highly likely that a virtually nationwide 

emissionemissions trading market for compliance will emerge, and 

that these creditsERCs will be effectively available to any 

sourceaffected EGU wherever located, as long as its state plan 

authorizes their purchase and use in meeting the standard of 

performance the state establishes.emissions trading among 

affected EGUs.474

 

474 There is a theoretical possibility – which we view as 

extremely unlikely – that the affected EGUs in a given state or 

group of states that has chosen to pursue a technology-specific 

rate-based approach could have insufficient access to ERCs 

because of the choices of certain other states to pursue massbased or blended-rate approaches. We view this as very unlikely 

in part because of the conservative assumptions used in 

calculating the emission reductions available through the 

building blocks and the broad availability of non-BSER emission 

reduction opportunities, such as energy efficiency, that will 

generate ERCs. If such a situation arises, and the state or 

states implementing the technology-specific rates does not have, 

within the state or states, sufficient ERC-generation potential 
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It should also be noted that although in a state that sets 

emission limits in a rate-based form the measures in building 

blocks 2 and 3 can be taken into account directly in 

computations to determine whether an individual affected EGU has 

achieved an emissions limit set in anits emission ratelimit, in 

a state that sets emission limits in a mass-based form if, as 

expected, the state chooses to authorize a mechanism for doing 

 

to match their compliance requirements, the EPA will work with 

the state or states to ensure that there is a mechanism that the 

state or states can include in their state plans to allow the 

affected EGUs in the state or states to generate additional ERCs 

where the state or states can demonstrate that the ERCs do not 

represent double-counting under other state programs. One 

potential mechanism would be to assume for purposes of 

demonstrating compliance with their standards of performance 

that the generation replacing any reductions in generation at 

those affected EGUs that was not paired with verified ERCs came 

from existing NGCC units in other states from which ERCs were not 

accessible. In other words, any reductions in fossil steam 

generation from 2012 levels in a state or states that was 

implementing technology-specific rates that could not be matched 

by increases in NGCC generation or by ERCs from zero-emitting 

sources, and for which it could be demonstrated that no further 

ERCs can be procured, could generate building block 2 ERCs as if 

that level of displaced generation were NGCC generation. A 

demonstration that no further ERCs are procurable would have to 

include demonstrations that the capacity factor of all NGCC 

generation in the state or states was expected to be greater 

than 75 percent and that further deployment of renewable 

energywould go beyond the amounts found available in the BSER. 

States could distribute these additional ERCs to ensure 

compliance by affected EGUs. Before such ERCs could be created 

by a state or states, a framework would have to be submitted to 

the EPA for approval including documentation of the levels of 

fossil steam and NGCC generation in the state or states, a 

demonstration that no further ERCs are accessible, and the total 

amount of building block 2 ERCs to be created. 
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so, theythese measures are not taken into account directly in 

computations to determine whether an individual affected EGU has 

achieved an emissionsits emission limit set in a mass-based 

form. However, by reducing generation and therefore CO2 emissions 

from the group of affected EGUs within a region, in a state with 

mass-based limits implementation of these measures 

facilitatefacilitates the ability of the individual EGUs within 

the region to achieve mass-basedtheir limits by choosing to 

reduce their own generation and emissions. 

(b) Reduced generation. 

In addition, the owner/operator of an affected EGU may help 

itself meet its emission limit by reducing its generation. If 

the owner/operator reduces generation and therefore the amount 

of its CO2 emissions, then, if the affected EGU is subject to an 

emission rate limit, the owner/operator will need to implement 

fewer of the building block measures, e.g., buy fewer emission 

rate credits, to achieve its emission rate; and if the affected 

EGU is subject to a mass emissionsemission limit, the 

owner/operator will need fewer mass allowances. As discussed 

below, at the levels that the EPA has selected for the BSER, 

reduced generation at higher-emitting EGUs does not decrease the 

amount of electricity available to the system and end users 
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because lower-emitting (or zero-emitting) generation will be 

available from other sources.

An owner/operator may take actions to ensure that it 

reduces its generation. For example, it may accept a permit 

restriction on the amount of hours that it generates. In 

addition or alternatively, it may represent the cost of 

additional emission credits or allowances that would be required 

due to incremental generation as an additional variable cost 

that increases the total variable cost considered when dispatch 

decisions are made for the unit. 

Because of the integrated nature of the electricity system, 

combined with the system’s high degree of planning and 

reliability safeguards, as well as the long planning horizon 

afforded by this rule, individual affected steam EGUs,EGUs can 

implement the building blocks by reducing generation to achieve 

their emission performance standards.475 Individual affected 

steam EGUs can reduce their generation in the amounts of 

building blocks 2 and 3, andwhile individual affected NGCC 

units, reducing can reduce their generation in the amountsamount

 

475 For purposes of this discussion, we assume that coal-fired 

steam generators also implement building block 1 measures so 

that they will implement the full set of measures needed to 

achieve their emission limit. 
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of building block 3, can in aggregate achieve the requisite 

level of reductions in generation adequate to achieve emission 

limits reflecting the BSER.476. With emission limits for the 

source category as a whole in place, the resulting reduction in 

supply of higher-emitting generation will incentivize additional 

utilization of existing NGCC capacity, and the resulting 

reduction in overall fossil fuel-fired generation will 

incentivize investment in additional renewable energy generating 

capacity, and the integrated system’s response to these 

incentives will ensure that there will be sufficient electricity 

generated to continue to meet the demand for electricity 

services will continue to be met.

(c) Emissions trading. 

As described above, viewed from the perspective of the 

source- category perspective, as a whole, it is reasonable for 

our analysis of the BSER implicitly includesto include an 

element of source-category-wide multi-unit compliance, which at 

the level of implementation could be realized throughimplemented 

via a state-set standard of performance incorporating emissions 

trading, under which EGUs could engage in trading of rate-based 

 

476 For purposes of this discussion, we assume that coal-fired 

steam generators also implement building block 1 measures so 

that they will implement the full set of measures needed to 

achieve their emission limit. 
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emission credits or mass-based emission allowances. Indeed, as 

we have already observed, the comment record provides ample 

evidence that By the same token, viewed from the perspective of 

an individual EGU, consideration of the ready availability to 

states themselves anticipate establishing standards of 

performance that allow the use of emissions trading or other 

multi-unit compliance approaches, and the guidelines’ reliance 

on state level goals as of the basis on which states must 

demonstrate compliance can be expected to be the cornerstone on 

which states construct plans that rely, at least implicitly, on 

multi-unit compliance. The inclusion in the guidelines –- at the 

request of states and utilities –- of provisions that allow 

states to create “trading ready” plans for the purpose of 

facilitating interstate emissions trading or other multi-unit 

compliance approaches, as discussed in section VIII, is further 

evidence that utilities as well as states anticipateopportunity 

to establish standards of performance that rely on emissions 

trading or other multi-unit compliance approaches. Emissions 

trading, whether implemented through rate-based or mass-based 

standards of performance, enables the building blocks to be 

implemented by the EGUs with the lowest costs, and the overall 

costsincorporate emissions trading is integral to be distributed 

throughout the existing source universe, such that costs can be 
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reduced for the source category and for many individual affected 

EGUs. By the same token, viewed from the our analysis. 

Accordingly, our assessment of the actions available to 

individual-source perspective, EGUs for achieving standards of 

performance reflecting the BSER includes the purchase of ratebased emission credits or mass-based emission allowances,

because one of the things an affected EGU can do to achieve its 

emission limit is to buy a credit or an allowance from another 

affected EGU that has over-complied. The use of purchased 

credits or allowances would have to be authorized, of course, in 

the purchasing sources’EGUs’ states’ section 111(d) plans and 

would have to meet conditions set out for such approaches in 

section VIII below, but the record provides ample evidence that 

such authorization can be expected and section VIII addresses 

the necessary conditions extensively.. The role of emissions 

trading in the BSER analysis is discussed further in section 

V.A.2.f. below. 

It has been recognized for decades, starting with the Acid 

Rain SO2 trading program under Title IV of the CAA, that the 

availability of emissions trading facilitates the implementation 

of control measures and reduces their cost. For example, in this 

rule, while each affected EGU could, in theory, implement each 

of the building blocks, some affected EGUs would face lower 
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Page 477 of 2153

costs in doing so than others, at least for individual building 

blocks and likely for the combination of all three building 

blocks as well. Thus, the EPA expects that affected EGUs for 

whom application of one or more building blocks is relatively 

less expensive may overcomply. As a result, to the extent that 

the applicable section 111(d) plans permit emissions trading, 

the EGUs that overcomply would have rate-based emission credits 

or mass-based emission allowances to sell, which would enable 

affected EGUs for whom compliance is relatively more expensive 

to achieve their emission limits by purchasing those credits or 

allowances. Any of the building blocks could be the basis for 

overcompliance and consequent creation of a surplus of credits 

or allowances. When an EGU obtains an emission rate-based credit 

or mass-based allowance from another EGU, that is effectively 

the same as investing directly in the control measures that 

created the surplus, such that when emissions trading is 

permitted, all of the building blocks are effectively available 

to all affected EGUs through “cross investment” using emission 

credits or allowances. EGUs currently operating under a variety 

of pollution control programs incorporating emissions trading 

have effectuated such investments and actions through the 

purchase of surplus emissions reductions, in that the purchase 

price represents investment in other EGUs’ pollution reduction 
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Page 478 of 2153

actions that encompass a range of activity, including the use of 

cleaner generation. 

(d) Other multi-unit compliance approaches. The set of 

multi-unit compliance approaches inherent in the BSER because of 

the global nature of the CO2 pollutant and the interconnected 

nature of the electricity system is broader than just the 

emissions trading approaches described above. In addition to 

emissions trading approaches -– in essence, multi-unit 

compliance approaches that use tradable emission credits or 

allowances as marketable instruments to facilitate coordination 

among the sets of participating units -– it is possible for 

section 111(d) plans to provide for the use of multi-unit 

approaches that do not involve tradable instruments. Although 

potentially somewhat less flexible than emissions trading 

approaches, other types of multi-unit compliance approaches 

generally offer the same ability for affected sources with 

lower-cost emission-reduction opportunities to overcomply and to 

make surplus emission reductions available for use by affected 

sources with higher-cost emission-reduction opportunities. Thus, 

like emissions trading, these approaches effectively make it 

possible for affected EGUs to invest in emission reduction 

measures that are physically implemented at other locations, 
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consistent with longstanding practice in the interconnected 

electricity system. 

For units subject to rate-based performance standards, 

multi-unit compliance approaches other than emissions trading 

approaches would generally be “averaging” approaches where 

multiple units would combine their monitored emissions and 

generation (as well as any authorized emission rate credits 

representing the emissions-reducing benefits of investments in 

specific emissions-reducing activities) in order to compute a 

combined emission rate that would, in turn, be compared to a 

combined rate-based performance standard. For units subject to 

mass-based performance standards, such approaches would 

generally be “aggregation” approaches where multiple units would 

combine their monitored emissions in order to compute a combined 

total mass of emissions that would, in turn, be compared to a 

combined mass-based performance standard.477 The use of averaging 

or aggregation approaches would have to be authorized in the 

111(d) plans covering all the participating affected sources and 

would have to meet conditions set out for such approaches in 

section VIII below. 

 

477 Approaches that aggregate emissions of multiple units at a 

single facility are commonly known as “bubbling” approaches. 
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ff. The role of emissions trading. In making its BSER 

determination here, the EPA examined a number of technologies 

and emission reduction measures that result in lower levels of 

CO2 emissions and evaluated each one on the basis of the several 

criteria on which the EPA relies in determining the BSER. In 

contrast to section 111(b), however, section 111(d)(1) obliges 

the states, not the EPA, to set standards of performance for the 

affected EGUs in order to implement the BSER. Accordingly, with 

respect to each measure or control strategy under consideration, 

the EPA also evaluated whether or not the states could establish 

standards of performance for affected EGUs that would allow 

those sources to adopt the measure in question. In this case, 

the EPA identified a host of factors that persuaded us that 

states could –- and, in fact, may be expected to -- establish 

standards of performance that incorporate emissions trading.478

These wide-ranging factors include (i) the global nature of the 

air pollutant in question – i.e., CO2; (ii) the transactional 

nature of the industry; (iii) the interconnected functioning of 

the industry and the coordination of generation resources at the 

 

478 As an alternative to authorizing trading that would still 

provide a degree of multi-unit flexibility, a state could choose 

in its state plan to give an owner of multiple affected EGUs 

flexibility regarding how the owner distributes any credits or 

allowances it acquires among its affected EGUs. 
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level of the regional grid; (iv) the extensive experience that 

states – and EGUs – already have with emissions trading; and (v) 

material in the record demonstrating strong interest on the part 

of many states and affected EGUs in using emissions trading to 

help meet their obligations.479 

 

479 Numerous states submitted comments urging the EPA to allow 

states to develop trading programs, as suggested in the 

proposal, including interstate trading programs. They include, 

for example, Alabama (EPA should develop and issue guidelines 

that allow options for multi‐state plans and interstate credit 

trading programs, comment 23584), California (EPA should provide 

flexibility for allowance trading programs to be integrated into 

state plans, comment 23433), Hawaii (supports use of emission 

credit trading with other entities to achieve compliance, 

comment 23121), Massachusetts (EPA should explore possibility of 

hosting a third‐party emissions trading bank that can allow 

states interested in allowance trading to plug and play in to a 

wider, more cost‐effective market, comment 31910), Michigan 

(supports emissions trading programs, comment 23987), Minnesota 

(develop model trading rule that states could incorporate by 

reference as part of plan and automatically be included in 

multi-state mass trading program, comment 23987), North Carolina 

(EPA should examine a system of banking and trading for energy 

efficiency, comment 23542), Oregon (EPA should expand the 

explicit options for multi‐state plans beyond cap‐and-trade, 

comment 20678), Washington (supporting trading, comment 22764), 

Wisconsin (requesting EPA to develop a national trading program, 

Post‐111(d) Proposal Questions to EPA WI Questions for 7/16 Hub 

call). 

In addition, several groups of states supported trading 

programs: Georgetown Climate Center (a group of state 

environmental agency leaders, energy agency leaders, and public 

utility commissioners from California, Colorado, Connecticut, 

Delaware, Illinois, Maine, Maryland, Massachusetts, Minnesota, 

New Hampshire, New York, Oregon, Rhode Island, Vermont, and 

Washington) (“We believe states should have maximum flexibility 

to determine what kinds of collaborations might work for them. 

These could include submission of joint plans, standardized 
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approaches to trading renewable or energy efficiency credits.... 

We also encourage EPA to help facilitate such interstate 

agreements or multi-state collaborations by working with states 

to either identify or provide a platform or framework that 

states may elect to use for the tracking and trading of avoided 

generation or emissions credits due to interstate efficiency or 

renewable energy.” comment 23597, at 39-40); Regional Greenhouse 

Gas Initiative (including Connecticut, Delaware, Maine, 

Maryland, Massachusetts, New Hampshire, New York, Rhode Island, 

Vermont) (“[E]very serious proposal to reduce carbon emissions 

from EGUs, from proposed US legislation to programs in place in 

California and Europe, has identified allowance trading as the 

best approach.” Comment 22395 at 7-8); Western States Center for 

New Energy Economy (including Arizona, California, Colorado, 

Idaho, Montana, Nevada, Oregon, South Dakota, Utah, Washington) 

(“Some degree of RE and EE credit trading among states may 

support compliance, even in the absence of a comprehensive 

regional plan. Therefore, EPA should support approaches which 

allow states flexibility to allocate credit for these zerocarbon resources, along with approaches which allow states to 

reach agreements on the allocation of carbon liabilities. This 

includes ensuring that existing tracking mechanisms for 

renewable energy in the West, such as the Western Renewable 

Energy Generation Information System (WREGIS), are compatible 

with the final proposal.” Comment 21787 at 5); Midcontinent 

States Environmental and Energy Regulators (including Arkansas, 

Illinois, Michigan, Minnesota Missouri, Wisconsin) (EPA should 

also provide states with optional ... systems (or system) for 

tracking emissions, allowances, reduction credits, and/or 

generation attributes that states may choose to use in their 

111(d) plans,” comment 22535 at 3). 

In addition, trading programs were supported by, among 

others, a group of Attorneys General from 11 states and the 

District of Columbia. Comment 25433 (Attorneys General from New 

York, California, Connecticut, Maine, Maryland, Massachusetts, 

New Mexico, Oregon, Rhode Island, Vermont, Washington, District 

of Columbia, and New York City Corporation Counsel). 

Numerous industry commenters also supported trading, 

including Alliant Energy Corporate Services, Inc. (comment 

22934), Calpine (comment 23167), DTE Energy (comment 24061), 

Exelon (comment 23428 and 23155), Michigan Municipal Electric 

Association (MMEA) (comment 23297), National Climate Coalition 

(comment 22910), Pacific Gas and Electric Company (comment 
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The states’ and EGUs’ interest in emissions trading is 

rooted in the well-recognized benefits that trading provides. 

The experience of multiple trading programs over many years has 

shown that some units can achieve emission reductions at lower 

cost than others, and a system that allows for those lower-cost 

reductions to be maximized is more cost-effective overall to the 

industry and to society. Trading provides an affected EGU other 

options besides direct implementation of emission reduction 

measures in its own facility or an affiliated facility when 

lower-cost emission reduction opportunities exist elsewhere. 

Specifically, the affected EGU can cross-invest, that is, invest 

in actions at facilities owned by others, in exchange for ratebased emission credits or mass-based emission allowances. 

Through cross-investment, trading allows each affected EGU to 

access the control measures that other affected EGUs decide to 

implement, which in this case include all the building blocks as 

well as other measures. 

 

23198), Western Power Trading Forum (WPTF) (comment 22860). 

Environmental advocates also supported trading, including Clean 

Air Task Force (comment 22612), Environmental Defense Fund 

(comment 23140), Institute for Policy Integrity, New York 

University School of Law (comment 23418). 
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Accordingly, our analysis of the measures under 

consideration in our BSER determination reflected the wellfounded conclusion that it is reasonable for states to 

incorporate emissions trading in the standards of performance 

they establish for affected EGUs and that many, if not all, 

would do so.480

Whether viewed from the perspective of an individual EGU or 

the source category as a whole, emissions trading is thus an 

integral part of our BSER analysis. Again, we concluded that 

this is reasonable given the global nature of the pollutant, the 

transactional and interconnected nature of this industry, and 

the long history and numerous examples demonstrating that, in 

this sector, trading is integral to how regulators have 

established, and sources have complied with, environmental and 

similar obligations (such as renewable energy standards) when it 

was appropriate to do so given the program objective. The 

reasonableness is further demonstrated by the numerous comments 

(some of which are noted above) from industry, states, and other 

stakeholders in this rulemaking that supported allowing states 

 

480 As discussed in the Legal Memorandum, the EPA has promulgated 

other rulemakings, including the transport rulemakings -- the 

NOx SIP Call and CAIR, which required states to submit SIPs, and 

CSAPR, which allows SIPs -- on the premise of interstate 

emission trading. 
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to adopt trading programs to comply with section 111(d) and 

encouraged EPA to facilitate trading across state lines through 

the use of trading-ready state plans. The EPA’s reliance on 

trading in its BSER determination does not mean, however, that 

states are required to establish trading programs (just as 

states are not required to implement the building blocks that 

comprise BSER). Nor does it mean that trading is the only 

transactional approach that we could have considered in setting 

the BSER or that states could use to effectuate the building 

blocks were they to decide that they did not want to take on the 

responsibility of running a trading program. Rather, it is 

simply a recognition of the nature of this industry and the long 

history of trading as an important regulatory tool in 

establishing regulatory regimes for this industry and its 

reasonable availability to states in establishing standards of 

performance. 

As an initial matter, trading is permissible for these 

emission guidelines because CO2 is a global pollutant; the 

location of its emission does not affect the location of the 

environmental harm it causes. For CO2, it is the total amount of 

emissions from the source category that matters, not the 

specific emissions from any one EGU. The fact that trading 

allows sources to shift emissions from one location to another 
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does not impede achievement of the environmental goal of 

reducing CO2 pollution. In its character as a pollutant whose 

impacts extend beyond local areas, CO2 pollution resembles to 

some extent the regional SO2 pollution that Congress chose to 

address with the emissions trading program enacted in Title IV 

of the 1990 CAA Amendments. The argument in support of trading 

approaches is even stronger for CO2 pollution, whose adverse 

effects are global rather than merely regional like the SO2

emissions contributing to acid precipitation. 

Further, as discussed elsewhere in the preamble, the 

utility power sector – and the affected EGUs and other 

generation assets that it encompasses – has a long history of 

working on a coordinated basis to meet operating and 

environmental objectives, necessitated and facilitated by the 

unique interconnectedness and interdependence of the sector. 

That history includes joint dispatch for economic and 

reliability purposes, both within large utility systems and in 

multi-utility power pools that have evolved into RTOs; joint 

power plant ownership arrangements; and long-term and short-term 

bilateral power purchase arrangements. More recently, the 

sector’s history also includes emissions trading programs 

designed by Congress, the EPA, and the states to address 
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regional environmental problems and, most recently, climate 

change. Examples of such programs are noted below. 

Essentially, trading does nothing more than commoditize 

compliance, with the following two important results emerging 

from that: it reduces the overall costs of controls and spreads 

those costs among the entire category of regulated entities 

while providing a greater range of options for sources that may 

not want to make on-site investments for controlling their 

emissions and may prefer to make the same investment, via the 

purchase of the tradable compliance instrument, at another 

generating source. Building blocks 2 and 3 entail affected EGUs 

investing in increased generation from existing NGCC units and 

renewable energy. The affected EGUs could do so in any number of 

ways, including acquiring ownership interests in existing NGCC 

or renewable energy facilities or entering into bilateral 

transactions with the owners of existing NGCC facilities or 

renewable energy sources. As discussed elsewhere, it is 

reasonable to expect that these actions can develop into 

discrete, tradable commodities (e.g., an emission rate credit, 

or ERC) and that liquid markets will develop, which would reduce 

transaction costs and allow an affected EGU to comply with its 

emission limits by purchasing discrete units in amounts tailored 

closely to its compliance needs. The existence of such tradable 
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commodities also incentivizes over-compliance by affected EGUs, 

which can then sell their over-compliance in the form of ERCs or 

allowances to other affected EGUs. Moreover, as noted elsewhere, 

the opportunity to trade is consistent with the EPA’s regional 

approach for the building blocks. 

By the same token, the opportunity to trade incentivizes 

affected EGUs to over-comply with building block 1. Thus, the 

opportunity to trade supports the EPA’s assumptions about what 

an average affected EGU can achieve with regards to heat rate 

improvement even if each and every affected EGU cannot achieve 

that level of improvement. In addition, trading incentivizes 

affected EGUs to consider low-cost, non-BSER methods to reduce 

emissions as well, and, as discussed below, there are numerous 

non-BSER methods, ranging from implementation of demand-side 

energy efficiency programs to natural gas co-firing. 

Trading has become an important mechanism for achieving 

environmental goals in the electricity sector in part because 

trading allows environmental regulators to set an environmental 

goal while preserving the ability of the operators of the 

affected EGUs to decide the best way to meet it taking account 

of the full range of considerations that govern their overall 

operations. For example, commenters were concerned that because 

of building block 2, the emission guidelines would require state 
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environmental regulators to make dispatch decisions for the 

electricity markets, a role that state environmental regulators 

do not currently play. Although building block 2 entails 

substituting existing NGCC generation for steam generation, 

implementing the emission limits that are based in part on 

building block 2 through a trading program provides the 

individual affected EGUs with a great deal of control over their 

own generation while the industry as a whole achieves the 

environmental goals. For example, individual steam generators 

have the option of maintaining their generation as long as they 

acquire additional ERCs. Moreover, trading provides a way for 

states to set standards of performance that realize the required 

emissions reduction without requiring any form of “environmental 

dispatch” because, as many existing trading programs have shown, 

monetization of the environmental constraint is consistent with 

a least-cost dispatch system. Trading also supports the EPA’s 

approach to the “remaining useful life” provision in section 

111(d)(1) because with trading, an affected EGU with a limited 

remaining useful life can avoid the need to implement long-term 

emission reduction measures and can instead purchase ERCs or 

other tradable instruments, such as mass-based allowances, 

thereby allowing the state to meet the requirements of this 

rule. 
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The EPA’s job in issuing these emission guidelines is to 

determine the BSER that has been adequately demonstrated and to 

set emission limitations that are achievable through the 

application of the BSER and implementable through standards of 

performance established by the states. The three building blocks 

are the EPA’s determination of what technology is adequately 

demonstrated. We also consider trading an integral part of the 

BSER analysis because, in addition to being available to states 

for incorporation in the standards of performance they set for 

affected EGUs, trading has been adequately demonstrated for this 

industry in circumstances where systemic rather than unit-level 

reductions are central. Congress, the EPA, and state regulators 

have established successful environmental programs for this 

industry that allow trading of environmental (or similar) 

attributes, and trading has been widely used by the industry to 

comply with these programs. Examples include the CAA Title IV 

Acid Rain Program, the NOX SIP Call (currently referred to as the 

NOX Budget Trading Program), the Clean Air Interstate Rule 

(CAIR), the Cross-State Air Pollution Rule (CSAPR),481 the 

 

481 For example, in CSAPR, which covered the states in the 

eastern half of the U.S., the EPA assumed the existence of 

trading across those states in the rule’s cost estimates 

contained in the Regulatory Impact Analysis (RIA). “Regulatory 

Impact Analysis for the Federal Implementation Plans to Reduce 
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Regional Haze trading programs, the Clean Air Mercury Rule,482

RGGI, the trading program established by California AB32, and 

the South Coast Air Quality Management District RECLAIM program. 

We describe these programs in section II.E. of this preamble. In 

addition, we note in the Legal Memorandum accompanying this 

preamble that Congress, in enacting the Title IV acid rain 

trading program, and the EPA, in promulgating the regulatory 

trading programs listed, recognized both the suitability of 

trading for the EGU industry and the benefits of trading in 

reducing costs, spreading costs to affected EGUs throughout the 

sector, and facilitating the ability of affected EGUs to comply 

with their emission limits. In addition, as we discuss in 

section V.E. of this preamble, many states have adopted 

 

Interstate Transport of Fine Particulate Matter and Ozone in 27 

States; Correction of SIP Approvals for 22 States” 32 (June 

2011), http://www.epa.gov/airtransport/CSAPR/pdfs/FinalRIA.pdf 

In addition, the rule is being implemented either through 

federal implementation plans (FIPs) that authorize interstate 

emission trading or state implementation plans (SIPs) that 

authorize interstate emissions trading. 

482 Although the CAMR trading program never took effect because 

the rule was vacated on other grounds, it consisted of a 

nationwide trading program that the EPA adopted under CAA 

section 111(d). Some states declined to allow their sources to 

participate in the trading program on the grounds that 

nationwide trading was not appropriate for the air pollutant at 

issue, mercury, a hazardous air pollutant that caused adverse 

local impacts. 
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renewable energy standards that promote renewable energy through 

the trading of renewable energy certificates (RECs). 

Based on this history, it is reasonable for the EPA to 

determine that states can establish standards of performance 

that incorporate trading and, as a result, for the purpose of 

making a BSER determination here to evaluate prospective 

emission control measures in light of the availability of 

trading. Trading is a regulatory mechanism that works well for 

this industry. The environmental attributes in the preceding 

programs (representing emissions of air pollutants) are 

identical to or similar in nature to the environmental attribute 

here (CO2 emissions). The markets for RECs show that robust 

markets for renewable energy, in particular, already exist. 

Given the benefits of trading and the background of multiunit coordination grounded in the nature of the utility power 

sector, it is natural for sources and states to look for 

opportunities to apply similar coordination to a regional 

problem such as reduction of CO2 emissions from the sector. As 

noted earlier, the EPA heard this interest expressed during the 

outreach process for this rulemaking and saw it reflected in 

comments on the proposal. Emissions trading was prominent in 

these expressions of interest; while the proposal allowed 

trading and encouraged the development of multi-state plans 
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which would allow the benefits of trading to extend over larger 

regions, we heard that interest was even greater in “tradingready” plans that would use trading mechanisms and market-based 

coordination, rather than state-to-state coordination, as the 

primary means of facilitating multi-unit approaches to 

compliance. The general industry and state preference for multiunit compliance approaches makes great sense in the context of 

the industry and this pollutant, as does the specific preference 

for trading-ready section 111(d) plans, and we have made efforts 

in the final rule to accommodate trading-ready plans as 

described in section VIII. 

g. Measures that reduce CO2 emissions or CO2 emission rates but 

are not included in the BSER. There are numerous other measures 

that are available to at least some affected EGUs to help assure 

that they can achieve their emission limits, even though the EPA 

is not identifying these measures as part of the BSER. These 

measures include demand-side energy efficiency implementable by 

affected EGUs; new or up-rated nuclear generation; renewable 

measures other than those that are part of building block 3, 

including distributed generation solar power and off-shore wind; 

combined heat and power and waste heat power; and transmission 

and distribution improvements. In addition, a state may 

implement measures that yield emission reductions for use in 
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reducing the obligations on affected EGUs, such as demand-side 

energy efficiency measures not implementable by affected EGUs, 

including appliance standards, building codes, and drinking 

water or wastewater system efficiency measures. The availability 

of these measures further assures that the appropriate level of 

emission reductions can be achieved and that affected EGUs will 

be able to achieve their emission limits. 

gh. Ability of EGUs to implement the BSER. The EPA’s analysis, 

based in part on observed decades-long behavior of EGUs, shows 

that all types and sizes of affected EGUs in all locations are 

able to undertake the actions described as the BSER, including 

investor-owned utilities, merchant generators, rural 

cooperatives, municipally-owned utilities, and federal 

utilities. Some may need to focus more on certain measures; for 

example, an owner of a small generation portfolio consisting of 

a single coal-fired steam EGU may need to rely more multi-unit 

complianceon cross-investment approaches, possibly including the 

purchase of emission credits or allowances, because of a lack of 

sufficient scale to diversify its own portfolio to include NGCC 

capacity and renewableRE generating capacity in addition to 

coal-fired capacity. As noted elsewhere, asAs a legal matter, it 

is not necessary that each affected sourceEGU be able to 

implement the BSER, but in any event, in this rule, all affected 
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EGUs can do so. AffectedSince states can reasonably be expected 

to establish standards of performance incorporating emissions 

trading, affected EGUs may rely on emissions trading or other 

multi-unit compliance approaches authorized under their states’ 

section 111(d) plans to, in effect, invest in building block 

measures that are physically implemented at other locations. As 

discussed above, the EPA’s quantification of the CO2 emission 

performance rates in a manner that provides headroom within the 

BSER also contributes to the ability of all affected EGUs to 

implement the BSER and achieve emissions limitations consistent 

with those performance rates. 

hi. Subcategorization. As noted above, in this rule, we are 

treating all fossil fuel-fired EGUs as a single category, and, 

in the emission guidelines that we are promulgating with this 

rule, we are treating steam EGUs and combustion turbines as 

separate subcategories. We are determining the BSER for steam 

EGUs and the BSER for combustion turbines, and applying the BSER 

to each subcategory to determine a performance rate for that 

subcategory. We are not further subcategorizing among different 

types of steam EGUs or combustion turbines. As we discuss below, 

this approach is fully consistent with the provisions of section 

111(d), which simply require the EPA to determine the BSER, do 

not prescribe the method for doing so, and are silent as to 
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subcategorization. This approach is also fully consistent with 

other provisions in section 111, which require the EPA first to 

list source categories that may reasonably be expected to 

endanger public health or welfare and then to regulate new 

sources within each such source category, and which grant the 

EPA discretion whether to subcategorize the sources for purposes 

of determining the BSER. 

 As discussed below, each affected EGU can achieve the 

performance rate by implementing the BSER, specifically, by 

taking a range of actions –- some of which depend on features of 

the section 111(d) plan chosen by the state, such as the choice 

of rate-based or mass-based standards of performance and the 

choice of what multi-unit compliance approacheswhether and how

to permit, possibly including emissions trading approaches -- 

including investment in the building blocks, replaced or reduced 

generation, and emissions tradingpurchase of emission credits or 

other multi-unit compliance approaches.allowances. Further, in 

the case of a rate-based state plan, several other compliance 

options not included in the BSER for this rule are also 

available to all affected sourcesEGUs, including investment in 

demand-side energy efficiency measures. Such compliance options 

may also indirectly help affected sourcesEGUs achieve compliance 

under a mass-based plan. 
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 Our approach of subcategorizing between steam EGUs and 

combustion turbines is reasonable because building blocks 1 and 

2 apply only to steam EGUs. Moreover, our approach of not 

further subcategorizing as between different types of steam EGUs 

or combustion turbines reflects the reasonable policy that 

affected EGUs with higher emission rates should reduce their 

emissions by a greater percentage than affected EGUs with lower 

emission rates and can do so at a reasonable cost using the 

approaches we have identified as the BSER as well as other 

available measures. 

 Of course, a state retains great flexibility in assigning 

standards of performance to its affected EGUs and can impose 

different emission reduction obligations on its sources, as long 

as the overall level of emission limitation is at least as 

stringent as the emission guidelines, as discussed below. 

3. Changes from proposal 

 For the BSER determined in this final rule, based on 

consideration of comments responding to a broad array of topics 

considered in the proposal, the EPA has adopted certain 

refinementsmodifications to the proposed BSER. In this 

subsection we describe the most significant refinementsimportant 

modifications, including some that relate to individual building 

blocks and some that are more general. Additional 
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refinementsmodifications that relate to individual building 

blocks are discussed in the respective sections for those 

building blocks below (sections V.C. through V.E.). 

 We note that taken together, the refinementsmodifications

yield emission reductions requirements that commence more 

gradually than the proposed goals but are projected to produce 

slightly greater overall annual emission reductions overall by 

2030.483 We also note that the refinementsmodifications lead to 

requirements that are more uniform across states than was the 

casethe proposed state goals (consistent with the direction of 

certain alternatives on which we sought comment in the 

proposal), with the final requirements generally becoming more 

stringent (compared to the proposal) in states with the highest 

2012 CO2 emission rates and less stringent in states with lower 

2012 CO2 emission rates. 

a. Interpretations of CAA section 111. In the June 2014 proposal, 

the EPA proposed interpretations of section 111(a)(1) and (d), 

and applied these interpretations to existing fossil fuel-fired 

 

483 For the proposed rule, the EPA projected total CO2 emission 

reductions from 2005 levels of 29% in 2025 and 30% in 2030. For 

the final rule, the EPA projects total CO2 emissions reductions 

from 2005 levels of 28% in 2025 and 32% in 2030. See Regulatory 

Impact Analysis for the CPP Proposed Rule, Table 3-6, and 

Regulatory Impact Analysis for the CPP Final Rule, Table 3-6, 

available in the docket. 
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EGUs.484 Informed by comments, the EPA has clarified some of 

these interpretations, and has developed a more refined 

understanding of how some of these interpretations should be 

applied. The clarified and more refined interpretations replace 

the proposed interpretations, as indicated in section V.A.1. and 

the Legal Memorandum for the CPP Final Rule available in the 

docket, as well as in the final rule for new sources promulgated 

concurrently with this final rule for existing sources. 

 Two of these points merit mention here. First, the EPA is 

clarifying in this rule that the interpretation of “system of 

emission reduction” does not include emission reduction measures 

that the states have authority to mandate without the affected 

sourcesEGUs being able to implement the measures themselves 

(e.g., appliance standards or building codes). In the final 

rule, we have clarified that the components of the BSER must be 

implementable by the affected sourcesEGUs, not just by the 

states, and we show that all the components of the BSER have 

been demonstrated to be achievable on that basis without 

reliance on actions that can only be accomplished only through 

stategovernment mandates. Further discussion of these points can 

 

484 The June 2014 proposal in part referenced proposed 

interpretations of section 111(a)(1) that the EPA explained in 

the January 2014 proposal to address CO2 emissions from new 

fossil fuel-fired EGUs under section 111(b). 
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be found throughout this section on the BSER and the following 

sections on the individual building blocks. 

 Second, the EPA has adopted a combined interpretation of 

sections 111(a)(1) and 111(d) that, compared to the proposal, 

places more weight onbetter reflects the historical 

interpretations of section 111(a)(1), which have generally 

supported emissions standards that are nationally uniform for 

sources incorporating a given technology, and gives less weight 

onto the state-focused character of section 111(d), which calls 

for emissions standards to be implemented through the 

development of individual state plans. The proposed state goals 

were heavily (although not entirely) dependent on the emission 

reduction opportunities available to the sourcesEGUs in each 

individual state, and because the relative magnitudes of these 

opportunities varied by state, sources incorporating the same 

technologystates with similar EGU fleet compositions could have 

faced disparate state goals of different stringencies, 

potentially making it difficult for multiple states to set the 

same standards of performance (depending to some extent on 

howfor affected EGUs using the states chose to distributesame 

technologies (assuming the emission reduction requirements 

amongstates were interested in setting standards of performance 

for their individual sourcesvarious affected EGUs in such a 
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manner). Some commenters viewed this potential result as 

inconsistent with section 111(a)(1), inequitable, or both. 

WhileIn response, we continue to believe that, for the 

purposestook further comment on these potential disparities in 

the October 30, 2014 Notice of Data Availability. In this final 

rule, the focus of section 111(d) on individual state plans 

could justify an interpretation of section 111(a)(1) that 

emphasizes maximization of state-by-state emission reduction 

opportunities, we have determined thatare obviating those 

concerns by assessing the emission reduction opportunities at an 

appropriate regional scale, it is possible to reconcile the use 

ofconsistent with alternatives on which we sought comment, and 

using this regional information to reformulate the proposed 

emissions standards as nationally uniform emissions standards by 

technology with the state-focused 111(d) schemefor the emission 

guidelines.485 National uniformity is consistent with prior 

section 111 rulemaking and advances a number of other goals 

central to this rulemaking. The methodological refinements 

related to regional assessment of emission reduction 

 

485 Of course, a source in one state may face different 

requirements than similar sources in other states, depending on 

whether the state adopts the state measures approach or, if it 

adopts the emission standards approach, whether it imposes a 

mass limit or an emission rate and, if the latter, at what 

level. 
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opportunities and the use of uniform emissions standards by 

technology subcategory are further discussed below. 

b

. Approach to quantification of emission reductions from 

increased RE generation. In the June 2014 proposal, the EPA 

described two possible approaches for quantifying the amount of 

emission reductions achievable from affected EGUs through the 

use of renewable energy generation. The proposed approach used 

information on state RPS aggregated at a regional level along 

with historical RE generation data to project the amount of RE 

generation used in quantifying the emission reductions 

achievable through the BSER. The alternative approach used 

information on the technical and market potential for 

development of renewable resources in each state to project the 

RE-related emission reductions. In the October 30, 2014 Notice 

of Data Availability, we provided notice that some commenters 

had suggested modifying the alternativesought comment on an 

additional approach to aggregateof aggregating the state-level 

information to a regional level., as suggested by some 

commenters. In this final rule we are adopting the alternativea 

combination of these approaches that uses historical RE 

generating capacity deployment data aggregated to a regional 

level, supported and confirmed by projections of market 
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potential developed through a techno-economic approach from the 

proposal, modified as described in the NODA. 

 In the June 2014 proposal, RE generation was also 

quantified as generation from total –- that is, existing and new 

–- RE generating capacity, a formulation that was consistent 

with the formulation of most RPS, which are typically framed in 

terms of total rather than incremental generation. CommentersIn 

response to the EPA’s request for comment on this approach, 

commenters observed that this quantificationthe approach was 

inconsistent with the approach taken for other building blocks, 

and that generation from RE generating capacity that already 

existed as of 2012 should not be treated as reducing emissions 

of affected EGUs from 2012 levels. As just noted, we are not 

using the RPS-based methodology in the final rule, and we agree 

with comments that quantification of RE generation on an 

incremental basis is both more consistent with the treatment of 

other building blocks and more consistent with the general 

principle that the BSER should comprise incremental measures 

that will reduce emissions below existing levels, not measures 

that are already in place, even if those in-place measures help 

current emission levels be lower than would be the case without 

the measures. The final rule therefore defines the RE component 

of the BSER in terms of incremental rather than total RE 
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generation.486 Further details regarding the final rule’s 

quantification of RE generation are provided in section V.E. 

below. 

c

. Exclusion from the BSER of emission reductions from use of 

newunder-construction or preserved nuclear capacity. In the June 

2014 proposal, the EPA included in building block 3 provisions 

reflecting the ability for nuclear generation to replace fossil 

generation and thereby reduce CO2 emissions at affected 

sourcesEGUs. We proposed to include in building block 3 the 

potential generation from five under-construction nuclear 

generating units whose construction had commenced prior to the 

issuance of the proposal. In addition, to address the potential 

that some currently operating nuclear facilities may shut down 

prior to 2030, the proposal incorporated into the BSER for each 

state with nuclear capacity a projected 5.8 percent reduction in 

nuclear generation, based on an estimate of potential nationwide 

loss of nuclear generation from existing units. We sought 

comment on all aspects of these proposed approaches. ForWhile we 

 

486 Generation from existing RE capacity will continue to make 

compliance with mass-based standards easier to achieve by making 

the overall amount of fossil fuel-fired generation that is 

required to meet the demand for energy services lower than it 

would otherwise be, thereby keeping CO2 emissions lower than they 

would otherwise be. 
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recognize the important role nuclear power plants have to play 

in providing carbon-free generation in an all-of-the-above 

energy system, for this final rule, the BSER does not include 

either of the components related to nuclear generation. 

 The EPA received numerous comments on the proposed BSER 

components related to nuclear power. With respect to generation 

from newunder-construction nuclear units, some commenters 

expressed strong opposition to the inclusion of this generation 

in the BSER and the setting of state goals, stating that 

inclusion would result in very stringent state goals for the 

states where the new units are being built and that the 

inclusion of the generation in the goals is premature because 

the units’ actual completion dates are uncertain. Some 

commenters expressed concern regarding the lack of flexibility 

to find alternative emission reduction measures comparable in 

magnitude to the assumed emission reductions from the new 

nuclear generation in the event that construction was not 

completed, potentially hampering the ability to achieve the 

state goals. Commenters also stated that inclusion of the 

newcould be delayed. Commenters also stated that inclusion of 

the under-construction nuclear generation in the BSER would be 

inequitable because states where the same heavy investment in 
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zero-CO2 generation was not being made would have relatively less 

stringent goals. 

 With respect to generation from existing nuclear units, 

some commenters stated that our method of accounting for 

potential unit shutdowns was flawed, observing that even if the 

prediction of a 5.8 percent nationwide loss of nuclear 

generation were accurate, the actual shutdowns would occur in a 

handful of states, resulting isin much larger losses of 

generation in those particular states. 

 Upon consideration of comments and the accompanying data, 

the EPA has determined that the BSER should not include either 

of the components related to nuclear generation from the 

proposal. With respect to nuclear units under construction, 

although we believe that other refinements to this final rule 

would address commenters’ concerns that hostgoals for the 

particular states where the units are located would be at risk 

of being unableoverly stringent either in absolute terms or 

relative to achieve their goals if the units were not 

completedother states, we also acknowledge that including, in 

comparison to RE generating technology, investments in new 

nuclear units tend to be individually much larger and to require 

longer lead times. Also, important recent trends evidenced in RE 

development, such as rapidly growing investment and rapidly 
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decreasing costs, are not as clearly evidenced in nuclear

generation. We view these factors as distinguishing the underconstruction nuclear units from the units RE generating 

capacity, indicating that the new nuclear capacity is likely of 

higher cost and therefore less appropriate for inclusion in the 

BSER would fail to . Excluding the under-construction nuclear 

units from the BSER, but allowing emission reductions 

attributable to generation from the units to be used for 

compliance as discussed below and in section VIII, will 

recognize the CO2 emission reduction benefits achievable through 

the significant ongoing commitment required to complete these 

major investments by instead treating them as though there were 

no chance they would not be completed. . 

 With respect to existing nuclear units, although again we 

believe that other refinements in the final rule would address 

the concern about disparate impacts on particular states, we 

acknowledge that we lack information on shutdown risk that would 

enable us to improve the estimated 5.8 percent factor for 

nuclear capacity at risk of retirement. Further, based in part 

on comments received on another aspect of the proposal –- 

specifically, the proposed inclusion of existing RE generation 

in the goal-setting computations –- we believe that it is 

inappropriate to base the BSER in part on the premise that the 
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preservation of existing low- or zero-carbon generation, as 

opposed to the production of incremental, low- or zero-carbon 

generation, could reduce CO2 emissions from current levels. 

Accordingly, we have determined not to reflect either of the 

nuclear elements in the final BSER. 

 Generation from under-construction or other new nuclear 

units and capacity uprates at existing nuclear units would still 

be able to help sources meet emission rate-based standards of 

performance through the creation and use of credits, as 

discussednoted in section V.A.6.b.,. and section VIII.K.1.a.(8),

and would help sources meet mass-based standards of performance 

through reduced utilization of fossil generating capacity 

leading to reduced CO2 emissions at affected EGUs. However, 

consistent with the reasons just discussed for not reflecting 

preservation of existing nuclear capacity in the BSER –- namely, 

that such preservation does not actually reduce existing levels 

of emissions from affected EGUs –- the rule does not allow 

preservation of generation from existing or relicensed nuclear 

capacity to serve as the basis for creation of credits that 
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individual affected EGUs could use for compliance.487, as further 

discussed in section VIII.K.1.a.(8).488

d. Exclusion from the BSER of emission reductions from demandside energy efficiency. The June 2014 proposal included demandside energy efficiency measures in building block 4 as part of 

the BSER, but the EPA is not finalizing that part of the 

proposal, for the following reasons. The EPA took comment on the 

attributes of each of the proposed building blocks, and building 

block 4 was a topic of considerable controversy among 

commenters. While many commenters recognized demand-side energy 

efficiency as an integral part of the electricity system, 

emphasized its cost-effectiveness as a means of reducing CO2

emissions from the utility power sector, and strongly supported 

its inclusion in the BSER, other commenters expressed 

significant concerns. 

 

487 As with generation from existing RE capacity, generation from 

existing nuclear capacity will continue to make compliance with 

mass-based standards easier to achieve by making the overall 

amount of fossil fuel-fired generation that is required to meet 

the demand for energy services lower than it would otherwise be, 

thereby keeping CO2 emissions lower than they would otherwise be. 488 As with generation from existing RE capacity, generation from 

existing nuclear capacity will continue to make compliance with 

mass-based standards easier to achieve by making the overall 

amount of fossil fuel-fired generation that is required to meet 

the demand for energy services lower than it would otherwise be, 

thereby keeping CO2 emissions lower than they would otherwise be. 
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Building block 4 caused more controversy among commenters 

than any other aspect of the June 2014 proposal. While many 

commenters emphasized the cost-effectiveness of demand-side 

energy efficiency measures, others expressed significant 

concerns. 

As a legal matter, commenters emphasized that demand-side 

energy efficiency measures reduce emissions from the generation 

of electricity by reducing overall demand for electricity and 

that this is different from generation shifts and renewable 

energy. Commenters also asserted that those differences are 

legally significant for purposes of determining whether demandside energy efficiency measures may qualify as part of the BSER. 

Commenters viewed demand-side energy efficiency as a restriction 

on the amount of electricity that the affected industry could 

generate, and they viewed that type of restriction as beyond the 

scope of the EPA’s authority under CAA section 111. 

The demand-side energy efficiency measures in building 

block 4 are different in certain respects from the generation 

shifts and renewable energy measures in building blocks 2 and 3. 

As noted, the generation shifts and renewable energy measures 

are mechanisms through which affected EGUs may generate the same 

electricity (which is a fungible product) with fewer CO2

emissions whereas the demand-side energy efficiency measures in 
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building block 4 do not provide the same amount of generation 

but through cleaner processes, and instead bring about 

reductions in demand for electricity, which avoids the need for 

variable generation, which tends to be higher-emitting. 

Commenters also assert that inclusion of building block 4 

would amount to an attempt to extend EPA regulation beyond 

emitting sources to electricity end-users, and they observe that 

such an extension would exceed the EPA’s authority. While we do 

not agree that inclusion of building block 4 in the BSER would 

be equivalent to regulation of electricity end-users, the legal 

uncertainty associated with this claim would increase the 

uncertainty for states during a window of time when significant 

progress must be made on their section 111(d) plans, potentially 

hindering those planning efforts. 

In addition, commenters noted that as a practical matter, 

demand-side energy efficiency programs involve the participation 

of more entities, including end-users, which creates levels of 

complexity in implementation not found with the other building 

blocks. Commenters also asserted that the record for the 

proposal lacked information demonstrating that a number of 

states could implement demand-side energy efficiency programs in 

the amounts and on the time-table that the proposal called for, 

or that certain segments of the industry –- independent power 
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producers, who comprise some 35-40 percent of the industry, but 

do not have a direct business relationship with end-users –- 

could do so. 

Upon consideration of the variety of points raised above, 

without necessarily agreeing with those points, the EPA has 

determined not to include demand-side energy efficiency in the 

BSER in this final rule.As explained in section V.B.3.c.(8) 

below, our traditional interpretation and implementation of CAA 

section 111 has allowed regulated entities to produce as much of 

a particular good as they desire provided that they do so 

through an appropriately clean (or low-emitting) process. While 

building blocks 1, 2, and 3 fall squarely within this paradigm, 

the proposed building block 4 does not. In view of this, since 

the BSER must serve as the foundation of the emission 

guidelines, the EPA has not included demand-side EE as part of 

the final BSER determination. 

 It should be noted that commenters also took the position 

that the EPA should allow demand-side energy efficiency as a 

means of compliance with the requirements of this rule, and, as 

discussed in section V.A.6.b. and section VIII below, we agree. 

e

. Consistent regionalized approach to quantification of emission 

reductions from all building blocks. In the June 2014 proposal, 
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the EPA treated each of the building blocks differently with 

respect to the regional scale on which the building block was 

applied for purposes of assessing the emission reductions 

achievable through use of that building block. Building block 1 

was quantified at a national scale, identifying a single heat 

rate improvement opportunity applicable on average to all coalfired steam EGUs. Building block 2 was quantified at the scale 

of each individual state, considering the amount of generation 

that could be shifted from steam EGUs to NGCC units within the 

state, although we solicited comment on considering generation 

shifts at a broader regional scale. The RE component of building 

block 3 was quantified at a regional scale using RPS information 

as a proxy for RE development potential, and the regional 

results were then applied to each state in the region using the 

state’s baseline data; an alternative methodology on which we 

requested comment quantified the RE component using a technoeconomic approach on a state-specific basis.489 In the October 

2014 Notice of Data Availability, we requested comment on using 

 

489 For building block 4, potential demand-side EE was first 

quantified on a state-specific basis but the emission reduction 

consequences for electricity-importing states were then adjusted 

downward in the goal setting process in order to account for 

regional effects; we solicited comment on making parallel upward 

adjustments to the goals for net electricity-exporting states to 

account for the regional effects more completely. 
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a techno-economic approach to quantify RE generation potential 

at a regional scale and took broad comment on strategies for 

better aligning the BSER with the regionally interconnected 

electrical grid.490 We also solicited comment on the appropriate 

regional boundaries or regional structure to facilitate this 

approach.

 For the final rule, with the benefit of comments received

in response to these proposals and alternatives, we have adopted 

a consistent regionalized approach to quantification of emission 

reductions achievable through all the building blocks. The 

regions we have determined to be appropriate for this purpose 

are the Eastern, Western, and Texas Interconnections, as we 

explain in more detail below.491 EachUnder this approach, each of 

the building blocks is quantified and applied at the regional 

level, resulting in the computation for each region of a 

performance rate for steam EGUs and a performance rate for NGCC 

units. For each of the technology subcategories, we identify the 

most conservative –- that is, the least stringent –- of the 

three regional performance rates. We then apply these least 

 

490 79 FR 64543, 64551-62 491 The Texas Interconnection encompasses the portion of the 

Texas electricity system commonly known as ERCOT (for the 

Electric Reliability Council of Texas). The state of Texas has 

areas within the Eastern and Western Interconnections as well as 

the Texas Interconnection. 
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stringent subcategory-specific performance rates to the baseline 

data for the EGU fleet in each state in a region to establish 

state goals of consistent stringency across the states 

(althoughcountry. (Note that the actual state goals vary among 

states to reflect the differences in generation mix among 

states).492 in the baseline year.) Further description of the 

steps in this overall process is contained in the preamble 

sections addressing the individual building blocks (sections 

V.C., V.D., and V.E.) and.), CO2 emission performance rate 

computation (section VI), and state goal computation (sections 

VI andsection VII), as well as the GHG Mitigation Measures TSD 

for the CPP Final Rule and the CO2 Emission Performance Rate and 

Goal Computation TSD for the CPP Final Rule available in the 

docket. 

 

 Compared to the more state-focused quantification approach 

selected in the proposal, and as recognized in the Notice of 

Data Availability, a regionalized approach better reflects the 

interconnected system within which interdependent affected EGUs 

 

492 As discussed below, we have determined that it is appropriate 

to go further and to use the single most conservative – that is, 

the least stringent – set of the three regionally developed 

uniform emissions standards to establish state goals for the 

states, in all three regions, thereby ensuring a consistent 

stringency of goals for all states. 
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actually carry out planning and operations in order to meet 

electricity demand. We have already discussed the relevance of 

the interconnected system and the interdependent operations of 

EGUs as factors supporting consideration of building blocks 2 

and 3 as elements of the BSER for this pollutant and this 

industry, and these same factors support quantifying the 

emission reductions achievable through building blocks 2 and 3 

on a regionalized basis. Because it better reflects how the 

industry works, a regionalized approach also better represents 

the full scope of emission reduction opportunities available to 

individual affected EGUs through the normal transactional 

processes of the industry, which do not stop at state borders 

but rather extend throughout these interconnected regions. With 

respect to building block 1, which comprises types of emission 

reduction measures that in other rulemakings under CAA section 

111 would typically be evaluated on a nationwide basis, for this 

rule, as discussed in section V.C. below, we are quantifying the 

emission reductions achievable through building block 1 on a 

regional basis in order to treat the building blocks 

consistently and to ensure that for each region the 

quantification of the BSER represents only as much potential 

emission reduction from building block 1 as our analysis of 
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historical data indicates can be achieved on average by the 

affected EGUs in that region. 

 Characterizing and quantifying the measures included in the 

BSER on a regional basis rather than a state-limited basis is 

also appropriate because states can establish standards of 

performance that incorporate emissions trading, including 

trading between and among EGUs operating in different states, 

and thus provide EGUs the opportunity to trade. Emissions 

trading provides at least one mechanism by which owners of 

affected EGUs can access any of the building blocks at other 

locations. With emissions trading, an affected EGU whose access 

to heat rate improvement opportunities, incremental generation 

from existing NGCC units, or generation from new renewable 

energy generating capacity is relatively favorable can 

overcomply with its own standard of performance and sell ratebased emission credits or mass-based emission allowances to 

other affected EGUs. Purchase of the credits or allowances by 

the other EGUs represents cross-investment in the emission 

reduction opportunities, and such cross-investment can be 

carried out on as wide a geographic scale as trading rules 

allow. 

 The regions we have determined to be appropriate for the 

regionalized approach in the final rule are the Eastern, 
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Western, and Texas Interconnections.493 In determining that the 

appropriate regional level for quantification of the BSER was 

the level of the interconnection, the EPA considered several 

factors. First, consistent with our goal of aligning regulation 

with the reality of the interconnected electricity system, we 

considered the regional scale on which electricity is actually 

produced, physically coordinated, and consumed in real time, and 

concluded that the three large interconnections –- –- 

specifically the Eastern, Western, and Texas –- were more 

appropriate than subregions within these 

interconnectionsInterconnections. The Bulk Power System (BPS) in 

the contiguous United States (including adjacent portions of 

Canada and Mexico) consists of these three interconnections, 

which are alternating current (AC) power grids where power flows 

freely from generating sources to consuming loads. These 

interconnections are separately planned and operated; they are 

connected to each other only through low-capacity direct current 

(DC) tie lines. Each interconnection is managed to maintain a 

single frequency and to maintain stable voltage levels 

 

493 The Texas Interconnection encompasses the portion of the 

Texas electricity system commonly known as ERCOT (for the 

Electric Reliability Council of Texas). The state of Texas has 

areas within the Eastern and Western Interconnections as well as 

the Texas Interconnection. 
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throughout the interconnection. Physically, each interconnection 

functions as a large pool, where all electricity delivered to 

the electric grid flows by displacement over all transmission 

lines in the interconnection and must be continually balanced 

with load to ensure reliable electricity service to customers 

throughout each interconnection. “Since power flows on all 

transmission paths, it is not uncommon to find circumstances in 

which part of a power delivery within one balancing area flows 

on transmission lines in adjoining areas, or part of a power 

delivery between two balancing areas flows over the transmission 

facilities of a third area.”494 The interconnections are the 

“complex machines” within which EGUs plan, coordinate, and 

operate, manifesting a degree of both long-term and real-time 

interdependence that is unique to this industry. We concluded 

that, absent a compelling reason to adopt a smaller regional 

scale for evaluation of CO2 emission reduction opportunities for 

the electric power sector –- which we have not found, as 

discussed below –- the interconnections should be the regions 

used for evaluation of the BSER for CO2 emission reductions from 

the electric power sector because of the fundamental 

characteristics of electricity, the industry’s basic 

 

494 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 188 (2d ed. 2010). 
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interconnected physical infrastructure, and the interdependence 

of the affected EGUs within each interconnection. 

 Second, we considered whether the interconnection 

subregions for which various planning and operational functions 

are carried out by separate institutional actors would represent 

more appropriate regions than the entire Interconnnections, and 

concluded that they would not. Interconnection planning and 

management follows the NERC functional model, which defines 

subregional areas and regional entities within each 

interconnection for the purposes of balancing generation with 

load and ensuring that reliability is maintained. While a 

variety of organizations plan and operate these subregions –- 

with the borders of the subregions occasionally changing as 

planning and management functions evolve or as owners of various 

portions of the grid change affiliations –-, those activities 

always occur in the context of the interconnections, whose 

boundaries change much less oftenand the subregions cannot be 

operated autonomously. The need to maintain common frequency and 

stable voltage levels throughout the interconnections requires 

constantly changing flows of electricity between the planning 

and operating subregions within each interconnection. 

 Because each interconnection is a freely flowing AC grid, 

any power generated or consumed flows through the entire 
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interconnection in real time; as a result of this highly 

interconnected nature of the power system, the management of 

generation and load on the grid must be carefully maintained. 

This management is carried out principally by subregional 

entities responsible for the operation of the grid, but this 

operation must be coordinated in real time to ensure the 

reliability of the system. Regional operators must coordinate 

the dispatch of power, not only in their own areas, but also 

with the other regionssubregions within the interconnection. 

Although this coordination has always been important, grid 

planning and management has evolved to be increasingly 

interconnection-wide, through the development of larger regional 

entities, such as RTO/ISOs, or large-utility dispatch across 

multiple balancing areas. As a result, the fact that much of the 

necessary coordination for the interconnections is performed 

regionally on a partially decentralized basis (at least in the 

case of the Eastern and Western Interconnections) or occurs 

through the operation of automated equipment and the physics of 

the grid does not render the subregions more relevant than the 

interconnections as the ultimate regions within which 

electricity supply and demand must balance. 

 Second Moreover, some planning and standard setting 

activities are undertaken explicitly at the interconnection 
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level. For example, interconnections also have interconnection 

reliability operating limits (IROLs).495 A joint FERC-NERC report 

on the September 8, 2011 Arizona-Southern California outages 

outlined the importance of IROLs.496 The report noted that to 

ensure the reliable operation of the bulk power system, entities 

must identify a plan for IROLs to avoid cascading outages. “In 

order to ensure the reliable operation of the BPS, entities are 

required to identify and plan for IROLs, which are SOLs that, if 

violated, can cause instability, uncontrolled separation, and 

cascading outages. Once an IROL is identified, system operators 

are then required to create plans to mitigate the impact of 

exceeding such a limit to maintain system reliability.”497 

 

495 For example, the Eastern Interconnection has Reliability 

Standard IRO-006-EAST-1, Transmission Loading Relief Procedure 

for the Eastern Interconnection, available at 

http://www.nerc.com/files/IRO-006-EAST-1.pdf (providing an 

“Interconnection-wide transmission loading relief procedure 

(TLR) for the Eastern Interconnection that can be used to 

prevent and/or mitigate potential or actual System Operating 

Limit (SOL) and Interconnection Reliability Operating Limit 

(IROL) exceedances to maintain reliability of the Bulk Electric 

System (BES).”). 

496 FERC-NERC, Arizona-Southern California Outages on September 

8, 2011: Causes and Recommendations (Apr. 2012), available at

http://www.ferc.gov/legal/staff-reports/04-27-2012-ferc-nercreport.pdf. 

497 FERC-NERC, Arizona-Southern California Outages on September 

8, 2011: Causes and Recommendations, at 97 (Apr. 2012), 

available at http://www.ferc.gov/legal/staff-reports/04-27-2012-

ferc-nerc-report.pdf. 
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Congress recognized the significance of the three 

interconnections in the American Recovery and Reinvestment Act 

of 2009 (Recovery Act) when it provided $80 million in funding 

for interconnection-based transmission planning.498 In order to 

fulfill this Congressional mandate, DOE and FERC signed a 

memorandum of understanding to enumerate their roles “for 

activities related to the Resource Assessment and 

Interconnection Planning project funded by the American Recovery 

and Reinvestment Act of 2009 (Recovery Act). Among the 

objectives of the project is to facilitate the development or 

strengthening of capabilities in each of the three 

interconnections serving the contiguous lower forty-eight 

States, to prepare analyses of transmission requirements under a 

broad range of alternative futures and develop long-term 

interconnection-wide transmission plans.”499 DOE issued awards to 

five organizations that performed work in the Western, Eastern, 

and Texas Interconnections to develop long-term interconnectionwide transmission expansion plans.500 

 

498 American Reinvestment and Recovery Act of 2009, Title IV, 

Public Law 111-5 (2009). 

499 Memorandum of Understanding Between the U.S. Department of 

Energy and the Federal Energy Regulatory Commission, available 

at http://www.ferc.gov/legal/mou/mou-doe-ferc.pdf. 500 DOE, Recovery Act Interconnection Transmission Planning, 

available at http://energy.gov/oe/services/electricity-policy-
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In Order No. 1000, FERC also took a broader regional view 

of transmission planning.501 FERC required each public utility 

transmission provider to participate in a regional transmission 

planning process that produces a regional transmission plan. 

FERC also required neighboring transmission planning regions to 

coordinate with each other. This interregional coordination 

includes identifying methods for evaluating interregional 

transmission facilities as well as establishing a common method 

or methods of cost allocation for interregional transmission 

facilities. 

In addition to Congressional, DOE, and FERC recognition of 

the importance of the three interconnections, NERC also 

considers them to be significant. NERC Organizational Standards 

“are based upon certain Reliability Principles that define the 

foundation of reliability for North American bulk electric 

systems.”502 These principles take a broad view of electric 

 

coordination-and-implementation/transmission-planning/recoveryact. 

501 Transmission Planning and Cost Allocation by Transmission 

Owning and Operating Public Utilities, Order No. 1000, FERC 

Stats. & Regs. ¶ 31,323 (2011), order on reh’g, Order No. 1000-

A, 139 FERC ¶ 61,132, order on reh’g, Order No. 1000-B, 141 FERC 

¶ 61,044 (2012), aff’d sub nom. S.C. Pub. Serv. Auth. v. FERC, 

762 F.3d 41 (D.C. Cir. 2014). 

502 NERC, Reliability and Market Interface Principles, at 1, 

available at 
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system reliability, considering the reliability of 

interconnected bulk electric systems. For example, Reliability 

Principle 1 states, “Interconnected bulk electric systems shall 

be planned and operated in a coordinated manner to perform 

reliably under normal and abnormal conditions as defined in the 

NERC standards.”503 NERC took a similarly broad view of system 

reliability when it delegated its authority to monitor and 

enforce mandatory reliability standards to a single Regional 

Entity in both the Western and Texas Interconnections (WECC in 

the West and the Texas Reliability Entity in the ERCOT region of 

Texas).504 Moreover, both WECC and ERCOT have interconnectionwide reliability standards.505 The Eastern Interconnection has 

multiple reliability regions with some differences in standards, 

but power flows and reliability are managed through a single 

 

http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInter

facePrinciples.pdf. 

503 NERC, Reliability and Market Interface Principles, at 1, 

available at 

http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInter

facePrinciples.pdf. 

504 NERC, Key Players, available at

http://www.nerc.com/AboutNERC/keyplayers/Pages/default.aspx. 

505 WECC, Standards, available at

https://www.wecc.biz/Standards/Pages/Default.aspx (last visited 

July 3, 2015); Texas Reliability Entity, Reliability Standards, 

available at 

http://www.texasre.org/standards_rules/Pages/Default.aspx (last 

visited July 3, 2015). 
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Reliability Coordinator Information System that tracks power 

flows for all transmission transactions.506 

 The importance that Congress, DOE, FERC, and NERC each 

place upon the interconnections for electric reliability and 

operational issues is another factor supporting our decision to 

set the interconnections as the regional boundaries for the 

establishment of BSER. The utilization of the three 

interconnections for both planning and reliability purposes is a 

clear indication of the importance that electricity system 

regulators, operators, and industry place upon the 

interconnections. Those responsible for the electricity system 

recognize the need to ensure that there is a free flow of 

electricity throughout each interconnection such that 

transmission planning and reliability analysis are occurring at 

the interconnection level. Further, this vigilance with respect 

to considering reliability from an interconnection-wide basis 

recognizes that each of the interconnections behaves as a single 

machine where “outages, generation, transmission changes, and 

 

506 The NERC glossary defines the Reliability Coordinator 

Information System as the “system that Reliability Coordinators 

use to post messages and share operating information in real 

time.” NERC, Glossary of Terms Used in Reliability Standards

(Apr. 20, 2009), available at

http://www.eia.gov/electricity/data/eia411/nerc_glossary_2009.pd

f. 
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problems in any one area in the synchronous network can affect 

the entire network.”507 By setting the three interconnections as 

the regions for purposes of BSER, we are acting consistent with 

the way in which planning, reliability, and industry experts 

view the electricity system. 

An additional factor weighing against the use of planning 

or operational subregions of the interconnections as the regions 

for our BSER analysis for this rule is that the borders of those 

subregions occasionally change as planning and management 

functions evolve or as owners of various portions of the grid 

change affiliations. This is not a merely theoretical 

consideration; numerous ISO/RTO and other regional boundaries 

have substantially changed in recent years. For example, in 

2012, Duke Energy Ohio and Duke Energy Kentucky integrated into 

PJM.508 The following year, in December 2013, Entergy and its six 

utility operating companies joined MISO, creating the MISO South 

Region.509 The integration of MISO South correspondingly led to 

 

507 Casazza, J. and Delea, F., Understanding Electric Power 

Systems, IEEE Press, at 159 (2d ed. 2010). 508 PJM, Duke Energy Ohio, Inc., and Duke Energy Kentucky, Inc., 

Successfully Integrated Into PJM (Jan. 3, 2012), available at 

http://www.pjm.com/~/media/about-pjm/newsroom/2012-

releases/20120103-duke-ohio-and-kentucky-integrate-intopjm.ashx.

509 Miso, South Region Integration, available at 

https://www.misoenergy.org/WhatWeDo/StrategicInitiatives/Souther
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changes in NERC’s regional assessment areas.510 FERC also 

recently approved the integration of the Western Areas Power 

Administration – Upper Great Plains, Basin Electric Power 

Cooperative, and Heartland Consumers Power District into SPP.511

Additionally, PacifiCorp and the CAISO recently began operating 

the western Energy Imbalance Market (EIM).512 Other entities such 

as NV Energy, Arizona Public Service Co., and Puget Sound Energy 

are planning to participate in the EIM in the future.513 The EIM 

“creates significant reliability and renewable integration 

benefits for consumers by sharing and economically dispatching a 

 

nRegionIntegration/Pages/SouthernRegionIntegration.aspx (noting 

that the creation of the MISO South Region “brought over 18,000 

miles of transmission, ~50,000 megawatts of generation capacity, 

and ~30,000 MW of load into the MISO footprint.”). 

510 NERC previously included Entergy and its six operating areas 

as part of the SERC Assessment Areas. NERC, 2014 Reliability 

Assessment (May 2014). “MISO now coordinates all RTO activities 

in the newly combined footprint, consisting of all or parts of 

15 states with the integration of Entergy and other MISO South 

entities. This transition has led to substantial changes to 

MISO’s market dispatch, creating the potential for unanticipated 

flows across the following systems: Tennessee Valley Authority 

(TVA), Associated Electric Cooperative Inc. (AECI), and Southern 

Balancing Authority.” Id. at 7. 511 SPP, FERC approves Integrates System joining SPP (Nov. 12, 

2014), available at 

http://www.spp.org/publications/FERC%20approves%20IS%20membershi

p.pdf.

512 NREL, Energy Imbalance Market, available at

http://www.nrel.gov/electricity/transmission/energy_imbalance.ht

ml. 

513 CAISO, EIM Company Profiles (May 2015), available at

http://www.caiso.com/Documents/EIMCompanyProfiles.pdf. 
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broad array of resources.”514 This history of changing regional 

boundaries leads us to the conclusion that selecting smaller 

regional boundaries for purposes of setting the BSER would 

merely represent a snapshot of current, changeable regional 

boundaries. As we have seen with recent, large-scale changes 

regarding ISO/RTO boundaries and NERC reliability assessment 

areas, such regions would likely not stand the test of the time, 

nor would smaller regional boundaries accurately reflect 

electricity flows on the grid. The EPA believes that the 

interconnections are the most stable and reasonable regional 

boundaries for setting BSER. 

 Third, we considered whether transmission constraints, and 

the fact that the specific locations of generation resources and 

loads within each interconnection clearly matter to grid 

planning and operations, necessitate evaluation of the emission 

reductions available from the building blocks at scales smaller 

than the interconnections. We concluded that no reduction in 

scale was needed due to such constraints. The same industry 

trends that are reflected in the BSER -- the changing 

efficiencies and mix of existing fossil EGUs and the development 

 

514 CAISO, Energy Imbalance Market, available at

http://www.caiso.com/informed/pages/stakeholderprocesses/energyi

mbalancemarket.aspx. 
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of renewable energy throughout each interconnection -- as well 

as the management of the interconnected grid as loads are 

reduced through energy efficiency, which is not reflected in the 

final BSER, are already driving power system development and are 

being managed through interconnection-wide planning, 

coordination and operations, and will continue to be managed in 

that manner in the future with or without this rule. While 

electricity supply and demand must be balanced in real time in a 

manner that observes all security constraints at that point in 

time, and key aspects of that management are carried out at a 

subregional scale, the emissions standards established in this 

rule can be met over longer timeframes through processes managed 

at larger geographic scales, just as they are today. We believe 

this rule will reinforce these developments and help provide a 

secure basis for moving forward. If a local transmission 

constraint requires that for reliability reasons a higheremitting resource must operate during a certain period of time 

in preference to a lower-emitting resource that would otherwise 

be the more economic choice when all costs are considered, 

nothing in this rule prevents the higher-emitting source from 

being operated. If the same transmission constraint causes the 

same conditions to occur frequently, the extra cost associated 

with finding alternative ways to reduce emissions will provide 
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an economic incentive for concerned parties to explore ways to 

relieve the transmission constraint. If relieving the constraint 

would be more costly than employing alternative measures to 

reduce emissions, the rule allows parties to pursue those 

alternative emission reduction measures. Accommodation of 

intermittent constraints and evaluation of alternatives for 

relieving or working around them have been routine operating and 

planning practices within the utility power sector for many 

years; the rule will not change these basic economic practices 

that occur today. The 2022-29 schedule for the rule’s interim 

goals and the 2030 schedule for the rule’s final goals allow 

time for planning and investment comparable to the sector’s 

typical planning horizons. 

 Finally, the EPA also considered whether the smaller 

geographic scales on which affected sourcesEGUs may typically 

engage in energy and capacity transactions necessitate 

evaluating the emission reductions available from the building 

blocks at scales smaller than the interconnections, and again 

concluded that a smaller scale was not necessary or justified. 

We first note that electricity trading occurs today throughout 

the interconnection through RTO/ISO markets and active spot 

markets, often over large areas such as RTO/ISOs, or managed 

over large dispatch areas outside RTOs. These trades result in 
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interconnection-wide changes in flow that are managed in real 

time. Moreover, the exchange of power is not limited to these 

areas. For example, RTOs regularly manage flows between RTOs, 

and EGUs near the boundaries of RTOs impact multiple subregions 

across the interconnections, so that any subregional boundaries 

that might be evaluated for potential relevance as trading 

region boundaries will change as conditions and EGU choices 

change, while interconnection boundaries will remain stable. 

 In addition, the final rule permits trading of rate-based 

emission credits or mass-based emission allowances. Emission 

allowances and other commodities associated with electricity 

generation activities, such as renewable energy certificates, 

which, again, represent investments in pollution control 

measures, are already traded separately from the underlying 

electric energy and capacity. There is no reason that whatever 

geographic limits may exist for electricity and capacity 

transactions by an affected sourceEGU should also limit the 

source’sEGU’s transactions for validly issued rate-based 

emission rate credits or mass-based emission allowances. In 

fact, as discussed below, the final rule not only allows 

national trading without regard to the interconnection 

boundaries, but also includes a number of options that readily 

facilitate states’ and utilities’ very extensive reliance on 
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emissions trading. It is appropriate for the rule to take this 

approach, in part, because the non-local nature of the impacts 

of CO2 pollution do not necessitate geographic constraints, and 

in the absence of a policy reason to constrain the geographic 

scope of trading, the largest possible scope is the most 

efficient scope. 

f. Uniform CO2 emission performance rates by technology 

subcategory. In conjunction with the refinements to the 

interpretations of section 111 reflected in the final rule, the 

EPA has refined the methodology for applying the BSER to the 

affected EGUs so as to incorporate performance rates that are 

uniform across technology subcategories. 

. Uniform CO2 emission performance rates by technology type. In 

conjunction with the refinements to the interpretations of 

section 111 reflected in the final rule, the EPA has refined the 

methodology for applying the BSER to the affected sources so as 

to incorporate performance rates that are uniform across 

technology types. 

 Specifically, the final rule reflectsestablishes a 

performance rate of 12901305 lbs. per net MWh for all affected 

steam EGUs nationwide and a performance rate of 780771 lbs. per 

net MWh for all affected stationary combustion turbines 

nationwide. The computations of these performance rates and the 
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determinations of state goals reflecting the performance rates 

are described in sections VI and VII of the preamble, 

respectively. This refinement is consistent with a number of 

comments we received on the proposal and is a logical outgrowth 

of the proposal informed by the comments.As described above, in 

its proposed rule and Notice of Data Availability, the EPA 

solicited comment on a number of proposals to reflect the 

regional nature of the electricity system in the methodology for 

quantifying the emission limitations reflective of the BSER. At 

the same time, the EPA also consistently emphasized the need for 

strategies to ensure the achievability and flexibility of the 

established emission limitations and to increase opportunities 

for interstate and industry-wide coordination. This modification 

is consistent with a number of comments we received in response 

to those proposals. The commenters took the position that the 

proposed state goals varied too much among states and 

unavoidably implied, or would inevitably result in, states 

establishing inconsistent standards of performance for sources 

of the same technology type in their respective states, which in 

the commenters’ view was not appropriate under section 111.

 In section VI, below, we describe how we use data assembled 

for the building blocks through the consistent regional approach 

described above to determine for each region a set of uniform 
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performance rates representing emission limits achievable 

through the application of the BSER to the subcategory of steam 

EGUs and the subcategory of NGCC units. Recognizing the comments 

favoring the use of nationally uniform performance rates by 

technology, the EPA considered whether any of the regional 

performance rates could represent the emission limitation 

achievable through application of the BSER for its respective 

source subcategory nationwide. Except for Alaska, Hawaii, Puerto 

Rico, and Guam, which are geographically isolated from the three 

major interconnections as well as from one another, the 

standards developed using data for the Eastern, Western and 

ERCOT Interconnections represented sufficiently broad 

combinations of affected sources and emission reduction 

opportunities to apply nationally. 

 We also determined that it would be more appropriate to use 

 Having determined to adopt regional alternatives for computing 

the emission reductions achievable under each building block, 

the EPA has further determined to exercise discretion not to 

subcategorize based on the regions, and instead to apply a 

nationally uniform CO2 emission performance rate for each source 

subcategory. Evaluating the emission reduction opportunities 

achievable through application of the BSER on a broad 

regionalized basis, which is appropriate for the reasons 
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discussed above, makes it possible to express the degree of 

emission limitation reflecting the BSER as CO2 emission 

performance rates that are uniform for all affected EGUs in a 

technology subcategory within each region. However, the goals 

and strategies embodied in the EPA’s proposed rule are best 

effected by setting uniform emission performance rates 

nationally and not just regionally, as recognized by commenters 

favoring the use of nationally uniform performance rates by 

technology subcategory. Nationally uniform emission performance 

rates create greater parity among the emission reduction goals 

established for states across the contiguous U.S. and increase 

the ability of states and affected EGUs to coordinate emission 

reduction strategies, including through the use of emission 

trading mechanisms if states choose to allow such mechanisms, 

which we consider likely. 

 Having determined that the performance rates computed on a 

regional basis merit consideration as nationally applicable 

performance rates, we are also determining that the objectives 

of achievability and flexibility would best be met by using the 

least stringent of the regional performance rates for the three 

interconnections for each technology typesubcategory as the 

basis for nationally uniform performance rates for that 

technology typesubcategory than to useby using the most 
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stringent or the region-specific performance rates. This is 

generally consistent with the approach taken in other NSPS 

rulemakings, where once the appropriate technology has been 

identified, stringencies are generally set based on the least 

stringent level reasonably achieved using that technology. Using 

the least stringent rate would provideof the regional 

performance rates.515 Under this approach, the CO2 emission 

performance rate reflecting the BSER for all steam EGUs is 

uniform across the contiguous U.S., regardless of the state or 

interconnection where the steam EGUs are located. While it is 

true that steam EGUs in the Western and Texas Interconnections 

have opportunities to implement the measures in the building 

blocks to a greater extent than the steam EGUs in the Eastern 

Interconnection –- for example, under building block 2, they 

have relatively greater amounts of incremental NGCC generation 

available to replace their generation in all years for which 

performance rates were computed -- we do not conclude that this 

 

515 The Eastern, Western, and Texas Interconnections each 

encompass large and diverse populations of EGUs with numerous 

and diverse opportunities to reduce CO2 emissions through 

application of the measures in each of the three building 

blocks. Based on these considerations of scale and diversity, we 

conclude that each of the interconnections is sufficiently 

representative of the source subcategories and emission 

reduction opportunities encompassed in the BSER to potentially 

serve as the basis for CO2 emission performance rates applicable 

to the respective source subcategories on a nationwide basis. 
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means that the EGUs in all three interconnections should be 

assigned the most stringent CO2 emission performance rate 

computed for any of the three regions. Applying nationally the 

performance rate computed for the interconnection with the lease 

stringent rate ensures that the emission limitations are 

achievable by the affected EGUs in all three interconnections. 

The use of a common CO2 emission performance rate across all of 

the steam EGUs in all three regions also allocates the burdens 

of the BSER equally across the steam EGU source subcategory. The 

same is true for the combustion turbine source subcategory, even 

though, in any year for which emission performance rates are 

computed, the combustion turbines in two of the interconnections 

have relatively greater opportunities to replace their 

generation with generation from new renewable energy generating 

capacity than combustion turbines in the third 

interconnection.516 

 

516 As discussed in section VI and the CO2 Emission Performance 

Rate and State Goal Computation TSD, the emission performance 

rates for each technology subcategory are computed by region for 

each year from 2022 through 2030, and the region with the least 

stringent emission rate for a particular subcategory, whose rate 

therefore is used for all three regions, can differ across 

years. In the case of the steam EGU subcategory, the nationwide 

rate for all years is the rate computed for the Eastern 

Interconnection. In the case of the NGCC subcategory, the 

nationwide rate is the rate computed for the Texas 

Interconnection for the years from 2022 through 2026 and the 
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In addition, using the least stringent rate provides

greater “headroom” –- that is, emission reduction opportunities 

beyond those reflected in the performance rates –- to affected 

sourcesEGUs in regionsthe interconnections that do not 

settingset the nationalnationwide level, and therefore. This

greater “headroom” provides greater nationwide compliance 

flexibility and assurance that the standards wouldset by the 

states based on the emission guidelines will be achievable at 

reasonable cost, while still representing an appropriately large 

set of emission reduction opportunities to and without adverse 

impacts on reliability. This is because affected EGUs in the 

interconnections that do not set the nationwide level have more 

opportunities to directly invest in each of the building blocks 

in their respective regions, and affected EGUs in the 

interconnection that does set the nationwide level may in effect 

invest in the opportunities in the other interconnections 

through trading. At the same time, our approach still represents 

the degree of emission limitation achievable through use of an 

appropriately large and diverse set of emission reduction 

opportunities and can therefore reasonably be considered the 

 

rate computed for the Eastern Interconnection for the years from 

2027 through 2030. 
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“best” system of emission reduction for each technology 

typesubcategory. 

 We Our approach in this rulemaking thus not only addresses 

the comments we received regarding potentially disparate impacts 

of the approach presented in the proposal, it is also generally 

consistent with the approach we have determined taken in other 

NSPS rulemakings, where standards of performance or emission 

guidelines have typically been established at uniform 

stringencies for all units in a given source subcategory, and 

where once the best system of emission reduction has been 

identified, stringencies are generally set based on what is 

reasonably achievable using that the nationwidesystem. 

 Providing each state with a state-specific weighted average 

rate-based goal allows the state to determine how the emission 

reduction requirements should be allocated among the state’s 

affected EGUs. We continue to believe that, as in the proposal, 

this is an important source of flexibility for states in 

developing their section 111(d) plans. Accordingly, in this 

final rule we are providing uniform CO2 emission performance 

rates should not for each source subcategory and also 

translating those rates to state-specific weighted average ratebased goals. For additional flexibility, we are also translating 

the state-specific rate-based goals into state-specific mass-
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based goals. Our determinations of the emission performance 

rates are described in section VI below, and our determinations 

of the rate-based and mass-based state goals are described in 

section VII below. 

 We note here that the weighted-average state goals reflect 

the application of the uniform CO2 emission performance rates for 

affected steam EGUs and affected NGCC units to the respective 

units in each subcategory in each state. Each state goal 

therefore reflects uniform stringency of emission reduction 

requirements with respect to affected units in each source 

subcategory, but also reflects the EGU fleet composition and 

historical generation specific to that particular state. 

Compared to the computation approach reflected in the proposed 

state goals, the revised approach to quantify the BSER on a 

regional basis and to translate the results into nationally 

uniform emission performance rates by source subcategory results 

in more stringent goals (compared to the proposal) for states 

whose generation has historically been most heavily concentrated 

at coal-fired steam EGUs. This shift is an expected consequence 

of the use of uniform performance rates by source subcategory. 

At proposal, these states’ goals reflected artificial 

assumptions in the selected goal quantification methodology that 

to a considerable extent limited their emission reduction 
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opportunities based on their states’ borders, and the proposed 

goals therefore were less stringent in states which had 

substantial coal generation and little local NGCC capacity. The 

final rule more realistically recognizes that emission reduction 

opportunities, like other aspects of the interconnected 

electricity system, are regional and are not constrained by 

state borders. The final rule also reflects the EPA’s emphasis 

in the proposal on ensuring the achievability and flexibility of 

the emission guidelines and increasing opportunities for 

interstate and industry-wide coordination. We consequently apply 

the same emission performance rates to coal-fired units in 

states with heavy reliance on coal-fueled generation as we do to 

coal-fired units in other states, which produces more stringent 

state goals than at proposal for the states with the highest 

concentrations of coal-fired generation. At the same time, the 

final goals for some states are less stringent than their 

proposed goals. For example, a goal based on the least stringent 

regional rates is less stringent for some states than a goal 

based on state-specific emission reduction opportunities would 

be. Accordingly, the differences among the final state goals are 

generally smaller than the differences among the proposed state 

goals. All of the final rate-based state goals are necessarily 

apply to in the range bounded by the CO2 emission performance 
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rate for NGCC units and the CO2 emission performance rate for 

steam EGUs because all of the state goals are computed as a 

weighted average of those two performance rates, and this range 

is narrower than the range of state goals in the proposal. 

 The computations of the uniform CO2 emission performance 

rates are shown in the CO2 Emission Performance Rate and Goal 

Computation TSD for the CPP Final Rule. These uniform emission 

performance rates are applicable to the states and areas of 

Indian country517 located in the contiguous U.S. that have 

affected EGUs.518 We have not in this rule applied the uniform 

emission performance rates to Alaska, Hawaii, Puerto Rico, or 

Guam -- states and territories that have otherwise affected EGUs 

but are isolated from the three major interconnections –- that 

is, Alaska, Hawaii, Puerto Rico, and Guam519 –- because affected 

EGUs in those areas lack the same opportunities to access the 

building blocks across wide regions that affected EGUs in the 

 

517 As explained in section III.A. above, an Indian tribe whose 

area of Indian country has affected EGUs will have the 

opportunity but not the obligation to seek authority to develop 

and implement a section 111(d) plan. If no tribal plan is 

approved, the EPA has the responsibility to establish a plan if 

it determines that such a plan is necessary or appropriate. 

518 As noted earlier, there are currently no affected EGUs in 

Vermont or the District of Columbia. 

519 The section 111(d) requirements do not currently apply to the 

other isolated U.S. territories –- the U.S. Virgin Islands, 

American Samoa, and the Northern Mariana Islands –- because no 

affected EGUs currently operate in these territories. 
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contiguous states enjoy. Instead, if the performance rates 

computed using data specific to one of these and will determine 

how to address the requirements of section 111(d) with respect 

to these jurisdictions at a later time. Further discussion 

regarding the isolated states or territories is less stringent 

than the nationwide performance rates, we have determined that 

the less stringent state- or territory-specific rates should 

apply. jurisdictions can be found in section VII.F. of the 

preamble.

 The computations of the regionally uniform performance 

rates for each of the three major interconnections as well as 

Alaska, Hawaii, Guam, and Puerto Rico are shown in the Final 

Rule Goal Computations TSD. 

g. Establishment of a 2022-2029 interim compliance period. The 

June 2014 proposal separately quantified emission limitations 

applicable to an interim 2020-29 period 

and to the period beginning in 2030. The EPA took broad comment 

on this proposed timing. Although the proposal provided 

flexibility in the timing with which emission reductions could 

be made over the course of the 2020-2029 period in order to 

achieve compliance with the emission limitations applicable to 

that interim period, many commenters perceived the start of the 

period as too soon and stated that it provided insufficient time 
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for planning and investments necessary for sources to begin 

complyingimplementation activities while maintaining reliable 

electricity supplies. 

 The EPA has considered these comments and in the final rule 

has established an interim compliance period of 2022-2029, 

providing two additional years for planning and investment 

before the start of compliance. We are persuaded by comments and 

by our own further analysis that this timeframe is appropriate 

given the nature and magnitudewill, in combination with the 

glide path of emission reductions reflected in the final 

building blocks and the states’ flexibility to define their own 

paths of emission reductions over the interim period (as 

discussed in section VIII), provide adequate time for necessary 

planning and investment activities that. This will be necessary 

to begin compliance withenable the final rule’s requirements to 

be implemented in an orderly manner while maintaining 

reliability of electricity supplies is maintained. Further 

discussion is provided in the sections of the preamble 

addressing the individual building blocks (sections V.C., V.D., 

and V.E.) and on electricity system reliability. (section 

VIII.G.2.). 

The initial compliance date of 2022, coupled with the fact 

that the 2030 standard is phased in over the subsequent eight 
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years, affords affected EGUs the benefit of having an extended 

planning period before they need to incur any significant 

obligations. Where needed, states may take the period through 

September 2018 to develop their final plans, and affected EGUs 

will be able to work with the states during that period to 

develop compliance approaches. States will also have the 

flexibility to select their own emissions trajectories in such a 

way that certain emission reduction measures could be 

implemented later in the interim period (again, provided that 

their affected EGUs still meet the interim performance rates or 

interim goal over the interim period as a whole). As a result, 

if the affected EGUs in those states need to incur any expenses 

before the adoption of the final state plans, those expenses 

need not be more than minimal. It is worth noting that an 

earlier state plan submission date provides regulated sources 

with more certainty and time to plan for compliance, but has no 

effect on the time when compliance must be achieved, as the 

mandatory compliance period begins in 2022 for all states. Some 

states that already have established programs for limiting CO2

emissions from power plants may adopt and submit to the EPA 

state plans by September 6, 2016. In those states, sources will 

already have developed compliance approaches to meet state law 

requirements. Other states that submit plans by September 6, 
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2016, may be expected to work with their affected EGUs to 

determine a reasonable compliance approach, in light of the fact 

that compliance is not required to begin until 2022. It is also 

possible that some states will submit neither final state plans 

nor initial submittals by September 6, 2016, and that the EPA 

will promulgate federal plans. Sources in those states will have 

more than five years to meet their 2022 compliance obligations, 

a lengthy period that will afford them the opportunity to plan 

before incurring significant expenditures. 

 These periods of time are consistent with current industry 

practice in changing generation or adding new generation. For 

example, in June 2015, Alabama Power Company announced plans to 

acquire 500 MW of renewable energy generation over the next six 

years. This amount would make up between four and five percent 

of Alabama Power’s generation mix.520 In addition, the study of 

 

520 Alabama Power Co., “Petition for a Certificate of Convenience 

and Necessity,” submitted to the Alabama Public Service 

Commission (June 25, 2015) (petition requests “a certificate of 

convenience and necessity for the construction or acquisition of 

renewable energy and environmentally specialized generating 

resources and the acquisition of rights and the assumption of 

payment obligations under power purchase arrangements pertaining 

to renewable energy and environmentally specialized generating 

resources, together with all transmission facilities, fuel 

supply and transportation arrangements, appliances, 

appurtenances, equipment, acquisitions and commitments necessary 

for or incident thereto”) (included in the docket for this 

rulemaking). See Swartz, Kristi, “Alabama Power plan would 
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utility IRPs placed in the docket for this rulemaking521 shows 

that sources are able to replace coal-fired generation with 

natural-gas fired generation and add incremental amounts of 

renewable energy (as well as take other actions, such as 

implement demand-side energy efficiency programs), on a gradual 

basis, after a several-year lead time, over an extended period, 

as provided for under the final rule. 

h. Refinements to stringency for individual building blocks. For 

each individual building block, the EPA has reexamined the data 

and assumptions used at proposal in light of comments 

received,solicited and has made a number of refinements in the 

final rule in light ofbased on that information. The refinements 

are discussed in the preamble sections for each building block 

(sections V.C., V.D., and V.E.) and goalemission performance 

rate computation (section VI) and in the GHG Mitigation Measures 

TSD for the CPP Final Rule and the CO2 Emission Performance Rate 

and Goal Computation TSD for the CPP Final Rule. In generalAs 

previously noted, viewed in terms of projected nationwide 

emission reductions, (but not necessarily with respect to each 

individual state), these refinements generally tend to make the 

 

dramatically boost its renewables portfolio,” E&E Publishing, 

July 16, 2015. 

521 See memo entitled “Review of Electric Utility Integrated 

Resource Plans” (May 7, 2015) available in the docket. 
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interim goals somewhat less stringent than at proposal withand

the 2030 goals being either at the same level of stringency as 

that of the proposal or at a somewhat more stringent levelthan 

at proposal. In addition to the changes described above, the 

refinements include the following: 

 Use of regional rates ranging from 2.1 percent to 4.3 

percent (rather than 6 percent) as the average heat rate 

improvement opportunity achievable by steam units under 

building block 1. 

 Use of 75 percent of summer capacity (rather than 70 

percent of nameplate capacity) as the target capacity 

factor for existing NGCC units under building block 2. 

 Use of updated information from the National Renewable 

Energy Laboratory (NREL) on renewable energy costs and 

potential, and revision of the list of quantified RE 

technologies to exclude landfill gas under building block 

3. 

4. Determination of the BSER 

 In this rule, the EPA is finalizing as the BSER a 

combination of building blocks 1, 2, and 3, with refinements as 

discussed below. The building blocks constitute the BSER from 

the perspective of the source- category perspectiveas a whole. 

Each building block can be implemented through standards of 
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performance set by the states and includes a set of actions and 

facilitating mechanisms that individual sources can use to 

achieve the emission limitations reflecting the BSER. These 

actions and mechanisms, which include reduced generation and 

emissions trading or other multi-unit compliance approaches, 

represent where the state-set standards of performance 

incorporate trading and which may be understood as part of the 

BSER from the individual-source perspective and , will be 

discussed below in section V.A.5. Each of the building blocks 

consists of measures that the source category and individual 

affected EGUs have already demonstrated the ability to 

implement. In quantifying the application of each building 

block, the EPA has identified reasonable levels of stringency 

rather than the maximum possible levels.

 As discussed above, one of the refinementsmodifications

being made in this rule is the establishment of uniform 

performance rates by technology type. Thesubcategory, which 

enhances the rule’s achievability and flexibility and 

facilitates coordination among the states and across the 

industry. However, in the first instance, the emission 

reductions achievable through use of the building blocks are 

being evaluated on a regional basis that reflects the regional 

nature of the interconnected electricity system and the region-
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wide scope of opportunities available for affected sources in 

each regionEGUs to access emission reduction measures. However, 

theThe EPA recognizes that the emission reduction opportunities 

under these building blocks vary by region because of regional 

differences in the existing mix of types of fossil fuel-fired 

EGUs and the available opportunities to increase low- and zerocarbon generation. InConsequently, in order to achieve uniform 

performance rates by technology type, and to do so in a way that 

respectssubcategory, while respecting these regional differences 

in emission reduction opportunities, we have determined that it 

is reasonable not to establish the stringency of the BSER 

separately by region based on the maximum emission reduction 

that would be achievable in that region, but instead to 

establish uniform stringency across all regions at a level that 

is achievable at reasonable cost in any region. Thus, for each 

technology typesubcategory, the BSER is the combination of the 

elements described above at the combined stringency that is 

reasonably achievable in the Eastern Interconnection, which is 

the region where the CO2 emission performance rates determined to 

be achievable at reasonable cost for both steam by the EGUs and 

combustion turbinesin that subcategory through application of 

the building blocks were least stringent. (For the isolated 

states and territories of Alaska, Hawaii, Puerto Rico, and Guam, 
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if the performance rates determined to be achievable at 

reasonable costs based on the application of the BSER to that 

state or territory are less stringent than the nationwide rates, 

the state- or territory-specific performance rates are used 

instead.) 522 

 This approach is consistent with the EPA’s efforts to 

enhance the achievability and flexibility of the rule and to 

promote interstate and industry coordination and reflects the 

regional strategies emphasized in the proposal and the Notice of 

Data Availability. It is also consistent with the approach we 

have taken in other NSPS rulemakings, where the degree of 

emission limitation achievable through the application of the 

BSER for each subcategory of affected sources generally has been 

determined not on the basis of what is achievable by the sources 

that can reduce emissions most easily, but instead on the basis 

of the least stringent rate that what is reasonably achievable. 

 

522 The determinations of stringency for each source subcategory 

were made independently for each year from 2022 through 2030, 

and in the case of the NGCC category, the limiting region 

changed over time. Thus, for the NGCC category, the uniform CO2

emission performance rate is based on the stringency achievable 

in the Texas Interconnection for the years from 2022 through 

2026 and the stringency achievable in the Eastern 

Interconnection for the years from 2027 through 2030. For the 

steam EGU subcategory, the uniform CO2 emission performance rate 

is based on the stringency achievable in the Eastern 

Interconnection in all years. 
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through the application of the BSER across a range of sources.

This approach also provides compliance headroom –- in addition 

to the headroom provided by our approach to setting the 

stringency for each individual building block -- for affected 

EGUs in regions where theadditional emission reductions that 

couldcan be achieved at reasonable cost exceed the reductions 

that are achievable at reasonable cost in the limiting region, 

thereby promoting nationwide compliance flexibility. Further, 

because we are not geographically restrictingauthorizing states 

to establish standards of performance that incorporate trading 

without geographic restrictions, the opportunity of affected 

EGUs to engage in emissions trading or other multi-unit 

compliance approaches, to the extent allowed under the relevant 

section 111(d) plans, ensures the availability of additional, 

lower-cost emission reduction opportunities in other regions 

that will also promote compliance flexibility and reducesreduce

compliance costs. 

 As discussed in section XI of the preamble and the 

Regulatory Impact Analysis, application of the BSER determined 

as summarized above is projected to result in substantial and 

meaningful reductions of CO2 emissions. 

 Briefly, the elements of the BSER are: 
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Building block 1: Reducing the carbon intensity of generation 

at individualImproving heat rate at affected coal-fired steam 

EGUs through heat rate improvements in specified percentages. 

Building block 2: Substituting increased generation from 

existing affected NGCC units for reduced generation from 

affected steam EGUs in specified quantities. 

Building block 3: Substituting generation from new low- or 

zero-carbonemitting RE generating capacity for reduced 

generation from affected EGUs in specified quantities. 

a. Building block 1. Building block 1 -- reducing the carbon 

intensity of generation at individualimproving heat rate at

affected coal-fired steam EGUs through heat rate improvements -- 

is a component of the BSER with respect to coal-fired steam 

EGUs523 because the measures the affected sourcesEGUs may 

undertake to achieve heat rate improvements are technically 

feasible and of reasonable cost, and perform well with respect 

to other factors relevant to a determination of the “best system 

of emission reduction ... adequately demonstrated.” Building 

 

523

 For the reasons discussed in the proposal, the EPA is not 

determining that heat rate improvements at other types of 

affected EGUs, such as NGCC units and oil-fired and natural gasfired steam EGUs, are components of the BSER. However, all types 

of affected EGUs would be able to employ heat rate improvements 

as measures to help achieve compliance with their assigned 

standards of performance. 
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block 1 is a “system of emission reduction” for steam EGUs 

because owners of these EGUs can take actions that will improve 

their heat rates and thereby reduce their rates of CO2 emissions 

with respect to generation. 

 The EPA has analyzed the technical feasibility, costs, and 

magnitude of CO2 emission reductions achievable through heat rate 

improvements at coal-fired steam EGUs based on engineering 

studies and on these EGUs’ reported operating and emissions 

data. We conclude that taking action to improve heat rates is a 

common and well-established practice within the industry that is 

capable of achieving meaningful reductions in CO2 emissions at 

reasonable cost., although, as discussed earlier, we also 

conclude that the quantity of emission reductions achievable 

through heat rate improvement measures is insufficient for these 

measures alone to constitute the BSER. Specifically, we have 

determined that an average heat rate improvement ranging from 

2.1 to 4.3 percent by all affected coal-fired EGUs, depending on 

the region, is an element of the BSER, based on the inclusion of 

those amounts of improvement in the three regions, determined 

through our regional analysis. Our analysis and conclusions are 

discussed in Section V.C. below and in the GHG Mitigation 

Measures TSD for the CPP Final Rule. Additional analysis and 
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conclusions with respect to cost reasonableness are discussed in 

section V.A.4.d. below.

 Consideration of other BSER factors also favors a 

conclusion that building block 1 is a component of the BSER. For 

example, with respect to non-air health and environmental 

impacts, heat rate improvements cause fuel to be used more 

efficiently, reducing the volumes of, and therefore the adverse 

impacts associated with, disposal of coal combustion solid waste 

products. By definition, heat rate improvements do not cause 

increases in net energy usage. Although we are justifying 

building block 1 as part of the BSER without reference to 

technological innovation, we willalso consider technological 

innovation in the alternative, and we note that building block 1 

encourages the spread of more advanced technology to EGUs 

currently using components with older designs. 

 As noted in the June 2014 proposal, the EPA is concerned 

about the potential “rebound effect” associated with building 

block 1 if applied in isolation. More specifically, we noted 

that in the context of the integrated electricity system, absent 

other incentives to reduce generation and CO2 emissions from 

coal-fired EGUs, heat rate improvements and consequent variable 

cost reductions at those EGUs would cause them to become more 

competitive compared to other EGUs and increase their 
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generation, leading to smaller overall reductions in CO2

emissions (depending on the CO2 emission rates of the displaced 

generating capacity). Unless mitigated, the occurrence of a 

rebound effect would reduce the emission reductions achieved by 

building block 1, exacerbating the inadequacy of emission 

reductions that is the basis for our conclusion that building 

block 1 alone would not represent the BSER for this industry. 

However, we believe that thisour concern about the potential 

rebound effect can be readily addressed by ensuring that the 

BSER also reflects other CO2 reduction strategies that encourage 

increases in generation from lower- or zero-carbon EGUs or in 

demand-side energy efficiency, thereby allowing building block 1 

to be considered an appropriate part of the BSER for CO2

emissions at affected EGUs as long as the building block is 

applied in combination with other building blocks.524 

b. Building block 2. Building block 2 –- reducing CO2 emissions 

at, and substituting for generation from, the most carbonintensive affected EGUs with generation from less carbon-

 

524 Concern about a rebound effect could also be addressed by 

requiring that standards of performance for affected EGUs be set 

in the form of mass-based caps, but the EPA has determined that 

it is appropriate to allow states the flexibility to establish 

either emission rate-based or mass-based standards of 

performance for their affected EGUs. 
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intensive affected EGUs (specifically NGCC units that are 

currently operating or under construction) for generation from 

the most carbon-intensive affected EGUs –- is a component of the 

BSER for steam EGUs because generation shifts that will reduce 

the amount of CO2 emissions at higher-emitting EGUs and from the 

source category as a whole are technically feasible, are of 

reasonable cost, and perform well with respect to other factors 

relevant to a determination of the “best system of emission 

reduction ... adequately demonstrated.” Building block 2 is a 

“system of emission reduction” for steam EGUs because 

incremental generation from existing NGCC units will result in 

reduced generation and emissions from steam EGUs, and owners of 

steam EGUs can, and many do, invest in incremental generation 

from NGCC units through a variety of possible mechanisms. A 

steam EGU investing in incremental generation from NGCC units 

may choose to reduce its own generation or may maintain its 

generation level and choose to allow the reduction in generation 

to occur at other steam EGUs through the coordinated planning 

and operation of the interconnected electricity system. An 

affected EGU may also invest in emission reductions from 

building block 2 through the mechanism of engaging in emissions 

trading. where the EGU is operating under a standard of 

performance that incorporates trading.
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 The EPA’s analysis and conclusions regarding the technical 

feasibility, costs, and magnitude of CO2 emission reductions 

achievable at high-emitting EGUs through generation shifts to 

lower-emitting affected EGUs are discussed in Section V.D.

below. Additional analysis and conclusions with respect to cost 

reasonableness are discussed in section V.A.4.d. below. We 

consider generation shifts among the large number of diverse 

EGUs that are linked to one another and to customers by 

extensive regional transmission grids to be a routine and wellestablished operating practice within the industry that is used 

to facilitate the achievement of a wide variety of objectives, 

including environmental objectives, while meeting the demand for 

electricity services. In the interconnected and integrated 

electricity industry, fossil fuel-fired steam EGUs are able to 

reduce their generation and NGCC units are able to increase 

their generation in a coordinated manner through mechanisms –- 

in some cases centralized and in others not -- that regularly 

deal with such changes on both a short-term and a longer-term 

basis. Our analysis demonstrates that the emission reductions 

that can be achieved or supported by such generation shifts are 

substantial and of reasonable cost. Further, both the 

achievability of this building block and the reasonableness of 

its costs are supported by the fact that there has been a long-
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term trend in the industry away from coal-fired generation and 

toward NGCC generation for a variety of reasons. 

 Building block 2 is adequately demonstrated as a “system of 

emission reduction” for affected steam EGUs. As discussed in 

section V.B., since the time of the 1970 CAA Amendments, the 

utility power sector has recognized that generation shifts are a 

means of controlling air pollutants; in the 1990 CAA Amendments, 

Congress has long recognized that generation shifts among EGUs 

are onea means of reducing emissions from the utility power 

sector and multiple provisions of the CAA reflect that 

recognition,this sector; and generation shifts similarly have 

been recognized as a means of reducing emissions under trading 

programs established by the EPA to implement the Act’s 

provisions. It is common practice in the industry to account for 

the cost of emission allowances as a variable cost when making 

security-constrained, cost-based dispatch decisions; doing so 

integrates generation shifts into the operating practices used 

to achieve compliance with environmental requirements in an 

economical manner. These industry trends are further discussed 

in section V.D. Thus, legislative history, regulatory precedent, 

and industry practice support interpreting the broad term 

“system of emission reduction” as including substituting lower-
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emitting generation for higher-emitting generation through 

generation shifts among affected EGUs. 

 An important additional consideration supporting the 

determination that building block 2 is adequately demonstrated 

as a “system of emission reduction” is that owners of affected 

steam EGUs have the ability to invest in generation shifts as a 

way of reducing emissions. The owner of an affected EGU could 

invest in such generation shifts in several ways, including by 

operatingincreasing operation of an NGCC unit that it already 

owns more or by purchasing an existing NGCC unit and 

operatingincreasing operation of that unit more. Increases in 

generation by NGCC units over baseline levels can also serve as 

the basis for creation of CO2 emission rate credits (ERCs) –- 

that is, instruments representing the ability of incremental 

electricity generated by NGCC units to cause emission reductions 

at affected steam EGUs, as distinct from the incremental 

electricity itself. Again, it is important to note that the 

acquisition of such ERCs, represents an investment in the 

actions of the facility or facilities whose alteration of 

utilization levels generated the emissions rate improvement or 

reduction. In the context of the BSER, purchase of instruments 

representing the emissions-reducing benefit of an action is 

simply a medium of investment in the underlying emissions 
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reduction action. These mechanisms are discussed further in 

section V.A.5. In this rule, the EPA is establishing minimum 

criteria for the creation of valid emission rate creditsERCs by 

NGCC units and for the use of such creditsERCs by affected steam 

EGUs for demonstrating compliance with emission rate-based 

standards of performance established under state plans. The 

existence of minimum criteria will ensure that crediting 

mechanisms are feasible and will facilitate the development of 

organized markets to simplify the process of buying and selling 

creditsERCs. The minimum criteria are discussed in section VIII 

of this preamble. 

 We note that an affected sourceEGU investing in building 

block 2 to reduce emissions may, but need not, also choose to 

reduce its own generation as part of its approach for meeting 

the standard of performance assigned to it by its state. Through 

the coordinated operation of the integrated electricity system, 

subject to the collective emission reduction requirements that 

will be imposed on affected sourcesEGUs in order to meet the 

emissions standards representing the BSER, an increase in NGCC 

generation will be offset elsewhere in the interconnection by a 

decrease in other generation. Because of the need to meet the 

collective emission reduction requirements, the decrease in 

generation resulting from that coordinated operation is most 
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likely to be generation from an affected steam EGU. Measures 

taken by affected sourcesEGUs that result in emission reductions 

from other sourcesEGUs in the source category may appropriately 

be deemed components of ameasures to implement or apply the

“system of emission reduction.”” of substituting lower-emitting 

generation for higher-emitting generation.

 Consideration of other BSER factors also supports a 

determination to include building block 2 as a component of the 

BSER. For example, we expect that building block 2 would have 

positive non-air health and environmental impacts. Coal 

combustion for electricity generation produces large volumes of 

solid wastes that require disposal, with some potential for 

adverse environmental impacts; these wastes are not produced by 

natural gas combustion. The intake and discharge of water for 

cooling at many EGUs also carries some potential for adverse 

environmental impacts; NGCC units generally require less cooling 

water than steam EGUs.525 With respect to energy impacts, 

 

525 For example, according to a DOE/NETL study, the relative 

amount of water consumption for a new pulverized coal plant is 

2.5 times the consumption for a new NGCC unit of similar size. 

“Cost and Performance Baseline for Fossil Energy Plants: Volume 

1: Bituminous Coal and Natural Gas to Electricity,” Rev 2a, 

September 2013, National Energy Technology Laboratory Report 

DOE/NETL-2010/1397. EPA believes the difference would on average 

be even more pronounced when comparing existing coal and NGCC 

units. 
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building block 2 represents replacement of electrical energy 

from one generator with electrical energy from another generator 

that consumes less fuel, so the overall energy impact should be 

a reduction in fuel consumption by the overall source category 

as well as by individual affected coal-fired steam EGUs. 

Although for purposes of this rule we consider the incentive for 

technological advancementinnovation only in the alternative, we 

note that building block 2 does not call for deployment of new 

technology, but does promotepromotes greater use of the NGCC 

technology installed in the existing fleet of NGCC units, which 

is newer and more advanced than the technology installed in much 

of the older existing fleet of steam EGUs. For all these 

reasons, the measures in building block 2 qualify as a component 

of the “best system of emission reduction ... adequately 

demonstrated.” 

 It should be observed that, by definition of the elements 

of this building block, the shifts in generation taking place 

under building block 2 occur entirely among existing EGUs 

subject to this rulemaking.526 Through application of this 

building block considered in isolation, some affected 

 

526 For purposes of this rulemaking, “existing” EGUs include 

units under construction as of January 8, 2014, the date of 

publication in the Federal Register of the Carbon Pollution 

Standards for new fossil fuel-fired EGUs. 
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sourcesEGUs –- mostly coal-fired steam EGUs -- would reduce 

their generation and CO2 emissions, while other affected 

sourcesEGUs –- NGCC units –- would increase their generation and 

CO2 emissions. However, because for each MWh of generation, NGCC 

units produce fewer CO2 emissions than coal-fired steam EGUs, the 

total quantity of CO2 emissions from all affected sourcesEGUs in 

aggregate would decrease without a reduction in total 

electricity generation. In the context of the integrated 

electricity system, where the operation of affected EGUs of 

multiple types is routinely coordinated to provide a 

fungiblehighly substitutable service, and in the context of CO2

emissions, where location is not a consideration, (in contrast 

with other pollutants,), a measure that takes advantage of that 

integration to reduce CO2 emissions from the overall set of 

affected EGUs is readily encompassed within the meaning 

ofunderstood as a means to implement a “system of emission 

reduction” for CO2 emissions at affected EGUs even if the measure 

would increase CO2 emissions from a subset of those affected 

EGUs. Indeed, some industry participants are already moving in 

this direction for this purpose (while other participants are 

moving in the same direction for other purposes). 

EmissionsStandards of performance that incorporate emissions

trading and other multi-unit compliance approaches can 
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facilitate the implementation of such a “system” and such 

approaches have already been used in the electricity industry to 

address CO2 as well as other pollutants, as discussed above. 

c. Building block 3. Building block 3 –- reducing CO2 emissions 

at, and substituting for generation from, affected EGUs by using 

generation from expanded RE generating capacity for reduced 

generation from affected EGUs –- is a component of the BSER 

because the expansion and use of renewable generating capacity 

to reduce emissions from affected sourcesEGUs is technically 

feasible, will not jeopardize system reliability, is of 

reasonable cost, and performs well with respect to other factors 

relevant to a determination of the “best system of emission 

reduction ... adequately demonstrated.” Building block 3 is a 

“system of emission reduction” for all affected EGUs because 

incremental RE generation will result in reduced generation and 

emissions from affected EGUs, and owners or operators of 

affected EGUs can apply or implement building block 3 through a 

number of actions. For example, they can invest in incremental 

RE generation either directly or through the purchase of 

emission rate creditsERCs. An affected EGU investing in 

incremental RE generation may choose to reduce its own 

generation by a corresponding amount or may choose to allow the 

reduction in generation to occur at other affected EGUs through 
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the coordinated planning and operation of the interconnected 

electricity system. An affected EGU can also invest in RE 

generation by means of engaging in emissions trading. where the 

EGU is operating under a standard of performance that 

incorporates trading.

 The EPA’s analysis and conclusions regarding the technical 

feasibility, costs, and magnitude of the measures in building 

block 3 are discussed in Section V.E. below. Additional analysis 

and conclusions with respect to cost reasonableness are 

discussed in section V.A.4.d. below. We consider construction 

and operation of expanded RE generating capacity to be proven, 

well-established practices within the industry consistent with 

recent industry trends. States are already pursuing policies 

that encourage production of greater amounts of renewable 

energy, such as the establishment of targets for procurement of 

renewable generating capacity. Moreover, as discussed earlier, 

markets are likely to develop for emission rate creditsERCs that 

would facilitate investment in increased RE generation as a 

means of helping sources comply with their standards of 

performance; indeed, markets for renewable energy certificates, 

which similarly facilitate investment in renewable energy for 

other purposes, are already well-established. As noted in 

Section V.A.5. below, an allowance system or tradable emission 
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rate system would provide incentives for affected sourcesEGUs to 

reduce their emissions as much as possible, where such 

reductions could be achieved economically (taking into account 

the value of the emission credits or allowances), including 

throughby substituting for their generation with generation from 

new renewable energy generating capacity for their own 

generation, or could provide a mechanism, as stated above, for 

such sources to invest in or acquire such generation. 

 Building block 3 is adequately demonstrated as a “system of 

emission reduction” for all affected EGUs. As discussed in 

section II, RE generation has been relied on since the 1970s to 

provide energy security by replacing some fossil fuel-fired 

generation. Both Congress and the EPA have previously 

established frameworks under which RE generation could be used 

as a means of achieving emission reductions from the utility 

power sector, as discussed in section V.B. Investment in RE 

generation has grown rapidly, such that in recent years the 

amount of new RE generating capacity brought into service has 

been comparable to the amount of new fossil fuel-fired capacity. 

Rapid growth in RE generation is projected to continue as costs 

of RE generation fall relative to the costs of other generation 

technologies. These trends are further discussed in section V.E. 

Interpretation of a “system of emission reduction” as including 
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RE generation for purposes of this rule is thus supported by 

legislative history, regulatory precedent, and industry 

practice. 

 Also supporting the determination that building block 3 is 

adequately demonstrated as a “system of emission reduction” is 

the fact that owners of affected EGUs have the ability to invest 

in RE generation as a way of reducing emissions. As with 

building block 2, this can be accomplished in several ways. For 

example, the owner of an affected EGU could invest in new RE 

generating capacity and operate that capacity. Operation of new 

RE generating capacity could also serve as the basis for 

issuance of an ERC, and the owner of the affected EGU could 

either operate new RE generating capacity in order to obtain 

ERCs or in order to obtain ERCs. Alternatively, the affected EGU

could purchase ERCs created based on the operation of an 

unaffiliated RE generating facility, effectively investing in 

the actions at another site that allow CO2 emission reductions to 

occur. These mechanisms are discussed further in section V.A.5. 

As with building block 2, in this rule the EPA is establishing 

minimum criteria for the creation of valid emission rate 

creditsERCs by new RE generators and for the use of such 

creditsERCs by affected EGUs for demonstrating compliance with 

emission rate-based standards of performance established under 
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state plans. The existence of minimum criteria will ensure that 

crediting mechanisms are feasible and will facilitate the 

development of organized markets to simplify the process of 

buying and selling credits. The minimum criteria are discussed 

in section VIII of the preamble. 

 As with building block 2, an affected sourceEGU investing 

in building block 3 to reduce emissions may, but need not, also 

choose to reduce its own generation as part of its approach for 

meeting the standard of performance assigned to it by its state. 

Through the coordinated operation of the integrated electricity 

system, subject to the collective requirements that will be 

imposed on affected sourcesEGUs in order to meet the emissions 

standards representing the BSER, an increase in RE generation 

will be offset elsewhere in the interconnection by a decrease in 

other generation. Because of the need to meet the collective 

requirements, the decrease in generation resulting from that 

coordinated operation is most likely to be generation from an 

affected EGU. As discussed in section V.B., measuresMeasures

taken by affected sourcesEGUs that result in emission reductions 

from other sources in the source category may appropriately be 

deemed components of amethods to implement the “system of 

emission reduction.” 
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 The renewable capacity measures in building block 3 

generally perform well against other BSER criteria. Generation 

from wind turbines and solar voltaic installations, two common 

renewable technologies, does not produce solid waste or require 

cooling water, a better environmental outcome than if that 

amount of generation had instead been produced at a typical 

range of fossil fuel-fired EGUs. With respect to energy impacts, 

fossil fuel consumption will decrease both for the source 

category as a whole and for individual affected EGUs. Although 

the intermittentvariable nature of generation from renewable 

resources such as wind and solar units requires special 

consideration from grid operators to address possible changes in 

operating reserve requirements, renewable generation has grown 

quickly in recent years, as discussed above, and grid planners 

and operators have proven capable of addressing any consequent 

changes in requirements through ordinary processes. The EPA 

similarly believes that planners and operators will be similarly

capable of addressing any changes in requirements due to future 

growth in renewable generation through ordinary processes, but 

notes that in addition, the reliability safety valve in this 

rule, discussed in section VIII.HG.2, will ensure the absence of 

adverse energy impacts. With respect to technological 

innovation, an alternative considerationwhich we consider for 
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the BSER only in the alternative, incentives for expansion of 

renewable capacity encourage technological innovation in 

improved renewable technologies as well as more extensive 

deployment of current advanced technologies. For all these 

reasons, the measures in building block 3 qualify as a component 

of the “best system of emission reduction ... adequately 

demonstrated.” 

d. Combination of all three building blocks. The final BSER 

includes a combination of all three building blocks. For the 

reasons described below, and similar to each of the building 

blocks, the combination must be considered a “system of emission 

reduction.” Moreover, as also discussed below, the combination 

qualifies as the “best” system that is “adequately 

demonstrated.” The combination is technically feasible; it is 

capable of achieving meaningful reductions in CO2 emissions from 

affected EGUs at a reasonable cost; it also performs well 

against the other BSER factors; and its components are wellestablished. The combination of the three building blocks will 

achieve greater CO2 emission reductions at reasonable costs than 

possible combinations with fewer building blocks and will also 

perform better against other BSER factors. We therefore find the 

combination of all three building blocks to be the “best system 
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of emission reduction ... adequately demonstrated” for reducing 

CO2 emissions at affected EGUs.527 

As already discussed, each of the individual building 

blocks generally performs well with respect to the BSER factors 

identified by the statute and the D.C. Circuit. (The exception, 

which we have pointed out above, is that building block 1, if 

implemented in isolation, would achieve an insufficient 

magnitude of emission reductions to be considered the BSER.) The 

EPA expects that combinations of the building blocks would 

perform better than the individual building blocks. Beginning 

with the most obvious and important advantage, combinations of 

the building blocks will achieve greater emission reductions 

than the individual building blocks would in isolation, assuming 

that the building blocks are applied with the same stringency. 

Because fossil fuel-fired EGUs generally have higher variable 

costs than other EGUs, it will generally be fossil fuel-fired 

generation that is replaced when low-variable cost RE generation 

 

527 The analysis of the interactions among building blocks 

provided above for the combination of building blocks 1 and 2, 

indicating that the addition of building block 2 would mitigate 

the potential concern about a “rebound effect” if building block 

1 were implemented in isolation, applies to the combination of 

all three building blocks as well; in fact, the addition of 

building block 3 would further mitigate that concern. The EPA 

believes that if implemented in combination, each of the three 

building blocks would achieve substantial reductions in CO2

emissions from affected EGUs at a reasonable cost. 
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is increased. At the levels of stringency determined to be 

reasonable in this rule, opportunities to deploy building block 

2 to replace higher-emitting generation and to deploy building 

block 3 to replace any emitting generation are not exhausted. 

Thus, as the system of emission reduction is expanded to include 

each of these building blocks, the emission reductions that will 

be achieved increase. 

Because the stringency and timing of emission reductions 

achievable through use of each individual building block have 

been set based on what is achievable at reasonable cost rather 

than the maximum achievable amount, the stringency of the 

combination of building blocks is also reasonable, and the 

combination provides headroom and additional flexibility for 

states in setting standards of performance and for sources in 

complying with those standards to choose among multiple means of 

reducing emissions. 

With respect to the quantity of emission reductions 

expected to be achieved from building block 1 in particular, the 

BSER encompassing all three building blocks is a substantial 

improvement over building block 1 in isolation. As noted 

earlier, the EPA is concerned that implementation of building 

block 1 in isolation not only would achieve insufficient 

emission reductions assuming generation levels from affected 
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steam EGUs were held constant, but also has the potential to 

result in a “rebound effect.” The nature of the potential 

rebound effect is that by causing affected steam EGUs to improve 

their heat rates and thereby lower their variable operating 

costs, building block 1 if implemented in isolation would make 

those EGUs more competitive relative to other, lower-emitting 

fossil fuel-fired EGUs, possibly resulting in increased 

generation and higher emissions from the affected steam EGUs in 

spite of their lower emission rates. Combining building block 1 

with the other building blocks addresses this concern by 

ensuring that owner/operators of affected steam EGUs as a group 

would have appropriate incentives not only to improve the steam 

EGUs’ efficiency but also to reduce generation from those EGUs 

consistent with replacement of generation by lowerlow- or 

nonzero-emitting EGUs and avoidance of generation through 

demand-side energy efficiency. While combining building block 1 

with either building block 2 or 3 should address this concern, 

the combination of all three building blocks addresses it more 

effectively by strengthening the incentives to reduce generation 

from affected steam EGUs. 

The combination of all three building blocks is also of 

reasonable cost. In general, building blocks 2 and 3 do not 

interact with one another in a manner that would cause the cost 
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of deploying any of these building blocks in combination with 

the other building blocks to be more than the cost of deploying 

the respective building block in isolation to the same degree of 

stringency. The EPA recognizes that as increasing quantities of 

generation from higher-emitting EGUs are replaced, the avoided 

cost of the generation that is being replaced by lower- or nonemitting generation decreases, but, for a number of independent 

reasons described below. The emission reductions associated with 

the BSER determined in this rule are significant, necessary, and 

achievable. As discussed in section V.A.1. above, the 

Administrator must take cost into account when determining that 

the measures constituting the BSER are adequately demonstrated, 

and the Administrator has done so here. Below, we summarize 

information on the cost of the building block measures and 

discuss the several independent reasons for the Administrator’s 

determination that the costs of the building block 1, 2, and 3 

measures, alone or in combination, are reasonable. In 

considering whether these costs are reasonable, the EPA 

considered the costs in light of both the observed and projected 

effects of GHGs in the atmosphere, their effect on climate, and 

the public health and welfare risks and impacts associated with 

such climate change, as described in Section II.A. The EPA 

focused on public health and welfare impacts within the United 
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States, but the impacts in other world regions strengthen the 

case for action because impacts in other world regions can in 

turn adversely affect the United States or its citizens. In 

looking at whether costs were reasonable, the EPA also 

considered that EGUs are by far the largest emitters of GHGs 

among stationary sources in the U.S., as more fully set forth in 

section II.B. 

As described in sections V.C. through V.E. and the GHG 

Mitigation Measures TSD, the EPA has determined that the cost of 

each of the three building blocks is reasonable. In summary, 

these cost estimates are $23 per ton of CO2 reductions for 

building block 1, $24 per ton for building block 2, and $37 per 

ton for building block 3. The EPA estimates that, together, the 

three building blocks are able to achieve CO2 reductions at an 

average cost of $30 per ton, which the EPA likewise has 

determined is reasonable. The $30 per ton estimate is an average 

of the estimates for each building block, weighted by the total 

estimated cumulative CO2 reductions for each of these building 

blocks over the 2022-2030 period. While it is possible to weight 

each building block by other amounts, the EPA believes that 

weighting by cumulative CO2 reductions best reflects the average 

cost of total reduction potential across the three building 
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blocks. The EPA considers each of these cost levels reasonable 

for purposes of the BSER established for this rule. 

The EPA views the weighted average cost estimate as a 

conservatively high estimate of the cost of deploying all three 

building blocks simultaneously. The simultaneous application of 

all three building blocks produces interactive dynamics, some of 

which could increase the cost and some of which could decrease 

the cost represented in the individual building blocks. For 

example, one dynamic that would tend to raise costs (and whose 

omission would therefore make the weighted average understate 

costs) is that the emission reduction measures associated with 

building blocks 2 and 3 both prioritize the replacement of 

higher-cost generation (from affected steam EGUs in the case of 

building block 2 and from all affected EGUs in the case of 

building block 3). The EPA recognizes that the increased 

magnitude of generation replacement when building blocks 2 and 3 

are implemented together necessitates that some of the 

generation replacement will occur at more efficient affected 

EGUs, at a relatively higher cost; however, this is a 

consequence of the greater emission reductions that can be 

achieved by combining building blocks, not an indication that 

any individual building block has become more expensive because 

of the combined deployment. Moreover, the likely use of 
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emissions trading or other multi-unit compliance approaches, 

which are inherent in the building blocks as discussed above, 

will further reduce the overall costs of this rule by 

facilitating the ability of individual affected EGUs to take 

advantage of instances where other affected EGUs have 

opportunities to reduce emissions at lower cost.

TheAlso, the EPA recognizes that when building block 1 is 

combined with the other building blocks, the combination has the 

potential to raise the cost of the portion of the overall 

emission reductions achievable through heat rate improvements 

relative to the cost of those same reductions if building block 

1 were implemented in isolation (assuming for purposes of this 

discussion that the rebound effect is not an issue and that the 

affected steam EGUs would in fact reduce their emissions if 

building block 1 were implemented in isolation).528 However, we 

believe that the cost of emission reductions achieved through 

heat rate improvements in the context of a three-building block 

 

528 If an EGU produces less generation output, then an 

improvement in that EGU’s heat rate and rate of CO2 emissions per 

unit of generation produces a smaller reduction in CO2 emissions. 

If the investment required to achieve the improvement in heat 

rate and emission rate is the same regardless of the EGU’s 

generation output, then the cost per unit of CO2 emission 

reduction will be higher when the EGU’s generation output is 

lower. Commenters have also stated that operating at lower 

capacity factors may cause units to experience deterioration in 

heat rates.
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BSER will remain reasonable for two reasons. First, as discussed 

in section V.C. below, even when conservatively high investment 

costs are assumed, the cost of CO2 emission reductions achievable 

through heat rate improvements is quite low, and enough that the 

cost per ton of CO2 emission reductions will remain reasonable 

even if itthat cost is substantially increased. Second, although 

under a BSER encompassing all three building blocks the volume 

of coal-fired generation will decrease, that decrease is 

unlikely to be spread uniformly among all coal-fired EGUs. It is 

more likely that some coal-fired EGUs will decrease their 

generation slightly or not at all while others will decrease 

their generation by larger percentages or cease operations 

altogether. We would expect EGU owners to take these changes in 

EGU operating patterns into account when considering where to 

invest in heat rate improvements, with the result that there 

will be a tendency for such investments to be concentrated in 

EGUs whose generation output is expected to decrease the least. 

This enlightened bias in spending on heat rate improvements –- 

that is, focusing investments on EGUs where such improvements 

will have the largest impacts and produce the highest returns, 

given consideration of projected changes in dispatch patterns –- 

will tend to mitigate any deterioration in the cost of CO2

emission reductions achievable through heat rate improvements. 
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For the regulatory impacts analysis accompanying this final 

rule, the EPA has assessed the costs, benefits, and other 

impacts of deployment of the final BSER through section 111(d) 

plans. The analysis reflects the compliance flexibility under 

the rule, along with transmission and pipeline capabilities and 

constraints, fuel market and electricity dispatch dynamics, and 

seasonal electricity load requirements. As described below in 

Section X, the results indicate that compliance with standards 

of performance consistent with the final BSER is readily 

achievable with no adverse impacts on electricity system 

reliability, and that impacts on retail electricity prices are 

modest and fall within the range of price variability seen 

historically in response to changes in factors such as weather 

and fuel supply. Further, the costs tend to decline over time as 

states and regulated entities take advantage of the available 

flexibility and expand deployment of more cost-effective 

measures (notably demand-side energy efficiency). The EPA 

considers this analysis strong confirmation of the 

reasonableness of the costs of the measures in the three 

building blocks in combination as the best system of emission 

reduction. 

In contrast with those prior examples, combining the 

building blocks also produces interactive dynamics that 
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significantly reduce the cost for CO2 reductions represented in 

the individual building blocks (and whose omission would 

therefore make the weighted average overstate costs). Foremost 

among these dynamics is the stabilization of wholesale power 

prices. When assessed individually, building blocks 2 and 3 have 

opposite impacts on wholesale power prices, although in each 

case, the direction of the wholesale power price impact 

corresponds to an increasing cost of that building block in 

isolation. For example, building block 2 promotes more 

utilization of existing NGCC capacity, which (assessed on its 

own) would increase natural gas consumption and therefore price, 

in turn raising wholesale power prices (which are often 

determined by gas-fired generators as the power supplier on the 

margin); this dynamic puts upward pressure on the cost of 

achieving CO2 reductions through shifting generation from steam 

EGUs to NGCC units.529 Meanwhile, building block 3 increases RE 

deployment; because RE generators have very little variable 

cost, an increase in RE generation replaces other supply with 

higher variable cost, which would yield lower wholesale power 

prices. Lower wholesale power prices would make further RE 

deployment less competitive against generation from existing 

 

529 The EPA’s cost-effectiveness estimate of $24 per ton for 

building block 2 reflects these market dynamics. 
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emitting sources; while this dynamic would generally reduce 

electricity prices to consumers, it also puts upward pressure on 

the cost of achieving CO2 reductions through increased RE 

deployment.530 Applying building blocks 2 and 3 together produces 

significantly more CO2 reductions at a relatively lower cost 

because the countervailing nature of these wholesale power price 

dynamics mitigates the primary cost drivers for each building 

block.531

The EPA believes the dynamics tending to cause the weighted 

average above to overstate costs of the combination of building 

blocks are greater than the dynamics tending to cause costs to 

be understated, and that the weighted average costs are 

therefore conservatively high. Analysis performed by the EPA at 

an earlier stage of the rulemaking supports this conclusion. At 

proposal, the EPA evaluated the cost of increasing NGCC 

 

530 The EPA’s cost-effectiveness estimate of $37 per ton for 

building block 3 reflects these market dynamics. 

531 Notwithstanding the interactive dynamics that improve the 

cost effectiveness of emission reductions when building blocks 2 

and 3 are implemented together, we also consider each of these 

building blocks to be independently of reasonable cost, so that 

either building block 2 or 3 alone, or combinations of the 

building blocks that include either but not both of these two 

building blocks, could be the BSER if a court were to strike 

down the other building block, as discussed in section V.A.7. 

below. (We also note in section V.A.7. that a combination of 

building blocks 2 and 3 without building block 1 could be the 

BSER if a court were to strike down building block 1.) 
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utilization (building block 2) and deploying incremental RE 

generation (building block 3) independently, as well as the cost 

of simultaneously increasing NGCC utilization and incremental RE 

generation. The average cost (in dollars per ton of CO2 reduced) 

was less for the combined building block scenario, showing that 

the net outcome of the interactivity effects described above is 

a reduction in cost per ton when compared to cost estimates that 

do not incorporate this interactivity.532 

A final reason why the EPA considers the weighted-average 

cost above conservatively high is that simply combining the 

building blocks at their full individual stringencies overstates 

the stringency of the BSER. As discussed in section V.A.3.f and 

section VI, the BSER reflects the combined degree of emission 

limitation achieved through application of the building blocks 

in the least stringent region. By definition, in the other two 

regions, the BSER is less stringent than the simple combination 

of the three building blocks whose stringency is represented in 

the weighted-average cost above. 

 

532 Specifically, at proposal the EPA quantified the average 

cost, in dollar per ton of CO2 reduced, of building blocks 1, 2, 

and 3 ($22.5 per ton) to be less than the cost of either 

building block 2 ($28.9 per ton) or building block 3 ($23.4 per 

ton) alone. 
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The cost estimates for each of the three building blocks 

cited above -- $23, $24, and $37 per ton of CO2 reductions from 

building blocks 1, 2, and 3, respectively – are each 

conservatively high for the reasons discussed in section V.C., 

V.D., and V.E. below. Likewise, the $30 per ton weighted-average 

cost of all three building blocks is a conservatively high 

estimate of the cost of the combination of the three individual 

building block costs, as described above. While conservatively 

high, and especially so in the case of the $30 per ton weightedaverage cost, these estimates fall well within the range of 

costs that are reasonable for the BSER for this rule. 

In assessing cost reasonableness for the BSER determination 

for this rule, the EPA has compared the estimated costs 

discussed above to two types of cost benchmark. The first type 

of benchmark comprises costs that affected EGUs incur to reduce 

other air pollutants, such as SO2 and NOX. In order to address 

various environmental requirements, many coal-fired EGUs have 

been required to decide between either shutting down or 

installing and operating flue gas desulfurization (FGD) 

equipment – that is, wet or dry scrubbers – to reduce their SO2

emissions. The fact that many of these EGUs have chosen 

scrubbers in preference to shutting down is evidence that 

scrubber costs are reasonable, and we believe that the cost of 
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these controls can reasonably serve as a cost benchmark for 

comparison to the costs of this rule. We estimate that for a 

300-700 MW coal-fired steam EGU with a heat rate of 10,000 Btu 

per kWh and operating at a 70 percent utilization rate, the 

annualized costs of installing and operating a wet scrubber are 

approximately $14 to $18 per MWh and the annualized costs of 

installing and operating a dry scrubber are approximately $13 to 

$16 per MWh.533 

In comparison, we estimate that for a coal-fired steam EGU 

with a heat rate of 10,000 Btu per kWh, assuming the 

conservatively high cost of $30 per ton of CO2 removed through 

the combination of all three building blocks, the cost of 

reducing CO2 emissions by the amount required to achieve the 

uniform CO2 emission performance rate for steam EGUs of 1,305 

lbs. CO2 per MWh would be equivalent to approximately $11 per 

MWh. The comparable costs for achieving the required emission 

performance rate for steam EGUs through use of the individual 

building blocks range from $8 to $14 per MWh. For an NGCC unit 

with a heat rate of 7,800 Btu per kWh, assuming a conservatively 

high cost of $37 per ton of CO2 removed through the use of 

 

533 For details of these computations, see the memo “Comparison of 

building block costs to FGD costs” available in the docket. 
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building block 3,534 the cost of reducing CO2 emissions by the 

amount required to achieve the uniform CO2 emission performance 

rate for NGCC units of 771 lbs. CO2 per MWh would be equivalent 

to approximately $3 per MWh.535 These estimated CO2 reduction 

costs of $3 to $14 per MWh to achieve the CO2 emission 

performance rates are either less than the ranges of $14 to $18 

and $13 to $16 per MWh to install and operate a wet or dry 

scrubber, or in the case of CO2 emission reductions at a steam 

unit achieved through building block 3, near the low end of the 

ranges of scrubber costs. This comparison demonstrates that the 

costs associated with the BSER in this rule are reasonable 

compared to the costs that affected EGUs commonly face to comply 

with other environmental requirements. 

The second type of benchmark comprises CO2 prices that 

owners of affected EGUs use for planning purposes in their IRPs. 

Utilities subject to requirements to prepare IRPs commonly 

include assumptions regarding future environmental regulations 

that may become effective during the time horizon covered by the 

IRP, and assumptions regarding CO2 regulations are often 

represented in the form of assumed prices per ton of CO2 emitted 

 

534 The comparison for an NGCC unit considers only building block 

3 because building blocks 1 and 2 do not apply to NGCC units. 

535 For details of these computations, see the memo “Comparison of 

building block costs to FGD costs” available in the docket. 
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or reduced. A survey of the CO2 price assumptions from 46 recent 

IRPs shows a range of CO2 prices in the IRPs’ reference cases of 

$0 to $30 per ton, and a range of CO2 prices in the IRPs’ high 

cases from $0 to $110 per ton.536 In comparison, the 

conservatively high, weighted-average cost of $30 per ton 

removed described above is at the high end of the range of 

reference case assumptions but at the low end of the range of 

the high case assumptions. The costs of the individual building 

blocks are likewise well within the range of the high case 

assumptions, and either at or slightly above the high end of the 

reference case assumptions. This comparison demonstrates that 

the costs associated with the BSER in this rule are reasonable 

compared to the expectations of the industry for the potential 

costs of CO2 regulation. 

In addition to comparison to these benchmarks, there is a 

third independent way in which EPA has considered cost. In light 

of the severity of the observed and projected climate change 

effects on the U.S., U.S. interests, and U.S. citizens, combined 

with EGUs’ large contribution to U.S. GHG emissions, the costs 

 

536 See Synapse Energy Economics Inc., 2015 Carbon Dioxide Price 

Forecast (March 3, 2015) at 25-28, available at

http://www.synapseenergy.com/sites/default/files/2015%20Carbon%20Dioxide%20Price%2

0Report.pdf. 
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of the BSER measures are reasonable when compared to other 

potential control measures for this sector available under 

section 111. Given EGUs’ large contribution to U.S. GHG 

emissions, any attempt to address the serious public health and 

environmental threat of climate change must necessarily include 

significant emission reductions from this sector. The agency 

would therefore consider even relatively high costs – which 

these are not – to be reasonable. Imposing only the lower cost 

reduction measures in building block 1 would not achieve 

sufficient reductions given the scope of the problem and EGUs’ 

contribution to it. While the EPA also considered measures such 

as CCS retrofits for all fossil-fired EGUs or co-firing at all 

steam units, the EPA determined that these costs were too high 

when considered on a sector-wide basis. Furthermore, the EPA 

has not identified other measures available under section 111 

that are less costly and would achieve emission reductions that 

are commensurate with the scope of the problem and EGUs’ 

contribution to it. Thus, the EPA determined that the costs of 

the measures in building blocks 1, 2 and 3, individually or in 

combination, are reasonable because they achieve an appropriate 

balance between cost and amount of reductions given the other 

potential control measures under section 111. 
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As required under Executive Order 12866, the EPA conducts 

benefit-cost analyses for major Clean Air Act rules.537 While 

benefit-cost analysis can help to inform policy decisions, as 

permissible and appropriate under governing statutory 

provisions, the EPA does not use a benefit-cost test (i.e., a 

determination of whether monetized benefits exceed costs) as the 

sole or primary decision tool when required to consider costs or 

to determine whether to issue regulations under the Clean Air 

Act, and is not using such a test here.538 Nonetheless, the EPA 

observes that the costs of the building block 1, 2 and 3 

measures, both individually and combined as discussed in this 

section above, are less than the central estimates of the social 

cost of carbon. Developed by an interagency workgroup, the 

social cost of carbon (SC-CO2) is an estimate of the monetary 

value of impacts associated with marginal changes in CO2

emissions in a given year.539 It is typically used to assess the 

 

537 The EPA’s regulatory impact analysis for this rule, which 

appropriately includes a representation of the flexibility 

available under the rule to comply using a combination of BSER 

and non-BSER measures (such as demand-side energy efficiency) is 

discussed in section XI of the preamble. 

538 See memo entitled “Consideration of Costs and Benefits Under 

the Clean Air Act” available in the docket. 

539 Estimates are presented in the Technical Support Document: 

Technical Update of the Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866 (May 2013, Revised 

July 2015), Interagency Working Group on Social Cost of Carbon, 
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avoided damages as a result of regulatory actions (i.e., 

benefits of rulemakings that lead to an incremental reduction in 

cumulative global CO2 emissions).540 The central values for the 

SC-CO2 range from $40 per short ton in 2020 to $48 per short ton 

in 2030.541 The weighted-average cost estimate of $30 per ton is 

well below this range. 

Finally, the EPA notes that the combination of all three 

building blocks would perform consistently with the individual 

building blocks with respect to non-air energy and environmental 

impacts. There is no reason to expect an adverse non-air 

environmental or energy impact from deployment of the 

combination of the three building blocks. , whether considered 

 

with participation by Council of Economic Advisers, Council on 

Environmental Quality, Department of Agriculture, Department of 

Commerce, Department of Energy, Department of Transportation, 

Environmental Protection Agency, National Economic Council, 

Office of Energy and Climate Change, Office of Management and 

Budget, Office of Science and Technology Policy, and Department 

of Treasury (May 2013, Revised July 2015). Available at: 

<https://www.whitehouse.gov/sites/default/files/omb/inforeg/scctsd-final-july-2015.pdf> Accessed 7/11/2015. 

540 The SC-CO2 estimates do not include all important damages 

because of current modeling and data limitations. The IPCC Fifth 

Assessment report observed that SC-CO2 estimates omit various 

impacts that would likely increase damages. 

541 The 2010 and 2013 TSDs present SC-CO2 in 2007$ per metric ton. 

The unrounded estimates from the current TSD were adjusted to 

(1) 2011$ using GDP Implicit Price Deflator (1.061374), 

http://www.bea.gov/iTable/index_nipa.cfm and (2) short tons 

using the conversion factor of 0.90718474 metric tons in a short 

ton. These estimates were rounded to two significant digits. 
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on a source-by-source basis, on a sector-wide or national basis, 

or both. In fact, the combination of the building blocks, like 

the building blocks individually, as discussed above, would be 

expected to produce non-air environmental co-benefits in the 

form of reduced water usage and solid waste production (and, in 

addition to these non-air environmental co-benefits, would also 

be expected to reduce emissions of non-CO2 air pollutants such as 

SO2, NOX, and mercury). Likewise, with respect to technological 

innovation, which we consider only in the alternative, the 

building blocks in combination would have the same positive 

effects that they would have if implemented independently.

he. Other combinations of the building blocks. The EPA has 

considered whether other combinations of the building blocks, 

such as a combination of building blocks 1 and 2 or a 

combination of building blocks 1 and 3, could be the BSER. We 

believe that any such combination is technically feasible and 

would be a “system of emission reduction” capable of achieving 

meaningful reductions in CO2 emissions from affected EGUs at a 

reasonable cost. As with the combination of three building 

blocks discussed above, any combination of building blocks would 

achieve greater emission reductions than the individual building 

blocks encompassed in that combination would achieve if 

implemented in isolation. Further, the cost of any combination 
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would be driven principally by the combined stringency and would 

remain reasonable in aggregate., such that the conclusions on 

cost reasonableness discussed in section V.A.4.d. would continue 

to apply. We have already noted our determination that building 

block 1 in isolation is not the BSER because it would not 

produce a sufficient quantity of emission reductions. A 

combination of building block 1 with one of the other building 

blocks would produce greater emission reductions and would not 

be subject to this concern. Any combination of building blocks 

including building block 1 and at least one other building block 

would also address the concern about potential “rebound 

effect”,” discussed above., that could occur if building block 1 

were implemented in isolation. Finally, there is no reason to 

expect any combination of the building blocks to have adverse 

non-air energy or environmental impacts, and the implications 

for technological innovation, which we consider only in the 

alternative, would likewise be positive for any combination of 

the building blocks because those implications are positive for 

the individual building blocks and there is no reason to expect 

negative interaction from a combination of building blocks. 

For these reasons, any combination of the building blocks 

(but not a BSER comprising building block 1 in isolation) could 

be the BSER if it were not for the fact that a BSER comprising 
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all three of the building blocks will achieve greater emission 

reductions at a reasonable cost and is therefore “better.” As 

discussed below in section V.A.7., we intend for the individual 

building blocks to be severable, such that if a court were to 

strike down adeem building block 2 or 3 defective, but not both, 

the BSER would comprise the remaining building blocks. 

f. Achievability of emission limits. As noted, based on the 

BSER, the EPA has established a source subcategory-specific 

emission performance rate for fossil steam units and one for 

NGCC units. As discussed in section V.A.1.c., for new sources, 

standards of performance must be “achievable” under CAA section 

111(a)(1), and the D.C. Circuit has identified criteria for 

achievability.542 In this rule, the EPA is taking the approach 

that while the states are not required to adopt those source 

subcategory-specific emission performance rates as the standards 

of performance for their affected EGUs, those rates must be 

achievable by the steam generator and NGCC subcategories, 

respectively. In addition, the EPA is assuming that the 

achievability criteria in the case law for new sources apply to 

 

542 See Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 

(D.C. Cir. 1973), cert. denied, 416 U.S. 969 (1974); Nat’l Lime 

Ass’n v. EPA, 627 F.2d 416, 433, n.46 (D.C. Cir. 1980); Sierra 

Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981) (citing Nat’l 

Lime Ass’n v. EPA, 627 F.2d 416 (D.C. Cir. 1980). 
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existing sources under section 111(d). For the reasons discussed 

next, for this rule, the source subcategory-specific emission 

performance rates are achievable in accordance with those 

criteria in the case law. 

As noted, the building blocks include several features that 

assure that affected EGUs may implement them. The building 

blocks may be implemented through a range of methods, including 

through the purchase of ERCs and emission trading. In addition, 

the building blocks incorporate “headroom.” Moreover, the source 

subcategory-specific emission performance rates apply on an 

annual basis, so that short-term issues need not jeopardize 

compliance. In addition, we quantify the emission performance 

rates based on the degree of emission limitation achievable by 

affected EGUs in the region where application of the combined 

building blocks results in the least stringent emission rate. 

Because the means to implement the building blocks are widely 

available and because of the just-noted flexibilities and 

approaches to the emission performance rates, all types of 

affected steam generating units, operating throughout the lower48 states and under all types of regulatory regimes, are able to 

implement building blocks 1, 2 and 3 and thereby achieve the 

emission performance rate for fossil steam units, and all types 

of NGCC units operating in all states under all types of 
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regulatory requirements are able to implement building block 3 

and thereby achieve the emission performance rate for NGCC 

units.543 

Commenters have raised questions about whether particular 

circumstances could arise, such as the sudden loss of certain 

generation assets, that would cause the implementation of the 

building blocks to cause reliability problems, and have 

cautioned that these circumstances could preclude implementation 

of the building blocks and thus achievement of the emission 

performance rates. Commenters have also raised concerns about 

whether affected EGUs with limited remaining useful lives can 

implement the building blocks and achieve the emission 

performance rates. We address those concerns in section VIII, 

where we authorize state plans to include a reliability 

mechanism and discuss affected EGUs with limited remaining 

useful lives. Accordingly, we conclude that the source 

subcategory specific emission performance standards are 

achievable in accordance with the case law. 

5. Actions under the BSER that sources can take to achieve 

standards of performance 

 

543 We discuss the ability of affected EGUs to implement the 

building blocks in more detail in sections V.C., V.D., and V.E. 

and the accompanying support documents. 
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 Based on the determination of the BSER described above, the 

EPA has identified a performance rate of 12901305 lbs. per net 

MWh for affected steam EGUs and a performance rate of 780771

lbs. per net MWh for affected stationary combustion turbines. 

The computations of these performance rates and the 

determinations of state goals reflecting these rates are 

described in sections VI and VII of the preamble, respectively. 

 Under section 111(d), states determine the standards of 

performance for individual sources. The EPA is authorizing 

states to express the standards of performance applicable to 

affected EGUs as either emission rate-based limits or mass-based 

limits. As described above, the sets of actions that sources can 

take to comply with these standards are another expression of 

the BSER, viewed through an individual-source lens.implement or 

apply the BSER and, in that sense, may be understood as part of 

the BSER. 

 A source to which a state applies an emission rate-based 

limit can achieve the limit through a combination of the 

following set of measures (to the extent allowed by the state 

plan), all of which are components of the BSER, again, in the 

sense that they implement or apply it: 

 Reducing its heat rate (building block 1). 
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 Directly investing in, or purchasing emission rate credits 

created as a result of, incremental generation from 

existing NGCC units (building block 2). 

 Directly investing in, or purchasing emission rate credits 

created as a result of, generation from new or up-rated RE 

generators (building block 3). 

 Reducing its utilization, coupled with direct investment in 

or purchase of emission rate credits representing building 

blocks 2 and 3 as indicated above. 

 Investing in surplus emission rate reductions at other 

affected EGUs through the purchase or other acquisition of 

rate-based emission credits or the use of other multi-unit 

compliance approaches (e.g., averaging).. 



 A source to which a state applies a mass-based limit can 

achieve the limit through a combination of the following set of 

measures (to the extent allowed by the state plan), all of which 

are likewise components of the BSER: 

 Reducing its heat rate (building block 1). 

 Reducing its utilization and allowing its generation to be 

replaced or avoided through the routine operation of 
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industry reliability planning mechanisms and market 

incentives. 

 Investing in surplus emission reductions at other affected 

EGUs through the purchase or other acquisition of massbased emission allowances or the use of other multi-unit 

compliance approaches (e.g., aggregation or bubbling).. 

 The EPA has determined appropriate emissions standardsCO2

emission performance rates for each of the two source 

categorysubcategories as a whole achievable through application 

of the building blocks. The wide ranges of measures included in 

the BSER and available to individual sources as indicated above 

provide assurance that the source category as a whole can 

achieve standards of performance consistent with those emissions 

standards using components of the BSER, whether states choose to 

establish emission rate-based limits or mass-based limits. The 

wide ranges of measures included in the BSER also provide 

assurance that each individual affected sourceEGU could achieve 

the standard of performance its state establishes for it using 

components of the BSER. Of course, sources may also employ 

measures not included in the BSER, to the extent allowed under 

the applicable state plan. 

 In the remainder of this subsection, we discuss further how 

affected EGUs can use each of the measures listed above to 
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achieve emission rate-based forms of performance standards and 

mass-based forms of performance standards, indicating that all 

types of owner/operators of affected EGUs –- i.e., vertically 

integrated utilities and merchant generators; investor-owned, 

government-owned, and customer-owned (cooperative) utilities; 

and owner/operators of large, small, and single-unit fleets of 

generating units –- have the ability to deployimplement each of 

the building blocks in some way. In the following subsection we 

discuss the use of measures not in the BSER that can help 

sources achieve the standards of performance. 

a. Use of BSER measures to achieve an emission rate-based 

standard. Under an emission-rate based form of performance 

standards, compliance is nominally determined through a 

comparison of the affected EGU’s emission rate to the emission 

rate standard. Because anThe emissions-reducing impact of BSER 

measures that reduce CO2 emissions through reductions in the 

quantity of generation rather than through reductions in the 

amount of CO2 emitted per unit of generation would not be 

reflected in an affected EGU’s emission rate computed solely 

based on measured stack emissions and measured electricity 

generation will not reflect the emissions-reducing impact of 

BSER measures that reduce CO2 emissions through reductions in the 

quantity of generation rather than through reductions in the 
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amount of CO2 emitted per unit of generation, a plan that imposes 

emission rate-based standards of performance on affected EGUs 

will also need to authorize a rate computation mechanism whereby 

affected EGUs can adjust the rate computation to account for 

generation reduction measuresbut can readily be reflected in an 

emission rate computation by averaging ERCs acquired by the 

affected EGU into the rate computation. 

 One mechanism that the EPA has determined to be appropriate 

is to include emission rate credits (ERCs) In section 

VIII.K., we discuss the processes for issuance and use of ERCs 

that can be included in the emission rate computations that 

affected EGUs perform to demonstrate compliance with an emission 

rate standard. This ERC mechanism is analogous to the approach 

the EPA has used to reflect building blocks 2 and 3 in the 

uniform emission rates representing the BSER, as discussed in 

section VI below. We have determined that one viable way to 

specify ERCs – which we believe offers benefits of fungibility 

and ease of tracking – is to define the ERCs associated with 

building blocks 2 and 3 as units of zero-emissions generation. 

As summarized below and as discussed in greater detail in 

section VIII and in the Rate-based Program Accounting TSD for 

the CPP Final Rule,.K., the existence of a clearly feasible path 

for usage of ERCs ensures that emission reductions achievable 
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through implementation of the measures in building blocks 2 and 

3 are available to assist all affected EGUs in achieving 

compliance with standards of performance based on the BSER. 

 (1) Building block 1. 

 The owner/operator of an affected steam EGU can take steps 

to reduce the unit’s heat rate, thereby lowering the unit’s CO2

emission rate. Examples of actions in this category are included 

in section V.C. below and in the GHG Mitigation Measures TSD for 

the CPP Final Rule. Any type of owner/operator can take 

advantage of this measure. 

 (2) Building block 2. 

 The owner/operator of an affected EGU can average the EGU’s 

emission rate with incremental generation from an existing NGCC 

unit or with ERCs issued on the basis of incremental generation 

from an existing NGCC unit. TheAs permitted under the EGU’s 

state’s section 111(d) plan, the owner/operator of the affected 

EGU could accomplish this either through either common ownership 

of the NGCC unit, a bilateral transaction with the 

owner/operator of the NGCC unit, or a transaction for ERCs 

through an intermediary, which could but need not involve an 
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organized market. Based544 As discussed earlier, based on 

observation of market behavior both inside and outside the 

electricity industry, we expect that intermediaries will seek 

opportunities to participate in such transactions and that 

organized markets are likely to develop as well if section 

111(d) plans authorize the use of ERCs. While the opportunity to 

acquire ERCs through common ownership of NGCC facilities might 

not extend to owner/operators of single EGUs or small fleets, 

all owner/operators would have the ability to engage in 

bilateral or intermediated purchase transactions for ERCs just 

as they can engage in transactions for other kinds of goods and 

services. 

 In section VIII.K. below, the EPA sets out the minimum 

criteria that must be satisfied for generation and issuance of a 

valid ERC based upon incremental electricity generation by an 

existing NGCC unit. Those criteria generally concern ensuring 

that the physical basis for the ERC –- i.e., 

incrementalqualifying generation by an existing NGCC unit and 

 

544 Each of these methods of implementing building block 2 meets 

the criteria for the BSER in that (i) as we discuss in section 

V.D. and supporting documents, each of these methods is 

adequately demonstrated;(ii) the costs of each of these methods 

on a source-by-source basis are reasonable, as discussed above; 

and (iii) none of these methods causes adverse energy impacts or 

non-quality environmental impacts. 
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Page 604 of 2153

the NGCC unit CO2 emissions associated with that 

incrementalqualifying generation –- is adequately monitored and 

that there is an adequate administrative process for tracking 

credits to avoid double-counting. In the case of ERCs related to 

building block 2, the monitoring criteria would generally be 

satisfied by standard 40 CFR part 75 monitoring. 

 As noted above, the EPA has determined that one way to 

define an ERC –- which facilitates fungibility and tracking –- 

is to denominate each ERC in the form of a single zero-emissions 

MWh. NGCC units have non-zero CO2 emission rates, but their CO2

emission rates are lower than the CO2 emission rates of affected 

steam EGUs. Consistent with the fact that the BSER for affected 

steam EGUs reflects the opportunity to replace generation from 

affected steam EGUs with incremental generation from existing 

NGCC units at a lower, but non-zero, emission rate, incremental 

generation by an existing NGCC unit can qualify as the basis for 

issuance of ERCs, but one incremental MWh of NGCC generation 

would be insufficient to serve as the basis for an ERC worth one 

full MWh of zero-emissions generation. The specific number of 

incremental MWh that an NGCC unit would need to generate in 

order to qualify for issuance of an ERC representing one MWh of 

zero-emissions generation would depend on the magnitude of the 

difference between the NGCC unit’s actual emission rate and the 
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average standard of performance for affected steam EGUs in its 

state –- e.g., the uniform emission rate representing the BSER 

for steam EGUs. Details of the computation are provided in the 

Rate-based Accounting TSD for the CPP Final Rule available in 

the docket. 

 The owner/operator of an affected steam EGU would use the 

ERCs it has acquired for compliance –- whether acquired through 

ownership of NGCC capacity, a bilateral transaction, or an 

intermediated transaction –- by adding the ERCs to its measured 

net generation when computing its CO2 emission rate for purposes 

of demonstrating compliance with its emission rate-based 

standard of performance. 

 (3) Building block 3. 

 The owner/operator of an affected EGU can average the EGU’s 

emission rate with ERCs issued on the basis of generation from 

new (i.e., post-2012) RE generating capacity, including both 

newly constructed capacity and new uprates to existing RE 

generating capacity, or with ERCs issued on. As permitted under

the basis of such generation. The EGU’s state’s section 111(d) 

plan, the owner/operator of the affected EGU cancould accomplish 

this either through either common ownership of the RE generating 

capacity, a bilateral transaction with the owner/operator of the 

RE generating capacity, or a transaction for ERCs through an 
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intermediary, which could, but need not, involve an organized 

market. Based545 As discussed earlier, based on observation of 

market behavior both inside and outside the electricity 

industry, we expect that intermediaries will seek opportunities 

to participate in such transactions and that organized markets 

are likely to develop as well if section 111(d) plans authorize 

the use of ERCs. While the opportunity to acquire ERCs through 

common ownership of RE generating facilities might not extend to 

owner/operators of single EGUs or small fleets, all 

owner/operators would have the ability to engage in bilateral or 

intermediated purchase transactions for ERCs just as they can 

engage in transactions for other kinds of goods and services. 

 In section VIII.K. below, the EPA sets out the minimum 

criteria that must be satisfied for generation and issuance of a 

valid ERC based upon generation from new RE generating capacity. 

Those criteria generally concern assuring that the physical 

basis for the ERC –- i.e., generation by from qualifying new RE 

capacity –- is adequately monitored and that there is an 

 

545 As with building block 2, each of these methods of 

implementing building block 3 meets the criteria for the BSER in 

that (i) as we discuss in section V.E. and supporting documents, 

each of these methods is adequately demonstrated;(ii) the costs 

of each of these methods on a source-by-source basis are 

reasonable, as discussed above; and (iii) none of these methods 

causes adverse energy impacts or non-quality environmental 

impacts. 
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adequate administrative process for tracking credits to avoid 

double-counting and to facilitate enforceability of emission 

limits. 

 The types of RE generating capacity used by the EPA to 

quantify building block 3 are zero-emitting units. Under the 

definition of ERCs described above, each MWh of incremental 

generation by qualifying new RE generating capacity therefore 

can qualify as the basis for issuance of an ERC representing a 

full zero-emissions MWh.546 Further details are provided in the 

Rate-based Program Accounting TSD for the CPP Final Rule 

available in the docket.547 

 As with building block 2, the owner/operator of an affected 

EGU would use the ERCs it has acquired for compliance –- whether 

acquired through ownership of qualifying RE generating capacity, 

a bilateral transaction, or an intermediated transaction –- by 

adding the ERCs to its measured net generation when computing 

its CO2 emission rate for purposes of demonstrating compliance 

with its emission rate-based standard of performance. 

 

546

 The possible use of types of RE generating capacity that are 

not necessarily zero-emitting, such as biomass, is discussed in 

section V.A.6. and section VIII of the preamble. 

547 The possible use of types of RE generating capacity that are 

not included in the BSER is discussed in section V.A.6. and 

section VIII of the preamble. 
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 (4) Reduced generation. 

 The owner/operator of an affected EGU can reduce the unit’s 

generation and reflect that reduction in the form of a lower 

emission rate provided that the owner/operator also acquires 

some amount of ERCs to use in computing the unit’s emission rate 

for purposes of demonstrating compliance or otherwise invests. 

As permitted under the EGU’s state’s section 111(d) plan, the 

ERCs could be acquired through investment in incremental 

generation from existing NGCC capacity or, generation from new 

RE generating capacity., or purchase from an entity with surplus 

ERCs. If the owner/operator does not average any ERCs or 

qualifying cleaner generation into the unit’s emission rate, 

reducing the unit’s own generation will proportionately reduce 

both the numerator and denominator of the fraction and therefore 

will not affect the computed emission rate. (unless the unit 

retires, reducing its emission rate to zero). However, if the 

owner/operator does average ERCs or qualifying cleaner 

generation into the unit’s emission rate, then a proportional 

reduction in both the numerator and the portion of the 

denominator representing the unit’s measured generation will 

amplify the effect of the acquired ERCs in the computation, with 

the result that the more the unit reduces its generation, the 

fewer ERCs will be needed to reach a given emission rate-based 
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standard of performance. All owner/operators have the ability to 

reduce generation, and as discussed above all also would be 

capable of acquiring ERCs, so all would be capable of reflecting 

reduced utilization in their emission rates for purposes of 

demonstrating compliance. 

 (5) Emissions trading or other multi-unit compliance 

approaches. 

 To the extent allowed under standards of performance that 

incorporate emissions trading or otherwise through the relevant 

section 111(d) plans, the owner/operator of an affected EGU can 

investacquire tradable rate-based emission credits representing 

an investment in surplus emission rate reductions not needed by 

another affected EGU and can average those reductionscredits

into its own emission rate for purposes of demonstrating 

compliance with its rate-based standard of performance. A multiunit approach without tradable credits is possible, commonly 

referred to as averaging. Alternatively, tradable credits could 

be used, reflecting an emissions trading approach. In either 

case, theThe approach would have to be authorized in the 

appropriate section 111(d) plan and would have to conform to the 

minimum conditions for such approaches described in section VIII 

below. As we have repeatedly noted, we read the comment record 

and the discussions that occurred during the outreach process, 
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it is reasonable to support the predictionpresume that such 

authorization will be forthcoming from virtually all states that 

submit plans establishing rate-based standards of performance 

for their affected EGUs. 

 Under ana rate-based emissions trading approach, credits 

are initially created and issued according to processes defined 

in the state plan. After credits are initially issued, the 

owner/operator of thean affected EGU needing additional credits 

can acquire surplus credits through common ownership of another 

affected EGU or through a bilateral transaction with the other 

affected EGU, or the owner/operator of the affected EGU can 

acquire credits in a transaction through an intermediary, which 

could, but need not, involve an organized market. BasedAs 

discussed earlier, based on observation of market behavior both 

inside and outside the electricity industry, we expect that 

intermediaries will seek opportunities to participate in such 

transactions and that organized markets are likely to develop as 

well if section 111(d) plans and/or standards of performance 

established thereunder authorize emissions trading. While the 

opportunity to acquire credits through common ownership might 

not extend to owner/operators of single EGUs or small fleets, 

all owner/operators would have the ability to engage in 

bilateral or intermediated purchase transactions for credits 
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just as they can engage in transactions for other kinds of goods 

and services. 

 One possible form of tradable credit that could be traded 

among affected EGUs would be a credit denominated in the form of 

a single zero-emission MWh, which would be entirely fungible 

with the form of ERC described above by which affected EGUs 

could acquire the emissions-reducing benefits of activating 

encompassed in building blocks 2 and 3. The number of MWh that 

an affected EGU with an emission rate below its standard would 

need to generate to serve as the basis for issuance of each 

tradable credit – or, conversely, the number of tradable credits 

that a unit with an emission rate above its standard would need 

to acquire in order to achieve compliance – would be based on 

the difference between the unit’s actual emission rate and the 

unit’s standard of performance established in the applicable 

section 111(d) plan. Details regarding these computations are 

included in the Rate-based Program Accounting for the CPP Final 

Rule available in the docket. Further details regarding the 

possible use of rate-based emission credits in a state plan 

(using ERCs issued on the basis of investments in building 

blocks 2 and 3 and potentially other measures as the credits) 

are provided in section VIII.K. 
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b. Use of BSER measures to achieve a mass-based standard. Under 

a mass-based form of the standard, compliance is determined 

through a comparison of the affected EGU’s monitored mass 

emissions to a mass-based emission limit. Although a state could 

choose to impose specific mass-based limits that each EGU would 

be required to meet on a physical basis, in past instances where 

mass-based limits have been established for large numbers of 

sources it has been typical for the limit on each affected 

sourceEGU to be structured as a requirement to periodically 

surrender a quantity of emission allowances equal to the 

source’s monitored mass emissions. The EPA believes that section 

111(d) encompasses the flexibility for plans to impose massbased standards in the typical manner where the standard of 

performance for each affected EGU consists of a requirement to 

surrender emission allowances rather than a requirement to 

physically comply with a unit-specific emissions cap. 

 Measurements of mass emissions at a given affected EGU 

capture reductions in the EGU’s emissions arising from both 

reductions in generation and reductions in the emission rate per 

MWh. Accordingly, under a mass-based standard there is no need 

to provide a mechanism such as the ERC mechanism described above 

in order to properly account for emission reductions 

attributable to particular types of BSER measures. The relative 
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simplicity of the mechanics of monitoring and determining 

compliance are significant advantages inherent in the use of 

mass-based standards rather than emission rate-based standards. 

 (1) Building block 1. 

 The owner/operator of an affected steam EGU can take steps 

to reduce the unit’s heat rate, thereby lowering the unit’s CO2

mass emissions. Examples of actions in this category are 

included in section V.C. below and in the GHG Mitigation 

Measures TSD for the CPP Final Rule. Any type of owner/operator 

can take advantage of this measure. 

 (2) Reduced generation. 

 The owner/operator of an affected EGU can reduce its 

generation, thereby lowering the unit’s CO2 mass emissions. Any 

type of owner/operator can take advantage of this measure. 

Although some action or combination of actions to increase 

lower-carbon generation or reduce electricity demand somewhere 

in the interconnected electricity system of which the affected 

EGU is a part will be required to enable electricity supply and 

demand to remain in balance, the affected EGU does not need to 

monitor or track those actions in order to use its reduction in 

generation to help achieve compliance with the mass-based 

standard. Instead, multiple participants in the interconnected 

electricity system will act to ensure that supply and demand 
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remain in balance, subject to the complex and constantly 

changing set of constraints on operation of the system, just as 

those participants have routinely done for years. 

 Of course, if the owner/operator of the affected EGU wishes 

to play a direct role in driving the increase in lower-carbon 

generation or demand-side energy efficiency required to offset a 

reduction in the affected EGU’s generation, the owner/operator 

may do so as part of whatever role it happens to play as a 

participant in the interconnected electricity system. However, 

the owner/operator will achieve the benefit that reduction in 

generation brings toward compliance with the mass-based standard 

whether it takes those additional actions itself or instead 

allows other participants in the interconnected electricity 

system to play that role. 

 (3) Emissions trading or other multi-unit compliance 

approaches. 

 To the extent allowed under the relevant section 111(d) 

plans -- as the record indicates that it is reasonable to expect 

it will be -- the owner/operator of an affected EGU can 

investacquire tradable mass-based emission allowances 

representing investment in surplus emission reductions not 

needed by another affected EGU and can aggregate those 

reductionsallowances with its own emissionsany other allowances 
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it already holds for purposes of demonstrating compliance with 

its mass-based standard of performance. This could be done 

through either approaches using tradable mass-based emission 

allowances or other multi-unit compliance approaches, which in 

this case would consist of aggregation or bubbling of emission 

limits. In either case, theThe approach would have to be 

authorized in the appropriate section 111(d) plan and would have 

to conform to the minimum conditions for such approaches 

described in section VIII below. 

 Under ana mass-based emissions trading approach, the total 

number of allowances to be issued is defined in the state plan, 

and affected EGUs may obtain an initial quantity of allowances 

through an allocation or auction process. After that initial 

process, the owner/operator of thean affected EGU needing 

additional allowances can acquire allowances through common 

ownership of another affected EGU or through a bilateral 

transaction with the other affected EGU, or the owner/operator 

of the affected EGU can acquire allowances in a transaction 

through an intermediary, which could but need not involve an 

organized market. BasedAs discussed earlier, based on 

observation of market behavior both inside and outside the 

electricity industry, we expect that intermediaries will seek 

opportunities to participate in such transactions and that 
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organized markets are likely to develop as well if section 

111(d) plans authorize the use of emissions trading. While the 

opportunity to acquire allowances through common ownership might 

not extend to owner/operators of single EGUs or small fleets, 

all owner/operators would have the ability to engage in 

bilateral or intermediated purchase transactions for allowances 

just as they can engage in transactions for other kinds of goods 

and services.

 Further details regarding the possible use of mass-based 

emission allowances in a state plan are provided in section 

VIII.J. 

6. Use of non-BSER measures to achieve standards of performance 

 In addition to the BSER-related measures that affected EGUs 

can use to achieve the standards of performance set in section 

111(d) plans, there are a variety of non-BSER measures that 

could also be employed (to the extent permitted under a given 

plan). This final rule does not limit the measures that affected 

EGUs may use for achieving standards of performance to measures 

that are included in the BSER; thus, the existence of these nonBSER measures provides flexibility allowing the individual 

affected EGUs and the source category to achieve emission 

reductions consistent with application of the BSER at the levels 

of stringency reflected in this final rule even if one or more 
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of the building blocks is not implemented to the degree that the 

EPA has determined to be reasonable for purposes of quantifying 

the BSER. In this way, non-BSER measures therefore provide 

additional flexibility to states in establishing standards of 

performance for affected EGUs through section 111(d) plans and 

to individual affected EGUs for achieving those standards. 

 Any of the non-BSER measures described below would help the 

affected source category as a whole achieve emission limits 

consistent with the BSER. The non-BSER measures either reduce 

the amount of CO2 emitted per MWh of generation from the set of 

affected EGUs or reduce the amount of generation, and therefore 

associated CO2 emissions, from the set of affected EGUs. However, 

the manner in which the various non-BSER measures would help 

individual affected EGUs meet their individual standards of 

performance varies according to the type of measure and the type 

of standard of performance –- i.e., whether the standard is 

emission rate-based or mass -based. 

 In general, a non-BSER measure that reduces the amount of 

CO2 emitted per MWh of generation at an affected EGU will reduce 

the amount of CO2 emissions monitored at the EGU’s stack 

(assuming the quantity of generation is held constant). Measures 

of this type can help the EGU meet either an emission rate-based 

or mass-based standard of performance. 
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 Other non-BSER measures do not reduce an affected EGU’s CO2

emission rate but rather facilitate reductions in CO2 emissions 

by reducing the amount of generation from affected EGUs. Under a 

mass-based standard, the collective reduction in emissions from 

the set of affected EGUs is reflected in the collective 

monitored emissions from the set of affected EGUs. An individual 

EGU that reduces its generation and emissions will be able to 

use the measure to help achieve its mass-based limit. Individual 

EGUs that do not reduce their generation and emissions will be 

able to use the measure, if the relevant section 111(d) plans 

provide for allowance trading, by purchasing emission allowances 

no longer needed by EGUs that have reduced their emissions. 

 Under an emission rate-based standard, non-BSER measures 

that reduce generation from affected EGUs but do not reduce an 

affected EGU’s emission rate generally can facilitate compliance 

by serving as the basis for ERCs that affected EGUs can average 

into their emission rates for purposes of demonstrating 

compliance. For some non-BSER measures, each MWh of incremental 

generation produced by the measure or each MWh of fossil fuelfired generation avoided by the measure could qualify as the 

basis for issuance of an ERC representing a full zero-emissions 

MWh, similar to building block 3. For other non-BSER measures, 

more than one MWh of incremental generation would be required to 
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qualify for the basis of an ERC representing a full zeroemissions MWh, similar to building block 2.Section VIII.K. 

includes a discussion of the issuance of ERCs based on various 

non-BSER measures. Affected EGUs could use such ERCs to the 

extent permitted by the relevant section 111(d) plans. 

 The remainder of this section discusses some specific types 

of non-BSER measures. The first set discussed includes measures 

that can reduce the amount of CO2 emitted per MWh of generation, 

and the second set discussed includes measures that can reduce 

CO2 emissions by reducing the amount of generation from affected 

EGUs. In some cases, considerations related to use of these 

measures for compliance isare discussed below in section VIII on 

state plans. The EPA notes that this is not an exhaustive list 

of non-BSER measures that could be employed to reduce CO2

emissions from affected EGUs, but merely a set of examples that 

illustrate the extent of the additional flexibility such 

measures provide to states and affected EGUs under the final 

rule. 

a. Non-BSER measures that reduce CO2 emissions per MWh generated. 

In the June 2014 proposal, the EPA discussed several potential 

measures that could reduce CO2 emissions per MWh generated at 

affected EGUs but that were not proposed to be part of the BSER. 

The measures discussed included heat rate improvements at 
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affected EGUs other than coal-fired steam EGUs; fuel switching

from coal to natural gas at affected EGUs, either completely 

(conversion) or partially (co-firing); and carbon capture and 

storage by affected EGUs. One reason for not proposing to 

consider these measures to be part of the BSER was that they 

were more costly than otherthe BSER measures. Another reason was 

that the emission reduction potential was limited compared to 

the potential available from the measures that were proposed to 

be included in the BSER. However, we also noted that 

circumstances could exist where these measures could be 

sufficiently attractive to deploy, and that the measures could 

be used to help affected EGUs achieve emission limits consistent 

with the BSER. 

 In the final rule, the EPA has reached determinations 

consistent with the proposal with respect to these measures: 

namely, that they do not merit inclusion in the BSER, but that 

they are capable of helping affected EGUs achieve compliance 

with standards of performance and are likely to be used for that 

purpose by some units. To the extent that they are selectively 

employed, they provide flexibility for the source category as a 

whole and for individual affected EGUs to achieve emission 

limits representativereflective of the BSER, as discussed above. 
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Further discussion of these measures is also provided in the GHG 

Mitigation Measures TSD for the CPP Final Rule.

 (1) Heat rate improvement at affected EGUs other than coalfired steam EGUs. 

 Building block 1 reflects the opportunity to improve heat 

rate at coal-fired steam EGUs but not at other affected EGUs. As 

the EPA stated at proposal, the potential CO2 reductions 

available from heat rate improvements at coal-fired steam EGUs 

are much larger than the potential CO2 reductions available from 

heat rate improvements at other types of EGUs, and comments 

offered no persuasive basis for reaching a different conclusion. 

Nevertheless, we recognize that there may be instances where an 

owner/operator finds heat rate improvement to be an attractive 

option at a particular non-coal-fired affected EGU, and nothing 

in the rule prevents the owner/operator from implementing such a 

measure and using it to help achieve a standard of performance. 

 (2) Carbon capture and storage at affected EGUs. 

 Another approach for reducing CO2 emissions per MWh of 

generation from affected EGUs is the application of carbon 

capture and storage (CCS) technology. Consistent with the June 

2014 proposal, we are determining that use of full or partial 

CCS technology should not be part of the BSER for existing EGUs 

because it would be more expensive than the measures determined 
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to be part of the BSER, particularly if applied broadly to the 

overall source category. At the same time, we note that retrofit 

of CCS technology may be a viable option at some individual 

facilities, particularly where the captured CO2 can be used for 

enhanced oil recovery (EOR). For example, construction of one 

CCS retrofit application with EOR has already been completed at 

a unit at the Boundary Dam plant in Canada, and construction of 

another CCS retrofit application with EOR is underway at the 

W.A. Parish plant in Texas. We expect the costs of CCS to 

decline as implementation experience increases. CO2 emission rate 

reductions achieved through retrofit of CCS technology would be 

available to help affected EGUs achieve emission limits 

consistent with the BSER. State plan considerations related to 

CCS are discussed in section VIII.I.2.a.

 (3) Fuel switching to natural gas at affected EGUs. 

 In the proposal we discussed the opportunity to reduce CO2

emissions at an individual affected EGU by switching fuels at 

the EGU, particularly by switching from coal to natural gas. 

Most coal-fired EGUs could be modified to burn natural gas 

instead, and the potential CO2 emission reductions from this 

measure are large – approximately 40 percent in the case of 

conversion from 100 percent coal to 100 percent natural gas, and 

proportionately smaller for partial co-firing of coal with 
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natural gas. The primary reason for not considering this measure 

part of the BSER, both at proposal and in this final rule, is 

that it is more expensive than otherthe BSER measures. In 

particular, combusting natural gas in a steam EGU is less 

efficient and generally more costly than combusting natural gas 

in an NGCC unit. For the category as a whole, CO2 emissions can 

be achieved far more cheaply by combusting additional natural 

gas in currently underutilized NGCC capacity and reducing 

generation from coal-fired steam EGUs (building block 2) than by 

combusting natural gas instead of coal in steam EGUs. 

 Some owner/operators are already converting some affected 

EGUs from coal to natural gas, and it is apparent that the 

measure can be attractive compared to alternatives in certain 

circumstances, such as when a unit must meet tighter unitspecific limits on emissions of non-GHG pollutants, the options 

for meeting those emission limits are costly, and retirement of 

the unit would necessitate transmission upgrades that are costly 

or cannot be completed quickly. CO2 emission reductions achieved 

in these situations are available to help achieve emission 

limits consistent with the BSER. 

 (4) Fuel switching to biomass at affected EGUs. Some 

affected EGUs may seek to reduce their CO2 emission rates by cofiring qualifying biomass with fossil fuels. As discussed in 
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section VIII below, the EPA recognizes that some biomass-derived 

fuels can play an important role in CO2 emissions reduction 

strategies. The EPA expects to recognize the biogenic CO2

emissions and climate policy benefits of waste-derived and 

certain forest- and agriculture-derived industrial byproduct 

feedstocks when considering state plans, based on the 

conclusions supported by a variety of technical studies. In 

addition, the EPA expects that states’ reliance on sustainably 

derived agriculture- and forest-derived feedstocks may also be 

an approvable element of their state plans.548 As with the other 

non-BSER measures discussed in this section, the EPA expects 

that use of biomass may be economically attractive for certain 

individual sources even though on a broader scale it would 

likely be more expensive or less achievable than the measures 

determined to be part of the BSER. A state can propose 

qualifying biomass feedstocks and the proposed treatment of 

biogenic CO2 emissions in its plan. State plans must include 

analysis supporting how proposed qualifying feedstocks or 

feedstock categories are considered appropriate as a CO2 emission 

mitigation approach as well as the proposed treatment of 

biogenic CO2 emissions (i.e., the proposed level of biogenic CO2

 

548 For a discussion of considerations concerning biomass in 

state plans, see section VIII.G.1.a.(2)(c)(i) of the preamble. 
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emissions from use of the biomass feedstock that would not be 

counted when demonstrating compliance with emission limits 

consistent with the BSER). The EPA would review the 

appropriateness and basis for such determinations in the course 

of its review of a state plan. 

 Some affected EGUs may seek to co-fire qualified biomass 

with fossil fuels. The EPA recognizes that the use of some 

biomass-derived fuels can play an important role in controlling 

increases of CO2 levels in the atmosphere. As with the other nonBSER measures discussed in this section, the EPA expects that 

use of biomass may be economically attractive for certain 

individual sources even though on a broader scale it would 

likely be more expensive or less achievable than the measures 

determined to be part of the BSER. Section VIII.I.2.c. describes 

the process and considerations for states proposing to use 

different kinds of biomass in state plans. 

 (5) Waste heat-to-energy conversion at affected EGUs. 

 Certain affected EGUs in urban areas or located near 

industrial or commercial facilities with needs for thermal 

energy may be able add new equipment to capture some of the 

waste heat from their electricity generation processes and use 

it to create useful thermal output, thereby engaging in a form 

of combined heat and power (CHP) production sometimes referred 
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to as topping-cycle cogeneration.. While the set of affected 

EGUs in locations making this measure feasible may be limited, 

where the measure is feasible the potential CO2 emission rate 

improvements can be substantial, because conversion of a 

conventional EGU to CHP configuration can increase: depending on 

the process used, the efficiency with which fuel is converted to 

useful energy can be increased by 25 percent or more. The final 

rule allows an owner/operator applying CHP technology to an 

affected EGU to account for the increased efficiency by counting 

the useful thermal output as additional MWh of generation, 

thereby lowering the unit’s computed emission rate and assisting 

with achievement of an emission rate-based standard of 

performance. (The EPA notes that unless the unit also reduced 

its fuel usage, the addition of the capability to capture waste 

heat and produce useful thermal output would not reduce the 

unit’s mass emissions and therefore would not directly help the 

unit achieve a mass-based standard of performance.).549)

b. Non-BSER measures that reduce CO2 emissions by reducing fossil 

fuel-fired generation. A second group of non-BSER measures has 

the potential to reduce CO2 emissions from affected EGUs by 

 

549 However, the EPA notes that a state could establish a 

mechanism for encouraging affected EGUs to apply CHP technology 

under a mass-based plan, for example, through awards of emission 

allowances to CHP projects. 
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reducing the amount of generation from those EGUs. As discussed 

above, under a section 111(d) plan with mass-based standards of 

performance, no special action is required to enable measures of 

this nature to help the source category as a whole and 

individual affected EGUs achieve their emission limits, because 

the CO2-reducing effects are captured in monitored stack 

emissions. However, under a section 111(d) plan with rate-based 

standards of performance, some form of crediting such as the ERC 

mechanism described earlier is necessary in order to enable 

measures of this nature to help the source category as a whole 

and individual affected EGUs achieve thewould need to acquire 

ERCs based on the non-BSER activities that could be averaged 

into their emission limits. rate computations for purposes of 

determining compliance with their standards of performance.

 (1) Demand-side energy efficiency. 

 One of the major approaches available for achieving CO2

emission reductions from the utility power sector is demand-side 

energy efficiency. In the June 2014 proposal, the EPA identified 

demand-side energy efficiency as one of the four proposed 

building blocks for the BSER. We continue to believe that 

significant emission reductions can be achieved by the source 

category through use of such measures at reasonable costs. In 

fact, we believe that the potential emission reductions from 
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demand-side energy efficiency rival those from building blocks 2 

and 3 in magnitude, and that demand-side energy efficiency 

willis likely to represent an important component of some state 

plans, particularly in instances where a state prefers to 

develop a plan reflecting the state measures approach discussed 

in section VIII below. We also expect that many sources would be 

interested in including demand-side energy efficiency in their 

compliance strategies to the extent permitted, and we received 

comment that it should be permitted. 

 For the reasons discussed in section V.AB.3.e. abovec.(8) 

below, the EPA has determined not to include demand-side energy 

in the BSER in this final rule. However, the final rule 

authorizes generation avoided through investments in demand-side 

energy efficiency to serve as the basis for issuance of ERCs in 

defined circumstances.when appropriate conditions are met. In 

section VIII.K. below, the EPA sets out the minimum criteria 

that must be satisfied for generation and issuance of a valid 

ERC based upon implementation of new demand-side EE programs. 

Those criteria generally concern assuringensuring that the 

physical basis for the ERC -– in this case, generation avoided 

through implementation of demand-side EE measures –- is 

adequately monitoredevaluated, measured, and verified and that 

there is an adequate administrative process for tracking credits
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to avoid double-counting and to facilitate enforceability of 

emission limits. The particular considerations related to 

evaluation, measurement, and verification of demand-side EE 

programs are also discussed in section VIII.. 

Through their authority over legal requirements such as 

building codes, states have the ability to drive certain types 

of demand-side energy efficiency measures that are beyond the 

reach of private-sector entities. The EPA recognizes that, by 

definition, this type of measure is beyond the ability of 

affected EGUs to invest in either directly or through bilateral 

arrangements. However, the final rule also authorizes generation 

avoided through such state policies to serve as the basis for 

issuance of ERCs that in turn can be used by affected EGUs. The 

section 111(d) plan would need to include appropriate provisions 

for evaluating, measuring, and verifying the avoided MWh 

associated with the state policies, consistent with the criteria 

discussed in section VIII.K. below. 

 (2) New or up-rated nuclear generating capacity. 

 In the June 2014 proposal, the EPA included generation from 

the five nuclear units currently under construction as part of 

the proposed BSER. As discussed above in section V.A.3.c., upon 

consideration of comments, we have determined that generation 

from these units should not be part of the BSER. However, we 
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continue to observe that the zero-emitting generation from these 

units would be expected to replace generation from affected EGUs 

and thereby reduce CO2 emissions, and the continued commitment of 

the owner/operators to completion of the units is essential in 

order to realize that result. Accordingly, a section 111(d) plan 

may rely on ERCs issued on the basis of generation from these 

units and other new nuclear units. For the same reason, a plan 

may rely on ERCs issued on the basis of generation from up-rates 

to the capacity of existing nuclear units. TheRequirements for 

state plan provisions intended to accommodate ERCs for 

generation from new and uprated nuclear capacity would be 

similar to the plan provisions necessary to accommodate ERCs 

issued on the basis of generation from new RE generating 

capacity (i.e., building block 3), which is also zero-emitting. 

These provisionsserve this purpose are discussed in section VIII

below..K. 

 (3) Zero-emitting RE generating technologies not reflected 

in the BSER. 

 The range of available zero-emitting renewable energy 

generating technologies is broader than the range of RE 

technologies determined to be suitable for use in quantification 

of building block 3 as an element of the BSER. Examples of 

additional zero-emitting RE technologies not included in the 
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BSER that could be used to achieve emission limits consistent 

with the BSER include offshore wind, distributed solar, and fuel 

cells. These technologies were not included in the range of RE 

technologies quantified for the BSER because they are generally 

more expensive than the measures that were included and the 

other measures in the BSER. However, these technologies are 

equally capable of replacing generation from affected EGUs and 

thereby reducing CO2 emissions. Further, as with any technology, 

there are likely to be certain circumstances where the costs of 

these technologies are more attractive relative to alternatives, 

making the technologies likely to be deployed to some extent. 

Indeed, distributed solar is already being widely deployed in 

much of the United States and offshore wind, while still unusual 

in this country, has been extensively deployed in some other 

parts of the world. We expect innovation in RE generating 

technologies to continue, making such technologies even more 

attractive over time. A section 111(d) plan may rely on ERCs 

issued on the basis of generation from new and uprated 

installations of these technologies. The plan provisions to 

accommodate ERCs issued on the basis of generation from these RE 

generating technologies again would be similar to the plan 

provisions necessary to accommodate ERCs issued on the basis of 

generation from other RE generating technologies (building block 
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3).The necessary state plan provisions are discussed in section 

VIII.K. 

 (4) Non-zero-emitting RE generating technologies. 

 Generation from new or expanded facilities that combust 

qualifyingqualified biomass or biogenic portions of municipal 

solid waste (MSW) to produce electricity can also replace 

generation from affected EGUs and thereby reducecontrol CO2

emissions.550levels in the atmosphere.551 While the EPA believes 

it is reasonable to consider generation from these fuels and 

technologies to be forms of RE generation, the fact that the 

technologiesthey can produce stack emissions containing CO2 means 

that a section 111(d) plan seeking to permit use of such 

generation to serve as the basis for issuance of ERCs must 

include appropriate consideration of feedstock characteristics 

and climate policy benefits. Again, as discussed in section VIII 

below, the EPA expects to recognize the biogenic CO2 emissions 

 

550 The EPA and many states have recognized the importance of 

integrated waste materials management strategies that emphasize 

a hierarchy of waste prevention and all other productive uses of 

waste materials to reduce the volume of disposed waste materials 

(see section VIII for more discussion of waste to energy 

strategies). 

551 The EPA and many states have recognized the importance of 

integrated waste materials management strategies that emphasize 

a hierarchy of waste prevention and all other productive uses of 

waste materials to reduce the volume of disposed waste materials 

(see section VIII for more discussion of waste to energy 

strategies). 
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and climate policy benefits of waste-derived feedstocks and 

certain forest- and agriculture-derived industrial byproduct 

feedstocks when considering state plans. The EPA also expects 

that states’ reliance specifically on sustainably-derived 

agriculture- and forest-derived feedstocks may also be an 

approvable element of their state plans. The EPA and many states 

have recognized the importance of integrated waste materials 

management strategies that emphasize a hierarchy of waste 

prevention and all other productive uses of waste materials to 

reduce the volume of disposed waste materials. Because it is 

likely that more than one MWh of incremental generation from 

these technologies would be required as the basis qualifying for 

the issuance of an ERC worth a full MWh of zero-emitting 

generation, the minimum requirements to accommodate ERCs issued 

on the basis of generation from these technologies would be 

similar to the plan provisions necessary to accommodate ERCs 

issued on the basis of incremental generation from existing NGCC 

units (building block 2), supplemented by appropriate provisions 

to address special characteristics of the feedstocksbenefits. 

Specifically, the use of some kinds of biomass has the potential 

to offer a wide range of environmental benefits, including 

carbon benefits. However these benefits can only be realized if 

biomass feedstocks are sourced responsibly and attributes of the 
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carbon cycle related to the biomass feedstock are taken into 

account. Section VIII.I.2.c. describes the process and 

considerations for states proposing to use biomass in state 

plans. Section VIII.K. describes additional provisions related 

to ERCs. 

 (5) Waste heat-to-electricity conversion at non-affected 

facilities. 

 Industrial facilities that install new equipment to capture 

waste heat from an existing combustion process and then use the 

waste heat to generate electricity –- a form of combined heat 

and power (CHP) production sometimes referred to as bottomingcycle cogeneration –- can produce generation that replaces 

generation from affected EGUs and thereby reduces CO2 emissions. 

A section 111(d) plan may rely on ERCs issued on the basis of 

generation of this nature provided that the facility does not 

generate and sell sufficient electricity to qualify as a new EGU 

for purposes of section 111(b) and is not covered under section 

111(d) for another source category. This form of CHP can be 

considered zero-emitting to the extent that the waste heat would 

have been produced by the industrial process anyway. To the 

extent that the More information is provided in section 111(d) 

plan includes appropriate provisions for establishing that the 

heat input truly is waste heat, each MWh of incremental 
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generation from this form of CHP could serve as the basis for 

issuance of an ERC worth a full MWh of zero-emitting generation 

similar to an ERC issued on the basis of building block 3. In 

order to permit ERCs issued on the basis of generation from 

facilities where the waste heat input is supplemented by fossil 

fuel input, the plan would need to include appropriate 

provisions for establishing the number of incremental MWh that 

would be generated in order to serve as the basis for issuance 

of each ERC worth one full MWh of zero-emitting generation, 

similar to the plan provisions required to support an ERC issued 

on the basis of building block 2VIII.K. 

 (6) Reduction in transmission and distribution line losses. 

 Reductions of electricity line losses incurred from the 

transmission and distribution system between the points of 

generation and the points of consumption by end-users allow the 

same overall demand for electricity services to be met with a 

smaller overall quantity of electricity generation. Such 

reductions in generation quantities would tend to reduce 

generation by affected EGUs, thereby reducing CO2 emissions. The 

opportunity for improvement is large because, on average, line 

losses account for approximately seven percent of all 

electricity generation. The EPA recognizes that, in general, 

only the owner/operators of the transmission and distribution 
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facilities have the ability to undertake line loss reduction 

investments, and that merchant generators may have little 

opportunity to engage a contractor to pursue such opportunities 

on a bilateral basis. Nevertheless, for entities that do have 

the opportunity to make such investments, generation avoided 

through investment that reduces transmission and distribution 

line losses may serve as the basis for issuance of ERCs that in 

turn can be used by affected EGUs. This avoided generation is 

analogous to the generation avoided through demand-side energy 

efficiency described above, and each MWh of avoided generation 

could serve as the basis for creation of an ERC worth one full 

zero-emitting MWh of generation. The section 111(d) would need 

to include appropriate provisions for quantifying and verifying 

the avoided MWh associated with the transmission and 

distribution investmentsFurther information is provided in 

section VIII.K. 

7. Severability. 

 The EPA intends that the components of the BSER summarized 

above be severable. It is reasonable to consider the building 

blocks severable because the building blocks do not depend on 

one another. Each building block is aBuilding blocks 2 and 3 are

feasible and demonstrated means of reducing CO2 emissions from 

the utility power sector that can be implemented independently 
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of the other building blocks. If implemented in combination with 

at least one of the other building blocks, building block 1 is 

also a feasible and demonstrated means of reducing CO2 emission 

from the utility power sector.552 As discussed in sections V.C. 

through V.E. below, we have determined that each building block 

is independently of reasonable cost whether or not the other 

building blocks are applied, and that alternative combinations 

of the building blocks are likewise of reasonable cost, and we 

have determined reasonable schedules and stringencies for 

implementation of each building block independently, based on 

factors that generally do not vary depending on the 

implementation of other building blocks. 

 Further, building block 2, building block 3, and all 

combinations of the building blocks (implemented on the 

schedules and at the stringencies determined to be reasonable in 

this rule) would achieve meaningful degrees of emission 

 

552 The heat rate improvement measures included in building block 

1 are capable of being implemented independently of the measures 

in the other building blocks but, as discussed earlier, unless 

at least one other building block is also implemented, a 

“rebound effect” arising from improved competitiveness and 

increased generation at the EGUs implementing heat rate 

improvements could weaken or potentially even eliminate the 

ability of building block 1 to achieve CO2 emission reductions. 
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reductions,553 although less than the combination of all three 

building blocks. No combination of the building blocks would 

lead to adverse non-air environmental or energy impacts or 

impose a risk to the reliability of electricity supplies. 

 In the event that a court should strike down any 

individualdeem building block used to compute the emissions 

standards and state goals set forth in this rule2 or 3 

defective, but not both, the standards and state goals can be 

recomputed on the basis of the remaining building blocks. All of 

the data and procedures necessary to determine recomputed state 

goals using any combination of the building blocks are set forth 

in the Final RuleCO2 Emission Performance Rate and Goal 

Computation TSD for the CPP Final Rule available in the docket. 

B. Legal Discussion of Certain Aspects of the BSER 

This section includes a legal analysis of various aspects 

of EPA’s determination of the BSER, including responses to some 

of the major adverse comments. These aspects include (1) the 

EPA’s authority to determine the BSER; (2) the approach to 

subcategorization; (3) the EPA’s basis for determining that 

building blocks 2 and, 3, and 4 qualify as part of the BSER 

 

553 This conclusion would not extend to a BSER comprising solely 

building block 1 because of the possibility of rebound effects 

discussed earlier. 
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under CAA sections 111(d)(1) and (a)(1), notwithstanding 

commenters’ arguments that these building blocks cannot be 

considered part of the BSER because they are not based on 

measures integrated into controlling the design or operation of 

the affected source itself ’ssource’s own production processes 

or methods or because they are dependent on actions by entities 

other than the affected source; (2) the EPA’s basis for 

including trading or averaging as a component of BSER; (3) the 

EPA’s basis for including reduced generation as a component of 

the BSER; (4) the EPA’s authority to determine the BSER; (5) the 

consistency between the EPA’s identification of the BSER for 

this rule for CO2 emissions from existing affected EGUs and the 

BSER for the rules the EPA is promulgating at the same time for 

CO2 emissions from new or modified affected EGUs; (64) the 

relationship between an affected EGU’s implementation of 

building blocks 2 and 3 and CO2 emissions reductions; and (7) the 

approach to subcategorization; and (8(5) how reduced generation 

relates to the BSER; (6) reasons why, contrary to assertions by 

commenters, this rule is within the EPA’s statutory authority

and does not represent, is not inconsistent with the Federal 

Power Act or state laws governing public utility commissions, 

and does not result in what the U.S. Supreme Court described as 

“an enormous and transformative expansion in [the] EPA’s 
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regulatory authority”.554”;555 and (7) reasons that, contrary to 

assertions by commenters, the stringency of the BSER for this 

rule for CO2 emissions from existing affected EGUs is not 

inconsistent with the stringency of the BSER for the rules the 

EPA is promulgating at the same time for CO2 emissions from new 

or modified affected EGUs.

1. The EPA’s authority to determine the BSER. 

In this section, we explain why the EPA, and not the 

states, has the authority to determine the BSER and, therefore, 

the level of emission limitation required from the existing 

sources in the source category in section 111(d) rulemaking and 

the associated state plans. 

CAA section 111(d)(1) requires the EPA to establish a 

section 110-like procedure under which each state submits a plan 

that “establishes standards of performance for any existing 

source of air pollutant” and “provides for the implementation 

and enforcement of such standards of performance.” As CAA 

section 111(d) was originally adopted in the 1970 CAA 

Amendments, however, state plans were required to establish 

“emission standards” –- an undefined term -- rather than 

 

554 Util. Air Regulatory Group v. EPA, 134 S. Ct. 2427, 2444 

(2014). 

555 Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2444 (2014). 
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“standards of performance,” a term that was limited to CAA 

section 111(b).556 The 1970 provision was in effect when the EPA 

issued the 1975 implementing regulations for CAA section 

111(d),557 which remain in effect to this day. 

These regulations establish a cooperative framework that is 

similar to that under CAA section 110. First, the EPA develops 

“emission guidelines” for source categories, which are defined 

as a final guideline document reflecting “the degree of emission 

reduction achievable through the application of the best system 

of emission reduction ... which the Administrator has determined 

has been adequately demonstrated.” Then, the states submit 

implementation plans to regulate any existing sources.558 

The preamble to these regulations carefully considered the 

allocation of responsibilities as between the EPA and the states 

for purposes of CAA section 111(d), and concluded that the EPA 

is responsible for determining the level of emission limitation 

from the source category, while the states have the 

 

556 See 1970 CAA Amendments, § 4, 84 Stat. at 1683-84. 

Subsequently, in 1977, Congress replaced the term “emission 

standard” with “standards of performance.” See 1977 CAA 

Amendments, § 109, 91 Stat. at 699. 

557 See “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340 (Nov. 17, 1975). 

558 See “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340 (Nov. 17, 1975). 
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responsibility of assigning emission requirements to their 

sources that assured their achievement of that level of emission 

limitation.559 The EPA explained “that some substantive criterion 

was intended to govern not only the Administrator’s promulgation 

of standards but also [her] review of state plans.”560 The EPA 

added, “it would make no sense to interpret [CAA] section 111(d) 

as requiring the Administrator to base approval or disapproval 

of state plans solely on procedural criteria. Under that 

interpretation, states could set extremely lenient standards -- 

even standards permitting greatly increased emissions -- so long 

as [the] EPA’s procedural requirements were met.”561 The EPA 

concluded that “emission guidelines, each of which will be 

subjected to public comment before final adoption, will serve 

[the] function” of providing substantive criteria “in advance to 

the states, to industry, and to the general public” to aid 

states in “developing and enforcing control plans under [CAA] 

 

559 As we made clear in the proposed rulemaking, we are not reopening these regulations (on the issue of the authority to 

determine the BSER or any other issue, unless specifically 

indicated otherwise) in this rulemaking, and our discussion of 

these regulations in responding to comments does not constitute 

a re-opening. 

560 ”“State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 F.R.FR 53340, 53342 (Nov. 17, 1975). 

561 ”“State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 F.R.FR 53340, 53343 (Nov. 17, 1975). 
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section 111(d).”562 Thus, the implementing regulations make clear 

that the EPA is responsible for determining the level of 

emission limitation that the state plans must achieve. 

In 1977, Congress revised CAA section 111(d) to require 

that the states adopt “standards of performance,” as defined 

under CAA section 111(a)(1). As noted above, a standard of 

performance is defined as “a standard for emissions of air 

pollutants which reflects the degree of emission limitation 

achievable through the application of the best system of 

emission reduction which ... the Administrator determines has 

been adequately demonstrated.” (Emphasis added.) By its terms, 

this provision provides that the EPA has the responsibility of 

determining whether the “best system of emission reduction” is 

“adequately demonstrated.” By giving the EPA this 

responsibility, this provision is clear that Congress assigned 

the role of determining the “best system of emission reduction” 

to the EPA. Even if the provision may be considered to be silent 

or ambiguous on that question, the EPA reasonably interprets the 

provision to assign the responsibility of identifying the “best 

system of emission reduction” to the Administrator for the same 

 

562 ”“State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 F.R.FR 53340, 53343 (Nov. 17, 1975). 
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reasons discussed in the preamble to the 1975 implementing 

regulations. 

In addition, in the legislative history of the 1977 CAA 

Amendments, when Congress replaced the term “emission standards” 

under CAA section 111(d)(1) with the term “standards of 

performance,” Congress endorsed the overall approach of the 

implementing regulations, which lends further credence to the 

proposition that the EPA has the responsibility for determining 

the “best system of emission reduction” and the amount of 

emission limitation from the existing sources. Specifically, in 

the House report that introduced the substantive changes to CAA 

section 111, the Committee explained that “[t]he Administrator 

would establish guidelines as to what the best system for each 

category of existing sources is.”563 States, on the other hand, 

“would be responsible for determining the applicability of such 

guidelines to any particular source or sources.”564 The use of 

the term “guidelines,” which does not appear in CAA section 

111(d), indicates Congress was aware of and approved of the 

approach taken in the EPA’s implementing regulations for 

establishing guidelines, which determine the BSER. At a minimum, 

if Congress disapproved of the EPA’s implementing regulations, 

 

563 H.R. Rep. No. 95-294, at 195 (May 12, 1977) (emphasis added). 564 H.R. Rep. No. 95-294, at 195 (May 12, 1977) (emphasis added). 
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we would not expect the House report to adopt the EPA’s 

terminology to clarify CAA section 111(d). 

In addition, Congress expressly referred to our 

“guidelines” in CAA section 129, added as part of the 1990 CAA 

Amendments. Congress added CAA section 129 to address solid 

waste combustion and specifically directed the Administrator to 

establish “guidelines (under section 111(d) and this section) 

and other requirements applicable to existing units.”565 This 

reference also indicates that Congress was aware of and approved 

the EPA’s regulations under section 111(d). 

The EPA has followed the same approach described in the 

implementation regulations in all its rulemakings under section 

111(d). Thus, in all cases, the EPA has identified the type of 

emission controls for the source category and the level of 

emission limitation based on those controls.566 The EPA’s 

 

565 CAA section 129(a)(1)(A) (emphasis added). 566 See 40 CFR Part 60, Subpart Ca (large municipal waste 

combustors), 56 FR 5514 (Feb. 11, 1991), 40 CFR 60.30a-.39a 

(subsequently withdrawn and superseded by Subpart Cb, see 60 FR 

65387 (Dec. 19, 1995)); Subpart Cb (large municipal waste 

combustors constructed on or before September 20, 1994), 60 FR 

65387 (Dec. 19, 1995), 40 CFR 60.30b-.39b (as amended in 1997, 

2001, and 2006); Subpart Cc (municipal solid waste landfills), 

61 FR 9905 (Mar. 12, 1996), 40 CFR 60.30c-.36c (as amended in 

1998, 1999, and 2000); Subpart Cd (sulfuric acid production 

units), 60 FR 65387 (Dec. 19, 1995), 40 CFR 60.30d-.32d; Subpart 

Ce (hospital/medical/infectious waste incinerators), 62 FR 48348 

(Sept. 15, 1997), 40 CFR 60.30e-.39e (as amended in 2009 and 
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longstanding and consistent interpretation of CAA section 111(d) 

is also “evidence showing that the statute is in fact not 

ambiguous,” and that the EPA’s interpretation should be 

adopted.567 

Lastly, this interpretation is consistent with the Supreme 

Court’s reading of CAA section 111(d) in American Electric Power 

Co. There, the Court explained that “EPA issues emissions 

guidelines, see 40 C.F.R. § 60.22, .23 (2009); in compliance 

with those guidelines and subject to federal oversight, the 

 

2011); Subpart BBBB (small municipal waste combustion units 

constructed on or before August 30, 1999), 65 FR 76738 (Dec. 6, 

2000), 40 CFR 60.1500-.1940; Subpart DDDD (commercial and 

industrial solid waste incineration units that commenced 

construction on or before November 30, 1999), 65 FR 75338 (Dec. 

1, 2000), 40 CFR 60.2500-.2875 (as amended in 2005, 2011, and 

2013); Subpart FFFF (other solid waste incineration units that 

commenced construction on or before December 9, 2004), 70 FR 

74870 (Dec. 16, 2005), 40 CFR 60.2980-.3078 (as amended in 

2006); Subpart HHHH (coal-electric utility steam generating 

units), 70 FR 28606 (May 18, 2005) (subsequently vacated by the 

D.C. Circuit in New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 

2008)); Subpart MMMM (existing sewage sludge incineration 

units), 76 FR 15372 (Mar. 21, 2011), 40 CFR 60.5000-.5250; 

“Phosphate Fertilizer Plants, Final Guideline Document 

Availability,” 42 FR 12022 (Mar. 1, 1977) (not codified); “Kraft 

Pulp Mills; Final Guideline Document; Availability,” 44 FR 29828 

(May 22, 1979) (not codified); and “Primary Aluminum Plants; 

Availability of Final Guideline Document,” 45 FR 26294 (Apr. 17, 

1980) (not codified). 

567 Scalia, Antonin, Judicial Deference to Administrative 

Interpretations of Law, 1989 Duke L.J. 511, 518; see Riverkeeper 

v. Entergy, 556 U.S. 208, 235 (2009). 
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States then issue performance standards for stationary sources 

within their jurisdiction, § 7411(d)(1).”568

 As noted in the response to comment document, some 

commenters agreed with our interpretation, just discussed, while 

others argued that the states should be given the authority to 

determine the best system of emission reduction and, therefore, 

the level of emission limitation from their sources. For the 

reasons just discussed, this latter interpretation is an 

incorrect interpretation of CAA section 111(d)(1) and (a)(1), 

and we are not compelled to abandon our longstanding practice. 

2. Approach to subcategorization. 

 As noted above, in this rule, we are treating all fossil 

fuel-fired EGUs as a single category, and, in the emission 

guidelines that we are promulgating with this rule, we are 

treating steam EGUs and combustion turbines as separate 

subcategories. We are determining the BSER for steam EGUs and 

the BSER for combustion turbines, and applying the BSER to each 

subcategory to determine a performance rate for that 

subcategory. We are not further subcategorizing among different 

types of steam EGUs or combustion turbines. 

 

568 Am. Elec. Power Co. v. Connecticut, 131 S. Ct. 2527, 2537-38 

(2011). 
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 This approach is fully consistent with the provisions of 

section 111(d), which simply require the EPA to determine the 

BSER, do not prescribe the method for doing so, and are silent 

as to subcategorization. This approach is also fully consistent 

with other provisions in CAA section 111, which require the EPA 

first to list source categories that may reasonably be expected 

to endanger public health or welfare569 and then to regulate new 

sources within each such source category,570 and which grant the 

EPA discretion whether to subcategorize new sources for purposes 

of determining the BSER.571 

 For this rule, our approach of subcategorizing between 

steam EGUs and combustion turbines is reasonable because 

building blocks 1 and 2 apply only to steam EGUs. No further 

subcategorization is appropriate because each affected EGU can 

achieve the performance rate by implementing the BSER. 

Specifically, as noted, each affected EGU may take a range of 

actions including investment in the building blocks, replacing 

or reducing generation, and emissions trading, as enabled or 

facilitated by the implementation programs the states adopt. 

Further, in the case of a rate-based state plan, several other 

 

569 CAA section 111(b)(1)(A). 570 CAA section 111(b)(1)(B). 571 CAA section 111(b)(2). 
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compliance options not included in the BSER for this rule are 

also available to all affected sources, including investment in 

demand-side energy efficiency measures. 1Such compliance options 

help affected sources achieve compliance under a mass-based 

plan, even if indirectly. Our approach to subcategorization in 

this rule is consistent with our approach to subcategorization 

in previous section 111 rules for this industry, in which we 

determined whether or not to subcategorize on the basis of the 

ability of affected EGUs with different characteristics (e.g., 

size or type of fuel used) to implement the BSER and achieve the 

emission limits).572 

 

572 Compare “Revision of Standards of Performance for Nitrogen 

Oxide Emissions From New Fossil-Fuel Fired Steam Generating 

Units; Revisions to Reporting Requirements for Standards of 

Performance for New Fossil-Fuel Fired Steam Generating Units: 

Final Rule,” 63 FR 49442 (Sept. 16, 1998) and “Proposed 

Revision of Standards of Performance for Nitrogen Oxide 

Emissions From New Fossil-Fuel Fired Steam Generating Units: 

Proposed Revisions,” 62 FR 36948, 36943 (July 9, 1997) 

(establishing a single NOx emission limit for new fossil-fuel 

fired steam generating units, and not subcategorizing, because 

the affected units could implement the BSER of SCR and achieve 

the promulgated emission limits) with “National Emission 

Standards for Hazardous Air Pollutants From Coal and Oil-Fired 

Electric Utility Steam Generating Units and Standards of 

Performance for Fossil-Fuel-Fired Electric Utility, IndustrialCommercial-Institutional, and Small Industrial-CommercialInstitutional Steam Generating Units: Final Rule,” 77 FR 9304 

(Feb. 16, 2012) (MATS rule) and “National Emission Standards 

for Hazardous Air Pollutants From Coal and Oil-Fired Electric 

Utility Steam Generating Units and Standards of 
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 In addition, there are numerous possible criteria to use in 

subcategorizing, including, among others, subcategorizing on the 

basis of age; size; steam conditions (i.e., subcritical or 

supercritical); type of fuel, including type of coal (i.e., 

lignite, bituminous, and sub-bituminous), and coal refuse; and 

method of combustion (i.e., fluidized bed combustion, pulverized 

coal combustion, and gasification). In addition, there are 

different possible combinations of those categories. At least 

some of those criteria do not have logical cut-points. 

Furthermore, we have not been presented with, nor can we 

discern, a method of subcategorizing based on these or other 

criteria that is appropriate in light of the BSER for the 

affected EGUs and their ability to meet the emission limits. 

Moreover, our approach of not further subcategorizing as between 

 

Performance for Fossil-Fuel-Fired Electric Utility, IndustrialCommercial-Institutional, and Small Industrial-CommercialInstitutional Steam Generating Units: Proposed Rule,” 76 FR 

24976, 25036-37 (May 3, 2011) (subcategorizing coal fired units 

designed to burn coal with greater than or equal to 8,300 Btu/lb 

(for Hg emissions only), coal-fired units designed to burn coal 

with less than 8,300 Btu/lb (for Hg emissions only), IGCC units, 

liquid oil units, and solid oil-derived units; evaluating 

“subcategorization of lignite coal vs. other coal ranks; 

subcategorization of Fort Union lignite coal vs. Gulf Coast 

lignite coal vs. other coal ranks; subcategorization by EGU size 

(i.e., MWe); subcategorization of base load vs. peaking units 

(e.g., low capacity utilization units); subcategorization of 

wall-fired vs. T fired units; and subcategorization of small, 

non-profit-owned units vs. other units;” but deciding not to 

adopt those latter subcategorizations). 
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different types of steam EGUs or combustion turbines reflects 

the reasonable policy that affected EGUs with higher emission 

rates should reduce their emissions by a greater percentage than 

affected EGUs with lower emission rates, and can do so by 

implementing the BSER we are identifying. 

 In addition, a section 111(d) rule presents less of a need 

to subcategorize because the states retain great flexibility in 

assigning standards of performance to their affected EGUs. Thus, 

a state can, if it wishes, impose different emission reduction 

obligations on its sources, as long as the overall level of 

emission limitation is at least as stringent as the emission 

guidelines, as discussed below. This means that if a state is 

concerned that its different sources have different capabilities 

for compliance, it can adjust the standards of performance in 

imposes on its sources accordingly. 

3. Building blocks 2 and 3 as a “system of emission reduction”

a. Overview. As we explain above, the emission performance 

standards for emissionsrates that we include in this rule’s 

emissionsemission guidelines are achievable by the affected EGUs 

through the application of the BSER, which includes the three 

building blocks. Commenters object that building blocks 2 

(generation shift) and 3 (renewable energy) cannot, as a legal 

matter, be considered to be part of the BSER under CAA section 
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111(d)(1) and (a)(1). These commenters explain that in their 

view, under CAA section 111, the emission performance 

standardsrates must be based on, and therefore the BSER must be 

limited to, methods for emissionsemission control that the 

owner/operator of the affected source can integrate into the 

design or operation of the source itself, and that cannot be 

based on actions taken beyond the source or actions involving 

third-party entities.573 For these reasons, these commenters 

argue that the phrase “system of emission reduction” cannot be 

interpreted to include building blocks 2 and 3. 

 

573 See, e.g., comments by UARG at 6-7 (“Standards promulgated 

under section 111 must be source-based and reflect measures that 

the source’s owner can integrate into the design or operation of 

the source itself. A standard cannot be based on actions taken 

beyond the source itself that somehow reduce the source’s 

utilization.”); comments by UARG at 31 (the building blocks 

other than building block 1 take a “’beyond“‘beyond-the-source’ 

approach” and “impermissibly rely on measures that go beyond the 

boundaries of individual affected EGUs and that are not within 

the control of individual EGU owners and operators”); comments 

by UARG at 33 (the “system” of emission reduction “can refer 

only to reductions resulting from measures that are incorporated 

into the source itself;” section 111 is “designed to improve the 

emissions performance of new and existing sources in specific 

categories based on the application of achievable measures 

implemented in the design or production process of the source at 

reasonable cost.”); comments by American Chemistry Council et 

al. (“Associations”) at 60-61 (EPA’s proposed BSER analysis is 

unlawful because it “looks beyond the fence line of the fossil 

fuel-fired EGUs that are the subject of this rulemaking;” “the 

standard of performance must ... be limited to the types of 

actions that can be implemented directly by an existing source 

within [the appropriate] class or category.”). 
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We disagree with these comments., and note that other 

commenters were supportive of our determination to include 

building blocks 2 and 3. Under CAA section 111(d)(1) and (a)(1), 

the EPA’s emission guidelines must establish achievable emission 

limits based on the “best system of emission reduction ... 

adequately demonstrated.” While some commenters assert that 

emission guidelines must be limited in the manner summarized 

above, the phrase “system of emission reduction,” by its terms 

and when read in context, contains no such limits. To the 

contrary, its plain meaning is deliberately broad and, under 

Chevron step 1, is capacious enough to include actions taken by 

the owner/operator of a stationary source designed to reduce 

emissions from that affected source, including actions that may 

occur off-site and actions that a third party takes pursuant to 

a commercial relationship with the owner/operator, so long as 

those actions enable the affected source to achieve its emission 

limitation. TheSuch actions include the measures in building 

blocks 2 and 3, which include these types of actions, when 

implemented by an affected source, enable the affected 

EGUssource to achieve their emission limits due tobecause of the 

unique characteristics of the utility power sector. For these 

reasonspurposes of this rule, we envisionconsider a “system of 

emission reduction” –-- as defined under CAA section 111(a)(1) 
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and applied under CAA section 111(d)(1) -- as-– to encompass a 

big toolboxbroad range of pollution-reduction actions, which 

includes the measures in building blocks 2 and 3. It should be 

recalled, however, that CAA section 111 also requires that we 

determine that these Furthermore, the measures are “adequately 

demonstrated”in building blocks 2 and represent the “best” 

system of emission reduction in order3 fall squarely within 

EPA’s historical interpretation of section 111, pursuant to 

serve aswhich the basisfocus for the emission reduction 

requirements. BSER has been on how to most cleanly produce a 

good, not on how much of the good should be produced.

Our Chevron step 1 interpretation that thea “system of 

emission reduction” is broad enough to include the measures in 

building blocks 2 and 3 is supported by the following: our 

interpretation of the phrase “system of emission reduction” is 

consistent with the “catch-all” natureits plain meaning and 

statutory context; our interpretation accommodates the very 

design of CAA section 111(d)(1), which is designed to 

covercovers a range of source categories and air pollutants;574

 

574 Because it is designed to apply to a range of air pollutants 

not regulated under other provisions, CAA section 111(d) may be 

described as a “catch-all” or “gap-filler.” As such, a “system 

of emission reduction” as applied under CAA section 111(d) 

should be interpreted flexibly to accommodate this role. 
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our interpretation is supported by the legislative history of 

CAA section 111(d)(1) and (a)(1), which indicates Congress’s 

intent to give the EPA broad discretion in determining the basis 

for CAA section 111 control requirements, particularly for 

existing sources, and Congress’s intent to authorize the EPA to 

consider measures that could be carried out by parties other 

than the affected sources; and our interpretation is reasonable 

in light of comparisons to otherCAA provisions of the CAA that 

give the EPA similar authority to consider such measures, and 

comparisons to otherCAA provisions that clearly narrow the field 

ofwould preclude the EPA from considering such measures to be 

considered. Finally, we note that contrary to arguments by 

commenters, no other provisions of CAA section 111 suggest that 

the phrase “system of emission reduction” must be limited to 

measures that the source’s owner can integrate into the design 

or operation of the affected source itself... 

To the extent the phrase “system of emission reduction” is 

ambiguous, the EPA has discretion under Chevron step 2In 

addition to interpret it to include building blocks 2 and 3, for 

the the reasons stated above, as well as the the EPA's 

interpretation is also reasonable for the following reasons.:

(i) Building blocks 2 and 3 fit well within the structure and 

economics of the utility power sector. (ii) Fossil fuel-fired 
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EGUs are already implementing the measures in these building 

blocks for various reasons, including for purposes of reducing 

CO2 emissions. (iii) Interpreting the phrase “system of emission 

reduction” to incorporate building blocks 2 and 3 is consistent 

with (a) other provisions in the CAA, including the acid rain 

provisions in Title IV and the SIP provisions in CAA section 

110, along with the EPA’s regulations implementing the CAA SIP 

requirements concerning interstate transport and regional haze, 

each of which is based on at least some of the same measures 

included in building blocks 2 and 3; (b) prior EPA action under 

CAA section 111(d), including the 2005 Clean Air Mercury Rule,575

which is based on some of the same measures in building blocks 2 

and 3; (c) the various provisions of the CAA that authorize 

emissions trading, because emissions trading entails a source 

meeting its emission limitation based on the actions of another 

entity; and (d) the pollution prevention provisions of the CAA, 

which make clear that a primary goal of the CAA is to encourage 

federal and state actions that reduce or eliminate, through any 

 

575 This rule was vacated by the D.C. Circuit on other grounds. 

New Jersey v. EPA, 517 F.3d 574, 583-84 (D.C. Cir. 2008), cert. 

denied sub nom. Util. Air Reg. Group v. New Jersey, 555 U.S. 

1169 (2009). 
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measures, the amount of pollution produced at the source.576 (iv) 

Most broadlyLastly, interpreting the phrase “system of emission 

reduction” to giveauthorize the EPA, in formulating its BSER 

determination, to weigh a big toolboxbroad range of emissionreducing measures that includes building blocks 2 and 3 to 

reduce emissions is consistent with Congress’s intentionintent

to address urgent environmental problems and to be precautionary 

in protectingprotect public health and welfare against risks, as 

well as Congress’s expectation that American industry would be 

able to develop the innovative solutions necessary to protect 

public health and welfare.

b. System of emission reduction as a big toolbox under Chevron

Step 1. 

Congress passed the CAA, including its several amendments, 

to protect public health and welfare from “mounting dangers,” 

including “injury to agricultural crops and livestock, damage to 

and the deterioration of property, and hazards to air and ground 

transportation.”577 In doing so, Congress established numerous 

programs to address air pollution problems and provided the EPA 

 

576 As noted in the Legal Memorandum, in several of these 

rulemakings and in the course of litigation, the fossil fuelfired electric power sector has taken positions that are 

consistent with the EPA’s interpretation that the BSER may 

include building blocks 2 and 3. 

577 CAA section 101(a)(2). 
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with guidance and flexibility in carrying out many of those 

programs. Even if we were to accept commenters’ view that the 

system of emission reduction identified as best here is not 

integrated into the design or operation of the regulated 

sources, in the context of this industry and this pollutant it 

is reasonable to reject the narrow interpretation urged by some 

commenters that the “system of emission reduction” applicable to 

the affected EGUs must be limited to only those measures that 

can be integrated into the design or operation of the source 

itself. The plain language of the statute does not support such 

an interpretation, and to adopt it would limit the “system of 

emission reduction” to measures that are either substantially 

more expensive or substantially less effective at reducing 

emissions than the measures in building blocks 2 and 3, 

notwithstanding the absence of any statutory language imposing 

such a limit. Such a result would be contrary to the goals of 

the CAA and would ignore the facts that sources in the electric 

generation industry routinely address planning and operating 

objectives on a broad, multi-source basis using the measures in 

building blocks 2 and 3 and would seek to use building blocks 2 

and 3 (as well as non-BSER measures) to comply with whatever 

emission standards are set as a result of this rule. Indeed, as 

already observed, building blocks 2 and 3 are already being used 
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Page 659 of 2153

to reduce emissions, and to do so specifically by operation of 

the industry’s inherent multi-source functions. 

 Although the BSER provisions are sufficiently broad to 

include, for affected EGUs, the measures in building blocks 2 

and 3, they also incorporate significant constraints on the 

types of measures that may be included in the BSER. We discuss 

those constraints at the end of this section. They include the 

section 111(d)(1) and (a)(1) requirements that emission 

reductions occur from the affected sources; that the emission 

performance standards for which the BSER forms the basis be 

achievable; that the system of emission reduction be adequately 

demonstrated; and that the EPA account for cost, non-air quality 

impacts, and energy requirements in determining the “best” 

system of emission reduction that is adequately demonstrated. 

The constraints included in these statutory requirements do not 

preclude building blocks 2 and 3 from the BSER. In interpreting 

these statutory requirements for determining the BSER, the EPA 

is consistent with past practice and current policy for both 

section 111 regulatory actions as well as regulatory actions 

under other CAA provisions for the electric power sector, under 

which the EPA has generally taken the approach of basing 

regulatory requirements on controls and measures designed to 

reduce air pollutants from the production process without 
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Page 660 of 2153

limiting the aggregate amount of production. This approach has 

been inherent in our past interpretation and application of 

section 111 and we maintain this interpretation in this 

rulemaking.578 While inclusion of building blocks 2 and 3 is 

consistent with our interpretation of the statutory 

requirements, inclusion of building block 4 is not, and for that 

reason, we are declining to include building block in the BSER. 

Finally, we briefly note additional constraints that focus the 

BSER identified for new sources under section 111(b) on controls 

that assure that sources are well-controlled at the the time of 

construction. 

b. System of emission reduction as a broad range of measures. 

(1) Plain meaning and context of “system of emission 

reduction”..” 

 

578 As we note in section V.A., this rulemaking presents a unique 

set of circumstances, including the global nature of CO2 and the 

emission control challenges that CO2 presents (which limit the 

availability and effectiveness of control measures), combined 

with the facts that the electric power industry (including 

fossil fuel-fired steam generators and combustion turbines) is 

highly integrated, electricity is fungible, and generation is 

substitutable (which all facilitate the generation shifting 

measures encompassed in building blocks 2 and 3). Our 

interpretation of section 111 as focusing on limiting emissions 

without limiting aggregate production must take into account 

those unique circumstances. 
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 The phrase “system of emission reduction” appears in the 

definition of a “standard of performance” under CAA section 

111(da)(1) and (a)(1) make). That definition reads: 

a standard for emissions of air pollutants which reflects 

the degree of emission limitation achievable through the 

application of the best system of emission reduction which 

(taking into account the cost of achieving such reduction 

and any nonair quality health and environmental impact and 

energy requirements) the Administrator determines has been 

adequately demonstrated. 

Pursuant to this definition, it is clear that a “system of 

emission reduction” serves as the basis for emission limits 

embodied by CAA section 111 standards. For this reason, emission 

limits must be “achievable” through the “application” of the 

“best” “system of emission reduction” “adequately demonstrated.” 

Under CAA section 111(d)(1), such a limit is established for 

“any existing source,” which is defined as any existing 

“building, structure, facility, or installation which emits or 

may emit any air pollutant.”579 

 

579 See CAA section 111(d)(1) (applying a standard of performance 

to any existing source); (a)(6) (defining the term “existing 

source” as any stationary source other than a new source); and 

(a)(3) (defining the term “stationary source” as “any building, 

structure, facility, or installation which emits or may emit any 

air pollutant,” however, explaining that “[n]othing in 

subchapter II [i.e., Title II] of this chapter relating to 

nonroad engines shall be construed to apply to stationary 

internal combustion engines.”) 
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Although a “system of emission reduction” lays the 

groundwork for CAA section 111 standards, the term “system” is 

not defined in the CAA. As a result, we look first to its 

ordinary meaning. 

Abstractly, the term “system” means a set of things or 

parts forming a complex whole; a set of principles or procedures 

according to which something is done; an organized scheme or 

method; and a group of interacting, interrelated, or 

interdependent elements.580 As a phrase, “system of emission 

reduction” takes a broad meaning to serve a singular purpose: it 

is a set of measures that work together to reduce emissions. 

 When read in context, the phrase “system of emission 

reduction” carries important limitations: because the purpose of 

the “system of emission reduction” is to serve as the basis for 

the emission limitation, and because the “degree of emission 

limitation” must be “achievable” by the source, through the 

application of the best system of emission reduction,” (emphasis 

added), the “system of emission reduction” must be oflimited to

 

580 Oxford Dictionary of English (3rd ed.) (2010), available at

http://www.oxforddictionaries.com/us/definition/american_english

/system; see also American Heritage Dictionary (5th ed.) (2013), 

available at 

http://www.yourdictionary.com/system#americanheritage; and The 

American College Dictionary (C.L. Barnhart, ed. 1970) (“an 

assemblage or combination of things or parts forming a complex 

or unitary whole”). 
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a typeset of measures that allows thework together to reduce 

emissions and that are implementable by the sources themselves. 

As a practical matter, the “source” includes the “owner or 

operator” of any building, structure, facility, or installation 

for which a standard of performance is applicable. For instance, 

under CAA section 111(e), it is the “owner or operator” of a

source who is prohibited from operating “in violation of any 

standard of performance applicable to such source.”581

Thus, a “system of emission reduction” for purposes of CAA 

section 111(d) means a set of measures that source owners or 

operators can implement to achieve itsan emission limitation. 

applicable to their existing source.582

The term “system” is not defined in the CAA. As a result, 

that term should be given its ordinary, everyday meaning, which 

is “a set of things working together as parts of a mechanism or 

 

581 While this section provides for enforcement in the context of 

new sources, a CAA section 111(d) plan must provide for the 

enforcement of a standard of performance for existing sources. 

582 Some commenters read the proposed rulemaking as taking the 

position that the phrase “system of emission reduction” includes 

anything whatsoever that reduces emissions, and criticized that 

interpretation as too broad. See UARG comment, at 3-4. We are 

not taking that interpretation here. In this final rule, we 

agree that the phrase should be limited to exclude, inter alia, 

actions beyond the ability of the owners/operators to control. 
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interconnecting network; a complex whole.”583 With this 

definition, the phrase “system of emission reduction” takes a 

broad meaning: a set of things that work together to reduce 

emissions. In light of its context, this phrase carries an 

important limitation: because the emission limitation must be 

achievable through the application of the system of emission 

reduction, the system must be limited to things that can be 

implemented by the sources themselves, that is, as a practical 

matter, to actions taken by the owners or operators of the 

sources. Thus, actions that the owners/operators may take to 

achieve an applicable emission limitation qualify as a system of 

emission reduction.584 In In contrast, a “system of emission 

reduction” does not include actions that theonly a state or 

other governmental entity could take that would have the effect 

of reducing emissions from the source category, butand that are 

 

583 Oxford Dictionary of English (3rd ed.) (published 2010, 

online version 2013) 

http://www.oxfordreference.com.mutex.gmu.edu/view/10.1093/acref/

9780199571123.001.0001/acref-9780199571123. See The American 

College Dictionary (C. L. Barnhart, ed. 1970) at [X](“an 

assemblage or combination of things or parts forming a complex 

or unitary whole”). 

584 Some commenters read the proposed rulemaking as taking the 

position that the phrase “system of emission reduction” includes 

anything whatsoever that reduces emissions, and criticized that 

interpretation as too broad. See UARG comment. In this final 

rule, we agree that the phrase should be limited to exclude 

actions beyond the ability of the owners/operators to take. 
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beyond the ability of the affected sources’ owners/operators to 

take or control,. Additionally, actions that a source owner or 

operator could take that would not have the effect of reducing 

emissions from the source category, such as purchasing offsets, 

would also not qualify as a “system of emission reduction for 

this purpose. .”

Building blocks 2 and 3 each fall within the meaning of a 

“system of emission reduction” because they consist of measures 

that the owners/operators of the affected EGUs can implement to 

achieve their emission limits. In doing so, the affected EGUs 

will achieve the overall emission reductions the EPA identifies 

in this rule. We describe these building block 2 and 3 measures 

in detail elsewhere in this rule, including the specific actions 

that owners/operators of affected EGUs can take to implement the 

measures. 

It should be noted that defining the scope of a “system of 

emission reduction” is not the end of our inquiry under CAA 

section 111(a)(1); rather, as noted above, a standard of 

performance must reflect the application of the “best system of 

emission reduction ... adequately demonstrated.” (Emphasis 

added.) It should be noted that, although we do not need to 

determine the overall scope of the “system of emission 

reduction,” other limitations may also apply. For example, it is 
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Page 666 of 2153

doubtful that payments by a source to a governmental entity to 

fund some sort of pollution prevention or emission control 

program would qualify as a system of emission reduction because 

the source may not be able to assure that the governmental 

entity will take the requisite action. A change in governmental 

policy could interfere with the implementation of the government 

program and, under those circumstances, the source would be 

unable to achieve the required degree of emission limitation. 

Thus, in determining the BSER, the Administrator must first 

determine whether the available systems of emission reduction 

are “adequately demonstrated,” based on the criteria, described 

above, set out by Congress in the legislative history and the 

D.C. Circuit in case law. After identifying the “adequately 

demonstrated” systems of emission reduction, the Administrator 

then selects the “best” of these, based on several factors, 

including amount of emission reduction, cost, non-air quality 

health and environmental impact and energy requirements. Only 

after the Administrator weighs all of these considerations can 

she determine the BSER and, based on that, establish a standard 

of performance under CAA section 111(b) or an emission guideline 

under CAA section 111(d). 

For purposes of this final rule, however, it is not 

necessary to enumerate all of the types of methods of emission 
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Page 667 of 2153

reduction measures that do or do not constitute a “system of 

emission reduction.” What is relevant is that building blocks 2 

and 3 each qualify as part of the “system of emission reduction” 

because, as.” As noted, they focus on supply-side activities and

they each constitute measures that the affected EGUs can 

implement that will allow those EGUs to achieve the degree of 

emission limitation that the EPA has identified based on those 

building blocks. Further, these building blocks also satisfy the 

other statutory criteria enumerated in CAA section 111(a)(1).

(2) Other indications that the BSER provisions areencompass

a big toolbox. broad range of measures. 

The EPA’s plain meaning interpretation ofthat the BSER 

provisions in CAA section 111(d)(1) and (a)(1) as a big toolbox 

that isare designed to include a broad range of measures, 

including building blocks 2 and 3, is supported by several other 

indications in the CAA and the legislative history of section 

111. 

(a) “Catch-all” natureScope of CAA section 111(d)(1). 

First, the “catch-all” naturebroad scope of CAA section 

111(d)(1) supports interpretingour interpretation of the BSER as 

a big toolbox because a wide range of control measures is 

appropriate for the wide range of source categories and air 

pollutants covered under CAA section 111(d). 
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 In the 1970 CAA Amendments, the Congress established a 

regulatory regime for existing stationary sources of air 

pollutants that may be envisioned as a three-legged stool, 

designed to address “three categories of pollutants emitted from 

statutorystationary sources”: (1) criteria pollutants 

(identified under CAA section 109 and regulated under section 

110); (2) hazardous air pollutants (identified and regulated 

under section 112); and (3) “pollutants that are (or may be) 

harmful to public health or welfare but are not” criteria or 

hazardous air pollutants.585 Congress enacted CAA section 111(d) 

to cover this third category of air pollutants and, in this 

sense, the Congress designed it to be a “catch-all” -- it would

apply to any air pollutants that were not otherwise regulated as 

toxics or NAAQS pollutants.586 This would include air pollutants 

that the EPA might later, when more information became 

available, designate as NAAQS or hazardous air pollutants, as 

 

585 40 FR 53340, 53340 (Nov. 17, 1975) (EPA regulations 

implementing CAA section 111(d)). 

586 See SenS. Rep. No. 91-1196, p.at 20 (Sept. 17, 1970), 1970 

CAA Legis. Hist. at 420 (“It should be noted that the emission 

standards for pollutants which cannot be considered hazardous 

(as defined in section 115 [i.e., the bill’s version of CAA 

section 112] could be established under section 114 [i.e., the 

bill’s version CAA section 111]. Thus, there should be no gaps 

in control activities pertaining to stationary source emissions 

that pose any significant danger to public health or welfare.”). 
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well as air pollutants that Congress may not have been aware of 

at the time.587 In addition, the indications are that Congress 

expected CAA section 111(d) to be a significant source of 

regulatory activity, by some measures, more active than CAA 

section 112. This is evident because Congress expected that CAA 

section 111(d) would cover more air pollutants than either CAA 

section 109/110 (criteria pollutants) or CAA section 112 

(hazardous air pollutants).588 In addition, in the 1990 CAA 

Amendments, Congress enacted CAA section 129 to achieve emission 

reductions from a major source category, solid waste 

incinerators, and established CAA section 111(d) as the basic 

mechanism for that provision. The EPA subsequently promulgated a 

number of CAA section 129/111(d) rulemakings.589 Finally, it 

 

587 See SenS. Rep. No. 91-1196, p.at 20 (Sept. 17, 1970), 1970 

CAA Legis. Hist. at 420. 

588 See SenS. Rep. No. 91-1196, pp.at 9; 18-20, 1970 CAA Legis. 

Hist. at 418-20. The Senate Committee Report identified 14 

substances as subject to the provision that became section 

111(d), four substances as hazardous air pollutants that would 

be regulated under the provision that became section 112, and 5 

substances as criteria pollutants that would be regulated under 

the provisions that became sections 109-110 (and more “as 

knowledge increases”). In particular, the Report recognized that 

in particular, relatively few air pollutants may qualify as 

hazardous air pollutants, but that other air pollutants that did 

not qualify as hazardous air pollutants would be regulated under 

what became section 111(d). 

589 See, e.g., Standards of Performance for New Stationary 

Sources and Emission Guidelines for Existing Sources: 

Hospital/Medical/Infectious Waste Incinerators, 62 Fed. Reg. 
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should be noted that Congress designed CAA section 111(d) to 

cover a wide range of source categories ––- including any source 

category that the EPA identifies under subsection 111(b)(1)(A) 

as meeting the criteria of, in general, causing or contributing 

significantly to air pollution that may reasonably be 

anticipated to endanger public health or welfare -- along with 

the wide range of air pollutants. 

Because Congress designed CAA section 111(d) as a “catchall” provision that coversto cover a wide range of air 

pollutants -- including ones that Congress may not have been 

aware of at the time it enacted the provision –- and a wide 

range of industries, it is logical that Congress intended that 

the EPA have broad discretion in determining the basis for 

emission limitations under CAA section 111(d), and that the BSER 

provision, as applied to CAA section 111(d), behave a broadbased scope so that it couldas to accommodate this diversitythe 

range of air pollutants and source categories. 

(b) Legislative history of CAA section 111. 

(i).) Breadth of “system of emission reduction.” 

 

48,348FR 48348, 48359 (Sept. 15, 1997); Standards of Performance 

for New Stationary Sources and Emission Guidelines for Existing 

Sources: Commercial and Industrial Solid Waste Incineration 

Units, 65 Fed. Reg.FR 75338, 75341 (Dec. 1, 2000). 
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The legislative history of CAA section 111(d) and the term 

“standard of performance,” which includes the phrase “best 

system of emission reduction ... adequately demonstrated,” 

underscores the breadth that the Congress intended for the basis 

of CAA section 111(d) rulemaking.,” particularly as applied 

under CAA section 111(d), should be broadly interpreted 

consistent with its plain meaning but also in light of its 

legislative history. The version of CAA section 111(d)(1) that

the Congress adopted as part of the 1970 CAA Amendments read 

largely as CAA section 111(d)(1) does at present, except that it 

required states to impose “emission standards” on any existing 

source. (Congress replaced that term with “standards of 

performance” in the 1977 CAA Amendments.) The 1970 CAA 

Amendments version of CAA section 111(d)(1) neither defined 

“emission standards” nor imposed restrictions on the EPA in 

determining the basis for the emission standards. Therefore, CAA 

section 111(d)(1), as it read in 1970, allowed the EPA broad 

discretion in determining the basis for the emission 

standards.590

 

590 Although not defined under CAA section 111, the term was used 

in other provisions and defined in some of them. The term was 

defined under the CAA’s citizen suit provision. See 1970 CAA 

Amendments, Pub. L. 91-604, § 12, 84 Stat. 1676, 1706 (Dec. 31, 

1970) (defined as “(1) a schedule or timetable of compliance, 
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For new sources, CAA section 111(b)(1)(B), as enacted in 

the 1970 CAA Amendments (and as it largely still reads), 

required the EPA to promulgate “standards of performance,” and 

defined that term, much like the present definition, as emission 

standards based on the “best system of emission reduction ... 

adequately demonstrated.” This quoted phrase was not included in 

either the House or Senate versions of the provision, and, 

instead, was added during the joint conference between the House 

and Senate. The conference report accompanying the text offers 

no clarifications. 

The House and Senate bills do, however, provide some 

insights. The House bill, H.R. 17255, would have required new 

sources of non-hazardous air pollutants to “prevent and control 

 

emission limitation, standard of performance or emission 

standard, or (2) a control or prohibition respecting a motor 

vehicle fuel or fuel additive....”). Congress also used it in the 

CAA’s NAAQS provisions and in CAA section 112. Under the CAA’s 

NAAQS provisions (i.e., the “Ambient Air Quality and Emission 

Standards” provisions), Congress directed the EPA to issue 

information on “air pollution control techniques,” and include 

data on “available technology and alternative methods of 

prevention and control of air pollution” as well as on 

“alternative fuels, processes, and operating methods which will 

result in elimination or significant reduction of emissions.” 

Id., § 4, 84 Stat. at 1679. Similarly, under CAA section 112, 

the Administrator was required to “from time to time, issue 

information on pollution control techniques for air pollutants” 

subject to emission standards. Id., 84 Stat. at 1685. These 

statements provide additional context for the term’s broad 

intent. 
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such emissions to the fullest extent compatible with the 

available technology and economic feasibility, as determined by 

the Secretary.”591 The Senate bill, S. 4358, would have 

established “Federal standards of performance for new sources,” 

which, in turn, were to “reflect the greatest degree of emission 

control which the Secretary determines to be achievable through 

application of the latest available control technology, 

processes, operating methods, or other alternatives.”592 The 

Senate Committee Report explains that “performance standards 

should be met through application of the latest available 

emission control technology or through other means of preventing 

or controlling air pollution.”593 This Report further elaborates 

that the term “standards of performance” --

refers to the degree of emission control which can be 

achieved through process changes, operation changes, 

direct emission control, or other methods. The 

Secretary should not make a technical judgment as to 

how the standard should be implemented. He should 

determine the achievable limits and let the owner or 

operator determine the most economic, acceptable 

technique to apply.594 

 

591 H.R. 17255, § 5, 1970 CAA Legis. Hist. at 921-22. The 

reference to “Secretary” was to the Secretary of Health 

Education and Welfare, which, at the time, was the agency with 

responsibility for air pollution regulations. 

592 S. 4358, § 6, 1970 Legis. Hist. at 554-55 (emphasis added). 593 S. Comm. Rep. No. 91-1196, at 15-16 (Sept. 17, 1970), 1970 

CAA Legis. Hist. at 415-16 (emphasis added). 

594 SenS. Rep. No. 91-1196, pp.at 15-16 (Sept. 17, 1970), 1970 

CAA Legis. Hist. at 415-16 (emphasis added). 
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Thus, the Senate bill clearly envisioned that standards of 

performance would not be based on a particular technology or 

even a particular method to prevent or control air pollution.595

This vision contrasted with the House bill, which would have 

restricted performance standards to economically feasible 

technical controls. 

Following the House-Senate Conference, the enacted version 

of the legislation defined a “standard of performance” to mean 

a standard for emissions of air pollutants which 

reflects the degree of emission limitation achievable 

through the application of the best system of emission 

reduction which (taking into account the cost of 

achieving such reduction) the Administrator determines 

has been adequately demonstrated.596 

While the term “system” was not discussed in the Conference 

Report or discussed in either chamber during the debates over 

passage of the Conference agreement, the final text clearly 

blends the broad spirit of S.While the phrase “system of 

emission reduction” was not discussed in the Conference Report, 

 

595 Notably, the Senate report identifies pollution control and

pollution prevention as objectives of the Senate provision. 

Pollution prevention is discussed more generally below as a 

“primary purpose” of the CAA, however, the report makes clear 

that pollution prevention measures – which the EPA understands 

to include such measures as building blocks 2 and 3 -- are 

appropriate under CAA section 111. 

596 CAA section 111(a)(1) under the 1970 CAA Amendments (emphasis 

added). 
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an exhibit titled “Summary of the Provisions of Conference 

Agreement on the Clean Air Amendments of 1970” was added to the 

record during the Senate’s consideration of the Conference 

Report and sheds some light on the phrase. According to the 

summary, “[t]he agreement authorizes regulations to require that 

new major industry plants such as power plants, steel mills, and 

cement plants achieve a standard of emission performance based 

on the latest available control technology, processes, operating 

methods, and other alternatives.”597 In light of this summary, 

the phrase “system of emission reduction” appears to blend the 

broad spirit of S. 4358 (which required the “latest available 

control technology, processes, operating methods, or other 

alternatives”) with the cost concerns identified in H.R. 17255 

(which required consideration of “economic feasibility” when 

establishing federal emission standards for new stationary 

sources). The legislative history, therefore, confirms that the 

term “system” should be given its ordinary and broad meaningThis 

history strongly suggests that Congress intended to authorize 

the EPA to consider a wide range of measures in calculating a 

standard of performance for stationary sources. At a minimum, 

there is no indication that Congress intended to preclude 

 

597 Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-1783 

(Dec. 17, 1970), 1970 CAA Legis. Hist. at 130. 
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measures or actions such as the ones in building blocks 2 and 3 

from the EPA’s assessment of the BSER. 

The 1977 Notwithstanding this broad approach, as we discuss in 

the Legal Memorandum, the legislative history of the 1970 CAA 

Amendments signaled, for the most part, an ideological shift in 

CAA section 111’s approach foralso indicates that Congress 

intended that new sources. The be well-controlled at the source, 

in light of their expected lengthy useful lives. 

In 1977, Congress amended CAA section 111(a)(1) to limit 

the types of controls that could be the basis of standards of 

performance for new sources to technological controls. Congress 

was clear, however, that existing source standards, which were 

no longer developed as “emission standards,” would not be 

limited to technological measures. Specifically, the 1977 CAA

Amendments revised CAA section 111(a)(1) to require “all new 

sources to meet emission standards based on the reductions 

achievable through the use of the ‘”best technological system of 

continuous emission reduction.’ This means.”598 According to the 

legislative history, [t]his mean[t] that new sources may not 

comply merely by burning untreated fuel, either oil or coal.” 599

 

598 CAA section 111(a)(1) (1977). 599 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2659. 
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This change600 The new requirement stemmed in part from 

Congress’s concern over the shocks that the country experienced 

during the 1973-74 Arab Oil Embargo, which led Congress to 

revise CAA section 111 to “encourage and facilitate the 

increased use of coal, and to reduce reliance (by new and old 

sources alike), upon petroleum to meet emission requirements.”601

Imposing a new technological requirement (along with a new

percentage reduction requirement) under CAA section 111 was 

designed to “force new sources to burn high-sulfur fuel thus 

freeing low-sulfur fuel for use in existing sources where it is 

harder to control emissions and where low-sulfur fuel is needed 

for compliance.” 602 603 Congress nonetheless recognized that 

despite narrowing new source standards to the best 

“technological system of continuous emission reduction,” many 

“innovative approaches may in fact reduce the economic and 

energy impact of emissions control,” and the Administrator 

 

600 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2659. 

601 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2659. 

602 New Stationary Sources Performance Standards; Electric 

Utility Steam Generating Units, 44 Fed. Reg. 33580, 33581-33582 

(June 11, 1979). 

603 New Stationary Sources Performance Standards; Electric 

Utility Steam Generating Units, 44 FR 33580, 33581-33582 (June 

11, 1979). 
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should still be encouraged to consider other technologically 

based techniques for emissions reduction, including 

“precombustion cleaning or treatment of fuels.”604 This is 

discussed in more detail below. 

Despite these changes with respect to new sources, the 1977 

CAA Amendments further reinforce the notion that with respect to 

existing sources, the BSER was never intended to be narrowly 

applied. In 1977, Congress changed CAA section 111(d)(1) to 

require that states adopt “standards of performance” and made 

clear that such standards were to be based on the ”“best system 

of continuous emission reduction ... adequately demonstrated,”605

but generally maintained the breadth of that term. Although 

Congress inserted the word “continuous” into the phrase, 

Congress explained that “standards in the Section 111(d) state 

plan would be based on the best available means (not necessarily 

technological) for categories of existing sources to reduce 

emissions.”606 This was intended to distinguish existing source 

 

604 H.R. Rep. No. 95-294, at 189 (May 12, 1977), 1977 CAA Legis. 

Hist. at 2656. 

605 CAA section 111(a)(1)(C) under the 1977 CAA Amendments. 606 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2662 (emphasis added). Congress also endorsed the EPA’s practice 

of establishing “emission guidelines” under CAA section 111(d). 

See H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. 

at 2662 (“The Administrator would establish guidelines as to 

what the best system for each such category of existing sources 
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standards from new source standards, for which “the requirement 

for [BSER] has been more narrowly redefined as best 

technological system of continuous emission reduction.”607,608

In the 1990 CAA Amendments, Congress restored the 1970s 

vintage definition of a standard of performance as applied to 

both new and existing sources. With respect to existing sources, 

this had the effect of no longer requiring that the BSER be 

“continuous.”609 Further, nothing in the 1990 CAA Amendments or 

their legislative history indicates that Congress intended to 

 

is. However, the state would be responsible for determining the 

applicability of such guidelines to any particular source or 

sources.”). 

607 Sen. Muskie, SenS. Consideration of the H.R. Conf. Rep. No. 

95-564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353. 

608 In 1977, Congress added a new substantive definition for 

“emission standard” generally applicable throughout the CAA. 

1977 CAA Amendments, Pub. L. 95-95, § 301, 91 Stat. 685, 770 

(Aug. 7, 1977) (defining “emission limitation” and “emission 

standard” as “a requirement established by the State or the 

Administrator which limits the quantity, rate, or concentration 

of emissions of air pollutants on a continuous basis, including 

any requirement relating to the operation or maintenance of a 

source to assure continuous emission reduction.”). Congress also 

added a generally applicable definition of standard of 

performance, defined as “a requirement of continuous emission 

reduction, including any requirement relating to the operation 

or maintenance of a source to assure continuous emission 

reduction.” Id. 609 We note that the general definition of a standard of 

performance at CAA section 302(l) still uses “continuous.” Even 

if this provision applies to section 111, it does not affect our 

analysis in this rule, including our interpretation that BSER 

includes building blocks 2 and 3. 
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impose new limitsconstraints on the types of systems of emission 

reduction that could be considered under CAA section 111(d)(1) 

and (a)(1). In this manner,In contrast, Congress retained the 

1990 CAA Amendments further reinforce the breadth and 

flexibilitydefinition of the “term “technological system of 

continuous emission reduction.”,” which means 

(A) a technological process for production or operation by any 

source which is inherently low-polluting or nonpolluting, 

or 

(B) a technological system for continuous reduction of the 

pollution generated by a source before such pollution is 

emitted into the ambient air, including precombustion 

cleaning or treatment of fuels. 

That term continues to be used in reference to new sources in 

certain circumstances, under CAA section 111(b), (h), and (j).610

 

610 There are numerous reasons to find that particular CAA 

section 111(b) standards of performance should be based on 

controls installed at the source at the time of new 

construction. This is due in part to the recognition that new 

sources have long operating lives over which initial capital 

costs can be amortized, as recognized in the legislative history 

for section 111. Thus, new construction is the preferred time to 

drive capital investment in emission controls. See, e.g., S. 

Rep. No. 91-1196, at 15-16, 1970 CAA Legis. Hist. at 416 (“[t]he 

overriding purpose of this section [concerning new source 

performance standards] would be to prevent new air pollution 

problems, and toward that end, maximum feasible control of new 

sources at the time of their construction is seen by the 

committee as the most effective and, in the long run, the least 

expensive approach.”); see also 1977 CAA Amendments, § 109, 91 

Stat. at 700, (redefining, with respect to new sources, CAA 

section 111(a)(1) to reflect the best “technological system of 

continuous emission reduction” and adding CAA section 111(a)(7) 

to define this new term). However, as a result of the 1990 
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However, it is not and never has been used to regulate existing 

sources. In this manner, the 1990 CAA Amendments further 

reinforce the breadth and flexibility of the phrase “system of 

emission reduction,” particularly as it applies to existing 

sources under CAA section 111(d). 

For these reasons, the 1970, 1977, and 1990 legislative 

history confirms the breadth of the term, “system of emission 

reduction,” and supportshistories support the EPA’s 

interpretation in this rule that the term is sufficiently broad 

to encompass building blocks 2 and 3. 

(ii).) Reliance on actions taken by other entities. 

The legislative history supports the EPA’s interpretation 

of “system of emission reduction” in another way, as well: The 

legislative history makes clear that Congress intended that 

standards of performance for electric power plants could be 

based on measures implemented by other entities, for example, 

entities that “wash,” or desulfurize, coal (or, for oil-fired 

EGUs, that desulfurize oil). This legislative history is 

consistent with the EPA’s view that the “system of emission 

reduction” may include actions taken by an entity with whom the 

 

revisions to CAA section 111(a)(1), which replaced the phrase 

“technological system of continuous emission reduction” with 

“system of emission reduction,” new source standards would not 

be restricted to being based on technological control measures. 
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owner/operator of the affected source enters into a contractual 

relationship as long as those actions allow the affected source 

to meet its emission limitation. By the same token, this 

legislative history directly refutes commenters’ assertions that 

the phrase “system of emission reduction” must not include 

actions taken by entities other than the affected sources.611

InAs noted above, in the 1977 CAA Amendments, Congress 

revised the basis for standards of performance for new fossil 

fuel-fired stationary sources to be a “technological system of 

continuous emission reduction,” including “precombustion 

cleaning or treatment of fuels.”612 Precombustion cleaning or 

treatment reduces the amount of sulfur in the fuel, which means 

that the fuel can be combusted with fewer SO2 emissions, and that 

in turn means that the source can achieve a lower emission 

limit. Congress understood that these fuel cleaning techniques 

 

611 See, e.g., comments by UARG at 31 (the building blocks other 

than building block 1 take a “’beyond“‘beyond-the-source’ 

approach” and “impermissibly rely on measures that go beyond the 

boundaries of individual affected EGUs and that are not within 

the control of individual EGU owners and operators”); comments 

by American Chemistry Council et al. (“Associations”) at 60-61 

(EPA’s proposed BSER analysis is unlawful because it “looks 

beyond the fence line of the fossil fuel-fired EGUs that are the 

subject of this rulemaking;” “the standard of performance must 

... be limited to the types of actions that can be implemented 

directly by an existing source within [the appropriate] class or 

category.”). 

612 1977 CAA Amendments, § 109, 91 Stat. at 700; see also CAA 

section 111(a)(7). 
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would not necessarily be accomplished at the affected source 

and, in revising CAA section 111(a)(1), wanted to ensure that 

such techniques would not be overlooked. For example, the 1977 

House Committee report indicates that an assessment of the best 

technological system of continuous emission reduction for fossil 

fuel-fired power plants would include off-site or third-party 

pre-combustion techniques for reducing emissions at the source 

(“e.g., various coal-cleaning technologies such as solvent 

refining, oil desulfurization at the refinery”).613 Thus, the 

standard of performance reflecting the best technological system 

implementable by an affected source could be based, in part, on 

technologies used at off-site facilities owned and operated by 

third-parties. 

In the 1990 CAA Amendments, Congress eliminated many of the 

restrictions and other provisions added in the 1977 CAA 

 

613 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2655 (emphasis added). Generally speaking, coal cleaning 

activities also are conducted by third parties. For instance, 

EPA recognized in a regulatory analysis of new source 

performance standards for industrial-commercial-institutional 

steam generating units that the technology “requires too much 

space and is too expensive to be employed at individual 

industrial-commercial-institutional steam generating units.” 

U.S. EPA, Summary of Regulatory Analysis for New Source 

Performance Standards: Industrial-Commercial-Institutional Steam 

Generating Units of Greater than 100 Million Btu/hr Heat Input, 

EPA-450/3-86-005, p. 4-4 (June 1986). 
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Amendments by largely reinstating the 1970 CAA Amendments’ 

definition of “standard of performance.” Nevertheless, there is 

no indication that in doing so, Congress intended to preclude 

the EPA from considering coal cleaning by third parties (which 

had been considered partwithin the scope of the best system of 

emission reduction for sulfur dioxide reductions promulgatedeven

under the 1970 CAA Amendments),614 and in fact, the EPA’s 

regulations promulgated underafter the 1990 CAA Amendments have 

continuedcontinue to impose standards of performance that are 

based on third-party coal cleaning.615

(c) Consistency of a broad interpretation of CAA section 

111 with the overall structure of the CAA. 

Interpreting CAA section 111(d)(1) and (a)(1) to grant 

broad authority to the EPA to determineauthorize the basis for 

EPA’s consideration of the standards of performancebuilding 

 

614 See U.S. EPA, Background Information for Proposed New-Source 

Performance Standards: Steam Generators, Incinerators, Portland 

Cement Plants, Nitric Acid Plants, Sulfuric Acid Plants, Office 

of Air Programs Tech. Rep. No. APTD-0711, p. 7 (Aug. 1971) 

(indicating the “desirability of setting sulfur dioxide 

standards that would allow the use of low-sulfur fuels as well 

as fuel cleaning, stack-gas cleaning, and equipment 

modifications” (emphasis added)). 

615 40 C.F.R. §CFR 60.49b(n)(4); see also Amendments to New 

Source Performance Standards (NSPS) for Electric Utility Steam 

Generating Units and Industrial-Commercial-Institutional Steam 

Generating Units; Final Rule, 72 Fed. Reg.FR 32742 (June 13, 

2007). 
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block 2 and 3 measures is in keepingconsistent with how Congress 

structured related provisionsthe overall structure of the CAA, 

particularly as it was amended in the 1970 CAA Amendments, when 

Congress added CAA section 111 in much the same form that it 

reads today. 

 In the 1970 CAA Amendments, for the most part, and 

particularly for stationary source provisions, Congress painted 

with broad brush strokes, giving broad authority to the EPA or 

the states. That is, Congress established general requirements 

that were intended to produce stringent results, but gave the 

EPA or the states great discretion in fashioning the types of 

measures to achieve those results. 

For example, under CAA section 109, Congress authorized the 

EPA to promulgate national ambient air quality standards (NAAQS) 

for air pollutants, and Congress established general criteria 

and procedural requirements, but left to the EPA discretion to 

identify the air pollutants and select the standards. Under CAA 

section 110, Congress required the states to submit to the EPA 

state implementation plans (SIPs), required that the plans 

attain the NAAQS by a date certain, and established procedural 

requirements, but allowed the states broad discretion in 

determining the substantive requirements of the SIPs. 
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Under CAA section 111(b), Congress directed the EPA to list 

source categories that endanger public health or welfare, and 

established procedural requirements, but did not include other 

substantive requirements, and instead, gave the EPA broad 

discretion to determine the criteria for endangerment. 

Under CAA section 112, Congress required the EPA to 

regulate certain air pollutants and to set “emission standards” 

that meet general criteria, and established procedural 

requirements, but did not include other substantive requirements 

and, instead, gave the EPA broad discretion in identifying the 

types of pollutants and in determining the standards.616 By and 

 

616 By comparison, under the 1990 CAA Amendments, Congress 

substantially transformed CAA section 112 to be significantly 

more prescriptive in directing EPA rulemaking, which reflected 

Congress’s increased knowledge of hazardous air pollutants and 

impatience with the EPA’s progress in regulating. 
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large, Congress left these provisions intact in the 1977 CAA 

Amendments.617,618

Congress drafted the CAA section 111(d) requirements in the 

1970 CAA Amendments, and revised them in the 1977 CAA 

Amendments, in a manner that is similar to the other stationary 

source requirements, just described, in CAA sections 109, 110, 

111(b), and 112. The CAA section 111(d) requirements are broadly 

phrased, include procedural requirements, but no more than very 

general substantive requirements, and give broad discretion to 

the EPA to determine the basis for the required emission limits 

and to the states to set the standards. It should be noted that 

this drafting approach is not unique to the CAA; on the 

contrary, as U.S. Supreme Court Associate Justice Kennedy has 

 

617 In the 1977 CAA Amendments, Congress applied the same broad 

drafting approach to the stratospheric ozone provisions it 

adopted in CAA sections 150-159. There, Congress authorized the 

EPA to determine whether, “in the Administrator’s judgment, any 

substance, practice, process, or activity may reasonably be 

anticipated to affect the stratosphere, especially ozone in the 

stratosphere, and such effect may reasonably be anticipated to 

endanger public health or welfare,” and then directed the EPA, 

if it made such a determination, to “promulgate regulations 

respecting the control of such process practice, process, or 

activity....” CAA section 157(a). This provision does not further 

specify requirements for the regulations. 

618 On the other hand, in those instances in which Congress had a 

clear idea as to the emission limitations that it thought should 

be imposed, it mandated those emission limits, e.g., in Title II 

concerning motor vehicles. 
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noted: Congress "usually does not legislate by specifying 

examples, but by identifying broad and general principles that 

must be applied to particular factual instances."619

In light of this statutory framework, it is clear that 

Congress delegated to the EPA the authority to administer CAA 

section 111, including by authorizing the EPA to apply the 

“broad and general principles” contained in CAA section 

111(a)(1) to the particular circumstances we face today. 

(3) Comments and responses. Some 

While some commenters support the EPA’s interpretation of 

section 111 to authorize the inclusion of building blocks 2 and 

3 in the BSER, other commenters assert that the emission 

standards must be based on measures that the sources subject to 

CAA section 111 ––- in this rule, the affected EGUs -- apply to 

their own design or operations, and, as a result, in this rule, 

cannot include measures implemented at entities other than the 

affected EGUs that have the effect of reducing generation, and 

therefore emissions, from the affected EGUs. The commenters 

assert that various provisions in CAA section 111 make this 

limitation clear. We do not find those arguments persuasive. 

 

619 Pub. Citizen v. U.S. Dept. of Justice, 491 U.S. 440, 475 

(1989) (Kennedy, J., concurring). 
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First, some commenters state that under CAA section 

111,(d)(1) and (a)(1), the existing sources subject to the 

standards of performance must be able to achieve their emission 

limit, but that they are able to do so only through measures 

integrated into the source’s own design and operation. As a 

result, according to these commenters, those are the only types 

of measures that may qualify as a “system of emission reduction” 

that may form the basis of the emissions standards. We disagree. 

We see nothing in CAA section 111(d)(1) or (a)(1) which by 

theirits terms limitlimits CAA section 111 to measures that must 

be integrated into the sources’ own design or operation. Rather, 

we recognize that in order for an emission limitation based on 

the BSER to be “achievable,” the BSER must consist of measures 

that can be undertaken by an affected source -- that is, its 

owner or operator. As noted elsewhere in the preamble, the 

affected sources subject to this rule are fully able to meet 

their emission standards by undertaking the measures described 

in all three building blocks 2 and 3. Moreover, as discussed, 

the measures in building blocks 2 and 3 are highly effective in 

achieving CO2 emission reductions from these affected EGUs, given 

the unique characteristics of the industry. This reinforces the 

conclusion that the term “system of emission reduction” is broad 

enough to include these measures. 
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The broad nature of CAA section 111(d)(1) and (a)(1) is 

also confirmed by comparing it to CAA provisions that explicitly 

require controls on the design or operations of the affected 

sources. An example includes the requirement under CAA section 

407(b)(2) that the EPA base thean affected source. The most 

notable comparison is at CAA section 111(a)(7). The term 

“technological system of continuous emission reduction,” which 

was added in 1977 and remains as a separately defined term 

means, in part, “a technological process for production or 

operation by any source which is inherently low-emitting or 

nonpolluting.” (Emphasis added.) With respect to this portion of 

the definition (and ignoring the additional text, which includes 

“precombustion cleaning or treatment of fuels” and clearly 

encompasses off-site activities), it could be argued that 

between 1977 and 1990 new source performance standards should be 

restricted to measures that could be integrated into the design 

or operation of a source. However, commenters’ assertion that 

the BSER must be limited in a similar fashion ignores the 

deliberate change in 1990 to restore the broader definition of a 

standard of performance (i.e., that it be based on the BSER and 

not the TSCER). In any case, the narrower scope of CAA section 

111(a)(7) was never applicable to the regulation of existing 

sources under CAA section 111(d). 
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Several other examples of standard setting in the CAA shed 

light on ways in which Congress has constrained the EPA’s 

review. CAA section 407(b)(2) provides that the EPA base NOx

emission limits for certain types of boilers “on the degree of 

reduction achievable through the retrofit application of the 

best system of continuous emission reduction” and further 

requires the EPA to revise previously promulgated emission 

limits for certain types of boilers “to be more stringent if the 

[EPA] determines that more effective low NOx burner technology is 

available.” (Emphasis added.) Likewise, in determining best 

available retrofit technology under CAA section 169A, the state 

(or Administrator) must “take into consideration the costs of 

compliance, the energy and nonair quality environmental impacts, 

any existing pollution control technology in use at the source, 

the remaining useful life of the source, and the degree of 

improvement in visibility which may reasonably be anticipated to 

result from the use of such technology.”620 (Emphasis added.) 

These provisions.” (Emphasis added.) These narrower 

specifications for the basis of these Title IV emissions limits 

 

620 Even under BART, the EPA is authorized to allow emissions 

trading between sources. See, e.g., 40 CFR 51.308(e)(1) & (2); 

Util. Air Reg. Group v. EPA, 471 F.3d 1333 (D.C. Cir. 2006); 

Ctr. for Econ. Dev. v. EPA, 398 F.3d 653 (D.C. Cir. 2005); and 

Cent. Ariz. Water Dist. v. EPA, 990 F.2d 1531 (9th Cir. 1993). 
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-- which were added in the 1990 CAA Amendments, at the same time 

that Congress revised the provisions of CAA section 111(a)(1) 

establishing the basis for controls under CAA section 111(d)(1) 

-- make clear that Congress knew how to constrain the basis for 

emission limits to measures that are integrated into the design 

or operation of the affected source, and that its choice to base 

CAA section 111(d)(1) and (a)(1) standards of performance on a 

“system of emission reduction” indicates Congress’ intent to 

authorize a broader basis for those standards. 

CommentersSome commenters also argue that other provisions 

in CAA section 111 indicate that Congress intended that CAA 

section 111(d)(1) and (a)(1) be limited to measures that are 

integrated into the source’s design or operations. These 

comments areThis argument is unpersuasive for several reasons. 

First, it would be unreasonable to presume that Congress 

intended to limit the BSER, indirectly through these other 

provisions, to measures that are integrated into the affected 

source’s design or operations, when Congress could have done so 

expressly, as it did for the above-discussed Title IVCAA section 

407(b)(2) NOx requirements. Third 

Second, the interpretations that commenters offer for these 

various provisions are not persuasive. Undermisapply the text. 

For example, commenters note that under CAA section 111(d)(1), 
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(a)(3), and (a)(6), the standards of performance apply to “any 

existing source,” and an “existing source” is defined to include 

“any stationary source,” which, in turn, is defined as “any 

building, structure, facility, or installation which emits or 

may emit any air pollutant.” Commenters assert that these 

applicability and definitional provisions indicate that the BSER 

provisions in CAA section 111(d)(1) and (a)(1) must be 

interpreted to require that the control measures must be 

integrated into the design or operations of the source itself. 

We disagree. These applicability and definitional 

provisions are jurisdictional in nature. Their purpose is simply 

to identify the types of sources whose emissions are to be 

addressed under CAA section 111(d), which isi.e., stationary 

sources, as opposed to other types of sources (such as, e.g.,

mobile sources), the, whose emissions from which are addressed 

under other CAA provisions (such as CAA Title II).621 This 

 

621 This purpose is made apparent by the terms of CAA section 

111(a)(3), which contains two sentences. The first sentence 

provides, “The term ‘stationary source’ mans any building, 

structure, facility, or installation which emits or may emit any 

air pollutant.” The second sentence provides: Nothing in 

subchapter II of this chapter relating to nonroad engines shall 

be construed to apply to stationary internal combustion 

engines.” This second sentence makes clear that stationary 

internal combustion engines are to be regulated under section 

111, and not Title II (relating to mobile sources), which 

confirms that the purpose of the definition of stationary source 
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purpose is made apparent by the terms of CAA section 111(a)(3), 

which contains two sentences (the second of which commenters 

seem to ignore). The first sentence provides: “The term 

‘stationary source’ means any building, structure, facility, or 

installation which emits or may emit any air pollutant.” The 

second sentence provides: “Nothing in subchapter II of this 

chapter relating to nonroad engines shall be construed to apply 

to stationary internal combustion engines.” This second sentence 

explains that stationary internal combustion engines are to be 

regulated under CAA section 111, and not Title II (relating to 

mobile sources), which confirms that the purpose of the 

definition of stationary source is jurisdictional in nature -- 

to identify the emissions that are to be regulated under section 

111, as opposed to other CAA provisions. 

These applicability and definitional provisions say nothing 

about the system of emission reduction ––- whether it is limited 

to measures integrated into the design or operation of the 

source itself or may be broader -- that may form the basis of 

the standards for those emissions that are to be promulgated 

under CAA section 111. 

 

is jurisdictional in nature -- to identify the emissions that 

are to be regulated under section 111, as opposed to other CAA 

provisions. 
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In additionThird, this argument by commenters does not 

account for the commonsense proposition that it is the 

owner/operator of the stationary source, not the source itself, 

who is responsible for taking actions to achieve the emission 

rate, so that actions that the owner/operator areis able to take 

should be considered in determining the appropriate standards 

for the source’s emissions. Again, it is common sense that 

buildings, structures, facilities, and installations can take no 

actions -- only owners and operators can install and maintain 

pollution control equipment; only owners and operators can 

solicit precombustion cleaning or treatment of fuel services; 

and only owners and operators can apply for a permit or trade 

allowances.622 Other provisions in CAA section 111 make clear the 

role of the owner/operator. CAA section 111(e) provides that for 

new sources, the burden of compliance falls on the “owner or 

operator.”623 The same is necessarily true for existing sources. 

This supports the EPA’s view that the basis for whether a 

 

622 Industry commenters also acknowledged that it is the owner or 

operator that implements the control requirements. See UARG 

comment at 19 (section 111(d) “provides for the regulation of 

individual emission sources through performance standards that 

are based on what design or process changes an individual 

source’s owner can integrate into its facility”). 

623 CAA section 111(e) provides: (“[I]t shall be unlawful for any 

owner or operator of any new source to operate such source in 

violation of any [applicable] standard of performance.”) 
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control measure qualifies as a “system of emission reduction” 

under CAA section 111(d)(1) and (a)(1) is whether it is 

something that the owner/operator can implement in order to 

achieve the emissions standard assigned to the source ––- if so, 

the control measure should qualify as a “system of emission 

reduction” ––- and not whether the control measure is integrated 

into the source’s own design or operation. 

Commenters also argue that CAA section 111(h), which 

authorizes “design, equipment, work practice or operational 

standard[s]” (together, “design standards”) only when a source’s 

emissions are not emitted through a conveyance or cannot be 

measured, makes clear that CAA section 111 standards of 

performance must be based on measures integrated into a source’s 

own design or operations. We disagree. CAA section 111(h) 

concerns the relatively rare situation in which an 

emissionsemission standard, which entails a numerical limit on 

emissions, is not appropriate because emissions cannot be 

measured, due either to the nature of the pollutant (i.e., the 

pollutant is not emitted through a conveyance) or the nature of 

the source category (i.e., the source category is not able to 

conduct measurements). CAA section 111(h) provides that a in 

such cases, the EPA may instead impose design standards rather 

than establish an emission standard is appropriate under those 
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Page 697 of 2153

circumstances, but only under those circumstances.(i.e., the EPA 

can require sources to implement a particular design, equipment, 

work practice, or operational standard). When an emissions 

standard is appropriate, includingas in the present rule, CAA 

section 111(h) is silent on which system of emissions reduction 

–as to what types of measures –- whether limited to a source’s 

own design or operations -- may formbe considered as the 

basissystem of the emissions standard.emission reduction.624 In 

any event, CAA section 111(h) applies only to standards 

promulgated by the Administrator, and therefore appears by its 

terms to be limited to CAA section 111(b) rulemakings for new, 

modified, or reconstructed sources, not CAA section 111(d) 

rulemakings for existing sources. 

Some commenters identify other provisions of CAA section 

111 that, in their view, prove that CAA section 111 is limited 

to control measures that are integrated within the design or 

operations of the source. We do not find those arguments 

persuasive, for the reasons discussed in the supporting 

documents for this rule. 

 

624 For this same reason, the fact that CAA section 111(h) 

authorizes the EPA to impose certain types of standards –- such 

as, among others, work practice or operational standards -- only 

in limited circumstances not present in this rulemaking, does 

not mean that the EPA cannot consider those same measures as the 

BSER in promulgating a standard of performance. 
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Commenters also argue, more generally, that Congress knew 

how to authorize control measures such as renewable energy, as 

indicated by Congress’s inclusion of those measures in Title IV 

(relating to acid rain), so that the fact that Congress did not 

explicitly include these measures in the BSER provisions of CAA 

section 111(d)(1) and (a)(1) indicates that Congress did not 

intend that they be included as part of the BSER, and instead 

intended that the BSER be limited to measures integrated into 

the sources’ design or operations. This argument misses the 

mark. The provisions of CAA section 111(d)(1) and (a)(1) do not 

explicitly include any specific controlemission reduction

measures ––- neither renewable energy measures (like the ones 

Congress expressly included inwanted to incentivize under Title 

IV), nor measures that are integrated into the sources’ design 

or operations (like the NOxretrofit control measures Congress 

also included in Title IV).required under CAA section 407(b)).

But this contrast with other CAA provisions does not mean that 

Congress did not intend the BSER to include any of those types 

of measures. Rather, this contrast supports viewing a “system of 

emission reduction” under CAA section 111(d)(1) and (a)(1) as a 

big toolbox that affords the EPA a sufficiently broad to 

encompass a wide range of measures to choosefor the purpose of 
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emission reduction of a wide range of pollutants from in 

determining the BSERa wide range of stationary sources.625

c. Chevron step 2 deferenceDeference to interpret the BSER to 

include the building blocks. Under 2 and 3. To the familiar 

Chevron step 2 analysis, if the plain meaning of the BSER 

provision under CAA section (a)(1) (and as applied under CAA 

section 111(d)(1)) does extent that it is not answer the 

question ofclear whether the phrase “system of emission 

reduction” includesmay include the measures in building blocks 2 

and 3, then the EPA’s interpretation that the provision does 

include those building blocks must be given deference as long as 

it is a of CAA section 111(d) and (a) is reasonable construction 

of the statute. In its 2014 decision upholding CSAPR, the U.S. 

Supreme Court re-affirmed Chevron deference for carrying out the 

provisions of the CAA, noting: “We routinely accord dispositive 

effect to an agency’s reasonable interpretation of ambiguous 

 

625 It should also be noted that Title IV is limited to one type 

of source –particular pollutants (i.e., SO2 and NOx) and 

particular sources -– fossil fuel-fired EGUs ––- and as a 

result, lends itself to greater specificity about the types of 

control measures. Section 111(d), in contrast, applies to a wide 

range of source types, which, as discussed above, supports 

reading it to authorize a broad range of control measures. 
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statutory language.”626 Moreover,627 in its 2011 decision holding 

that the CAA displaces the federal common law claim of nuisance, 

the U.S. Supreme Court generally recognized the breadth of CAA 

section 111, noting that “Congress delegated to the EPA the 

decision light of our discretion to determine “whether and how

to regulate carbon-dioxide emissions from power plants....”628 

 Our interpretation that a “system of emission reduction” 

for the affected EGUs may include building blocks 2 and 3 is a 

reasonable construction of the statute for the reasons described 

above and in this section below.

(1) Consistency of building blocks 2 and 3 with the 

structure of the utility power sector. 

(a) Integration of the utility power system. sector. 

Certain characteristics of the utility power sector are of 

central importance for understanding why the measures of 

building blocks 2 and 3 qualify as part of the system of 

emission reduction. As discussed in detail above, electricity is 

fungiblehighly substitutable and the utility power sector is 

 

626 EPA v. EME Homer City, 134 S. Ct. 1584, 1603 (2014). 627 EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584, 1603 

(2014) (“We routinely accord dispositive effect to an agency’s 

reasonable interpretation of ambiguous statutory language.”). 

628 American Electric Power Co. v. Connecticut, 131 S. Ct. 2527, 

2538 (2011) (“AEP”).”) (emphasis added).
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highly integrated, so much so that it has been likened to a 

big“complex machine..”629 Specifically, the utility power sector 

is characterized by a physical interconnection, as well as 

operational, interconnections between electricity generators 

themselves, and between those generators and electricity users. 

Because of the physical properties of electricity and the 

unavailabilitycurrent low availability of large scale 

electricity storage, generation and load (or use) must be 

instantaneously balanced in real time. As a result, the utility 

power sector is uniquely characterized by extensive planning and 

highly coordinated operation. These features have been present 

for decades, and in fact, over time, the sector has become more 

highly integrated. Another important characteristics of the 

utility power sector is that although the states have developed 

both regulated and de-regulated markets, the generation of 

electricity reflects a least-cost dispatch approach, under which 

electricity is generated first by the generators with the lowest 

variable cost. 

These characteristics of the sector have facilitated the 

overall objective of providing reliable electric service at 

 

629 S. Massoud Amin, “Securing the Electricity Grid,” The Bridge, 

Spring 2010, at 13, 14; Phillip F. Schewe, The Grid: A Journey 

Through the Heart of Our Electrified World 1 (2007). 
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least cost subject to a variety of constraints, including 

environmental constraints. Moreover, in each type of market, the 

sector has developed mechanisms, including the participation of 

institutional actors, to safeguard reliability and to assure 

least cost service. 

Congress,630 the Courts,631 the EPA in its regulatory 

actions,632 and states in their regulatory actions633 have 

recognized the integrated nature of the utility power sector. 

(b) Significance of integrated utility power sector for the 

BSER. 

The fungibility of electricity, coupled with the 

integration of the utility power sector, means that, assuming 

 

630 See CAA section 404(f)(2)(B)(iii)(I) (conditioning a 

utility’s eligibility for certain allowances on implementing an 

energy conservation and electric power plan that evaluates a 

range of resources to meet expected future demand at least 

cost); see also SenS. Rep. No. 101-228, pp.at 319-20 (Dec. 20, 

1989)(recognizing that “utilities already engage in powerpooling arrangements to ensure maximum flexibility and 

efficiency in supplying power” to support the establishment of 

an allowance system under titleTitle IV). 631 New York v. Federal Energy Regulatory Commission, 535 U.S. 1, 

at 7 (2002) (citing Brief for Respondent FERC 4-5). 

632 “Stack Heights Emissions Balancing Policy,” 53 Fed. Reg.FR

480, 482 (Jan. 7, 1988). 

633 See 79 FR 34830, 34880 (June 18, 2014) (discussing State of 

California Global Warming Solutions Act of 2006, Assembly Bill 

32, http://www.leginfo.ca.gov/pub/05-06/bill/asm/ab_0001-

0050/ab_32_bill_20060927_chaptered.pdf, and quoting December 27, 

2013 Letter from Mary D. Nichols, Chairman of California Air 

Resources Board, to EPA Administrator Gina McCarthy). 
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that demand is held constant, adding electricity to the grid 

from one generator will result in the instantaneous reduction in 

generation from other generators. Similarly, reductions in 

generation from one generator leadslead to the instantaneous 

increase in generation from other generators. Thus, the 

operation of individual EGUs is integrated and coordinated with 

the operations of other EGUs and other sources of generation, as 

well as with electricity users. This allows for locational 

flexibility across the sector in meeting demand for electricity 

services. The institutions that coordinate planning and 

operations routinely use this flexibility to economically meet 

demand for electricity services economically while satisfying 

constraints, including environmental constraints. Because of 

these characteristics, EGU owner/operators have long conducted 

their business, including entering into commercial arrangements 

with third parties, based on the premise that the performance 

and operations of any of their facilities is substantially 

dependent on the performance and operation of other facilities, 

including ones they neither own nor operate. For example, when 

an EGU goes off-line to perform maintenance, its customer base 

is served by other EGUs that increase their generation. 

Similarly, if an EGU needs to assure that it can meet its 

obligations to supply a certain amount of generation, it may 
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Page 704 of 2153

enter into arrangements to purchase that generation, if it needs 

to, from other EGUs. 

Because of this structure, fossil fuel-fired EGUs can 

reduce their emissions by taking the actions in building blocks 

2 and 3. Specifically, fossil fuel-fired EGUs may generate or 

cause the generation of increased amounts of lower- or zeroemitting electricity ––- through contractual arrangements, 

investment, or purchase -- which will back out higher-emitting 

generation, and thereby lower emissions. In addition, fossil 

fuel-fired EGUs may reduce their generation, which, given the 

overall emission limits this rule requires, will have the effect 

of stimulating lower- or zero-emitting generation. 

It should also be noted that CO2 is particularly well-suited 

for building blocks 2 and 3 because it is a global, not local, 

air pollutant, so that the location where it is emitted does not 

affect its environmental impact. The U.S. Supreme Court in the 

UARG case highlighted the importance of taking account of the 

unique characteristics of CO2.634

In light of these characteristics of the utility power 

sector, as well as the characteristics of CO2 pollution, it is 

reasonable for the EPA to reject an interpretation of the term 

 

634 See UARGUtil. Air. Reg. Group v. EPA, 134 S. Ct. 2427, 2441 

(2014). 
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“system of emission reduction” that would exclude building 

blocks 2 and 3 from consideration in this rule and instead 

restrict consideration to measures integrated into each 

individual affected source’s design or operation, especially 

since the record and other publicly available information makes 

clear that the measures in the two building blocks are effective 

in reducing emissions and are already widely used. 

As discussed above, no such restriction on the measures 

that can be considered part of a “system of emission reduction” 

is required by the statutory language, and the legislative 

history demonstrates that Congress intended an interpretation of 

the phrase broad enough to encompass building blocks 2 and 3. 

The narrow interpretation advocated by some commenters would 

permit consideration only of potential CO2 reduction measures 

that are either more expensive than building blocks 2 and 3 

(such as the use of natural gas co-firing at affected EGUs or 

the application of CCS technology) or measures capable of 

achieving far less reduction in CO2 emissions (such as the heat 

rate improvement measures included in building block 1). 

Imposing such a restrictive interpretation –- one which is not 

called for by the statute -- would be inconsistent with CAA 

section 111’s specific requirement that standards be based on 

the “best” system of emission reduction and, as discussed below, 
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Page 706 of 2153

would be inconsistent with Congressional design that the CAA be 

comprehensive and address the major environmental issues.635 

The unique characteristics of the sector described above 

require coordinated action in the fundamental, primary function 

of EGUs – and in meeting current pollution control requirements 

to the extent that EGUs operate in dispatch systems that apply 

variable costs in determining dispatch -- and affected EGUs 

necessarily already plan and operate on a multi-unit basis. In 

doing so, they already make use of building blocks 2 and 3 to 

meet operational and environmental objectives in a costeffective manner, as further described below. CO2 is a global 

pollutant that is exceptionally well-suited to emission 

reduction efforts optimized on a broad geographic scale rather 

than on a unit-by-unit basis. It is also clear from both 

comments and communications received through the Agency’s 

outreach efforts that affected EGUs will seek to use building 

blocks 2 and 3 to achieve compliance with the emission standards 

set in the section 111(d) plans following promulgation of this 

rule. For these reasons –- and the additional reasons discussed 

below -- interpreting “system of emission reduction” so as to 

 

635 See King v. Burwell, No. 14-114 (2015) (slip op., at 21) 

(“But in every case we must respect the role of the Legislature, 

and take care not to undo what it has done.”). 
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allow consideration in this rule of only the individual pieces 

of the “complex machine,” and to forbid consideration of the 

ways in which the pieces actually fit and work together as parts 

of that machine, such as building blocks 2 and 3, cannot be 

justified. This is particularly so in light of the dilemma 

presented by the types of control options that commenters argue 

are the only ones authorized under section 111(a)(1), which are 

controls that apply to the design or operation of the affected 

EGUs themselves. On the one hand, the control measures in 

building block 1 yield only a small amount of emission 

reductions. On the other hand, control measures such as carbon 

capture and storage, or co-firing with natural gas, could yield 

much greater emission reductions, but are substantially more 

expensive than building blocks 2 and 3. 

(2) Current implementation of measures in building blocks 2 

and 3. 

The requirement that the “system of emission reduction” be 

“adequately demonstrated” suggests that we begin our review 

under CAA section 111(d)(1) and (a)(1) with the systems that 

sources are already implementing to reduce their emissions. As 

noted above, fossil fuel-fired EGUs have long implemented, and 

are continuing to implement, the measures in building blocks 2 

and 3 for various purposes, including for the purpose of 
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Page 708 of 2153

reducing CO2 emissions.636637 –- and certainly always with the 

effect of reducing emissions. This is a strong indicator that 

these measures should be considered part of a “system of 

emission reduction” for CO2 emissions from these sources. The 

requirement that the “system of emission reduction” be 

“adequately demonstrated” indicates that the implementation of 

control mechanisms or other actions that the sources are already 

taking to reduce their emissions are of particular relevance in 

establishing the emission reduction requirements of CAA section 

111(d)(1) and (a)(1). As a result, such measures are a logical 

 

636 A number of utilities have climate mitigation plans. Examples 

include National Grid, 

http://www2.nationalgrid.com/responsibility/how-were-doing/griddata-centre/climate-change/; Exelon, 

http://www.exeloncorp.com/newsroom/pr_20140423_EXC_Exelon2020.as

px; PG&E, http://www.pge.com/about/environment/pge/climate/; and 

Austin Energy, 

http://austinenergy.com/wps/portal/ae/about/environment/austinclimate-protectionplan/!ut/p/a0/04_Sj9CPykssy0xPLMnMz0vMAfGjzOINjCyMPJwNjDzdzY0sDB

zdnZ28TcP8DAMMDPQLsh0VAU4fG7s!/. 

637 A number of utilities have climate mitigation plans. Examples 

include National Grid, 

http://www2.nationalgrid.com/responsibility/how-were-doing/griddata-centre/climate-change/; Exelon, 

http://www.exeloncorp.com/newsroom/pr_20140423_EXC_Exelon2020.as

px; PG&E, http://www.pge.com/about/environment/pge/climate/; and 

Austin Energy, 

http://austinenergy.com/wps/portal/ae/about/environment/austinclimate-protectionplan/!ut/p/a0/04_Sj9CPykssy0xPLMnMz0vMAfGjzOINjCyMPJwNjDzdzY0sDB

zdnZ28TcP8DAMMDPQLsh0VAU4fG7s!/. 
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starting point for consideration as a “system of emission 

reduction” under CAA section 111. 

(3) Reliance in CAA Title IV on building block measures. 

Some of the building block 2 and 3 approaches to reducing 

emissions in the utility power sector were also well recognized 

atfirst tested around the time that Congress adopted the 1970 

CAA Amendments.638 Over time, these techniques have become more 

established within the industry, and by the 1990 CAA Amendments, 

Congress expressly based the Title IV acid rain controlsprogram

for existing fossil fuel-fired EGUs in part on the same measures 

that are in those building blocks. This provides an important 

indication that Congress not only viewed such measures as 

effective emission control techniques but that these same 

measures were already in use by the industryconsidered here. 

(a) Overview. 

It is logical that in determining whether the “system of 

emission reduction” that Congress established in CAA section 

111(d)(1) and (a)(1) is broad enough to include the measures in 

building blocks 2 and 3 as the basis for establishing emission 

guidelines for fossil fuel-fired EGUs, an inquiry should be made 

 

638 See, e.g., Shepard, Donald S., A Load Shifting Model for Air 

Pollution Control in the Electric Power Industry, Journal of the 

Air Pollution Control Association, Vol. 20:11, pp. 756-761 

(November 1970). 
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into the tools that Congress relied on in other CAA provisions 

to reduce emissions from those same sources. The most useful CAA 

provision to examine for this purpose is Title IV, which 

includes a nationwide cap-and-trade program under which coalfired power plants must have allowances for their sulfur dioxide 

emissions. 

Title IV includes several signals that it is especially 

relevant for interpreting and implementing CAA section 111(d) 

for purposes of this rule. Title IV applies to most of the same 

sources that this rule applies to -- existing coal-fired EGUs 

and other utility boilers, as well as NGCC units. In addition, 

Congress added Title IV in the 1990 CAA Amendments at the same 

time that Congress largely reinstated the 1970-vintage reading 

of section 111(a)(1) to adopt the currently applicable 

definition of a “standard of performance,” which is based on the 

“best system of emission reduction ... adequately demonstrated.” 

Moreover, Congress linked Title IV and CAA section 111 in 

certain respects. Specifically, Congress conditioned the 

revisions to CAA section 111(a)(1), i.e., eliminating the 

percentage reduction and most of the other limitations under the 

1977 CAA Amendments, on the continued applicability of the Title 

IV SO2 cap, so that if the cap were eliminated, the changes 

would, by operation of law, also be eliminated, and the 1977 
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version of section 111(a)(1) would be reinstated.639

Additionally, Congress authorized the EPA to establish standards 

of performance for new and existing industrial (non-EGU) sources 

of SO2 emissions if emissions from these sources might exceed 

1985 levels and failed to decline at the expected rate.640 While 

industrial sources were not required to participate under Title 

IV —-- they could elect to do so, under CAA section 410(a) —--

Congress believed SO2 reductions from these sources were “an 

essential component of the reductions sought under [Title IV]” 

and intended that Title IV would “assure[] that these projected 

reductions occur and will not be overcome by future growth in 

emissions.”641 As such, Congress viewed federal standards of 

 

639 1990 CAA Amendments, § 403, 104 Stat. at 2631 (requiring

repeal of amendments to CAA section 111(a)(1) upon any cessation 

of effectiveness of CAA section 403(e), which requires new units 

to hold allowances for each ton of sulfur dioxide emitted). 

Congress believed that mandating a technological standard 

through the percentage reduction requirement in Sectionsection

111(a)(1) would ensure the continued availability of low sulfur 

coal for existing sources. In other words, the percentage 

reduction requirement discouraged compliance with new source 

performance standards based solely on fuel shifting because it 

was much more costly to achieve the percentage reduction with 

lower sulfur coal. This belief was expressed during the 1977 CAA 

Amendments and is discussed above as part of the legislative 

history of Sectionsection 111. 640 1990 CAA Amendments, § 406, 104 Stat. at 2632-33; see also

SenS. Rep. No. 101-228, at 282 (industrial source emissions 

totaled 5.6 million tons of SO2 in 1985). 641 SenS. Rep. No. 101-228, at 345 (Dec. 20, 1989). 
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performance as the appropriate backstop to Title IV even for 

sources that could not otherwise be regulated under CAA section 

111(d).642 Together, these signals suggest that it is reasonable 

for the EPA to consider Title IV when interpreting and 

implementing CAA section 111. 

For present purposes, the essential features of Title IV 

are that it regulates sulfur dioxideSO2 emissions from coal-fired 

EGUs by adopting a nationwide cap of 8.9095 million tons to be 

achieved through a tradable allowance system. As we explain 

below, the provisions of Title IV and its legislative history 

make clear that Congress based the stringency of the emission 

limitation requirement (8.9095 million tons) and the overall 

structure of the approach (a cap-and-trade system) on Congress’s 

recognition that the affected EGUs had a set of tools available 

to them to reduce their emissions, including through a shift to 

lower emitting generation and use of renewable energy, along 

with add-on controls and other measures. Thus, Title IV provides 

a close analogy to CAA section 111: generation shift and 

renewable energy were part of Congress’s basis for the Title IV 

emissions requirements, and that is analogous to building blocks 

 

642 To reiterate, ordinarily, standards of performance cannot be 

used to regulate SO2 emissions from existing sources because of 

the pollutant exclusions in CAA section 111(d). 
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2 and 3 serving as part of the “system of emission reduction” 

that is the EPA’s basis for the section 111(d) emission 

guidelines. For this reason, the fact that in Title IV, Congress 

relied on generation shift and renewable energy as the basis for 

the SO2 emission limitations for affected EGUs strongly supports 

interpreting CAA section 111(d)(1) and (a)(1) to include use of 

those same measures as part of the “system of emission 

reduction” as the basis for CO2 emission limitations for those 

same sources. 

(b) Title IV provisions. 

Several provisions of Title IV make explicit Congress’s 

reliance on some of the same measures as are in building blocks 

2 and 3. Title IV begins with a statement of congressional 

“findings,” including the following: 

§401(a). Findings 

The Congress finds that – 

* * * * 

(4) strategies and technologies for the control of 

precursors to acid deposition exist now that are 

economically feasible, and improved methods are 

expected to become increasingly available over the 

next decade. 

(Emphasis added.) Title IV then includes the following statement 

of its “purposes:” 

§401(b). Purposes 
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The purpose of this subchapter [Title IV] is to reduce 

the adverse effects of acid deposition through 

reductions in annual emissions of sulfur dioxide ... and 

nitrogen oxides.... It is the intent of this subchapter 

to effectuate such reductions by requiring compliance 

by affected EGUs with prescribed emission limitations 

by specified deadlines which limitations may be met 

through alternative methods of compliance provided by 

an emission allocation and transfer system. It is also 

the purpose of this subchapter to encourage energy 

conservation, use of renewable and clean alternative 

technologies, and pollution prevention as a long-range 

strategy, consistent with the provisions of this 

subchapter, for reducing air pollution and other 

adverse impacts of energy production and use. 

(Emphasis added). By its terms, this statement of Title IV’s 

purposes explicitly embraces the use of renewable energy. 

Moreover, the legislative history makes clear that the reference 

in the “findings” section quoted above to “strategies and 

technologies” includes generation shift to lower-emitting 

generation. Specifically, the Senate Report stated that an 

“allowance system”643 would encourage such “technologies and 

strategies” as –

energy efficiency; enhanced emissions reduction or 

control technologies—like sorbent injection, cofiring 

with natural gas, integrated gasification combined 

cycles; fuel-switching and least-emissions dispatching

in order to maximize emissions reductions.”644 

 

643 See SenS. Rep. No. 101-228, at 320 (Dec. 20, 1989). 644 See SenS. Rep. No. 101-228, at 316 (Dec. 20, 1989) (emphasis 

added). 
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Congress’s reliance on generation shifting and renewable energy 

to reduce acid rain precursors from affected EGUs in Title IV 

strongly supports the EPA’s authority to identify those same 

measures as part of the CAA section 111 “system of emission 

reduction” to reduce CO2 emissions from those same sources. 

 In addition, Title IV includes other provisions expressly 

concerning renewable energy. In CAA section 404(f) and (g), 

Congress set aside a special pool of allowances to encourage use 

of renewable energy. In order to obtain a special allowance, 

(which would authorize emissions from a coal-fired utility), an 

electric utility needed to pay for qualifying renewable energy 

sources “directly or through purchase from another person.”645

These measures confirm Congress’s recognition that renewable 

energy was available to the industry, was desirable to encourage 

from a policy perspective, and was appropriate to consider in 

determining the amount of pollution reduction the law should 

require. 

(c) Title IV legislative history. 

Numerous statements in the legislative history confirm that 

Congress based the Title IV requirements on the fact that 

affected EGUs could reduce their SO2 emissions through a set of 

 

645 CAA section 404(f)(2)(B)(i). 
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measures, including shifting to lower-emitting generation as 

well as reliance on renewable energy. 

For example, the Senate Committee Report646 and Senator 

Baucus,647 a member of the Senate Committee on Environment and 

Public Works and Chairman of the House and Senate Clean Air 

Conferees, both emphasized that affected EGUs could rely on, 

among other things, “least-emissions dispatching in order to 

maximize emissions reductions.” Similarly, statements supporting 

the renewable energy reserve were included in the legislative 

history on the House side. 

We believe that this provision of the bill will 

establish a balanced and workable approach that will 

provide certainty for utility companies that are 

considering conservation and renewables, while at the 

same time strengthening the environmental goals of 

this legislation.648 

 

646 SenS. Rep. to accompany S. 1630, Sen. Rep.No. 101-228 (Dec. 

20, 1989), 1990 CAA Legis. Hist. at 8656. 647 SenS. Debates on Conf. Rep. to accompany S. 1630, H.R. Rep.

No. 101-952 (Oct. 27, 1990), 1990 CAA Legis. Hist. at 1033-35 

(statement of Senator Baucus, inserting “the Clean Air 

Conference Report” into the record). 

648 H.R. Rep. No. 101-490, pp.at 368-69; 674-76 (May 17, 1990) 

(additional views of of Reps. Markey and Moorhead) (“We believe 

that H.R. 3030, as amended, will create a strong and effective 

incentive for utilities to immediately pursue energy 

conservation and renewable energy sources as key components of 

their acid rain control strategies.”); see also Rep. Collins, H. 

Debates on H.R. Conf. Rep. No. 101-952 (Oct. 26, 1990), 1990 CAA 

Legis. Hist. at 1307 (“The bottom line is that our Nation's 

utilities and production facilities must reach beyond coal, oil, 

and fossil fuels. The focus must shift instead toward 

conservation and renewables such as hydropower, solar thermal, 
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Congress’s reliance, in adopting Title IV, on generation 

shifting and renewable energy as part of the basis for the 

emission standards contrasts with circumstances in which 

emissions standards were established based on add-on controls, 

but other measures – such as renewables – were seen as a 

compliance alternative. Examples of the latter are two of the 

air pollutant transport rules that the EPA promulgated after the 

1990 CAA Amendments: the NOx SIP Call (1998) and the Clean Air 

Interstate Rule (CAIR) (2005). For each of those rules, the EPA 

established the emission standards and requirements in large 

part on the basis of add-on controls, but authorized and 

encouraged the implementation of renewable energy measures as 

compliance measures.649 

(4) Reliance on renewable energy measures to reduce carbon 

dioxide. 

The Title IV legislative history also makes clear that 

Congress viewed renewable energy measures as a means to reduce 

carbon dioxide for the purpose of mitigating climate change. By 

 

photovoltaics, geothermal, and wind. These clean sources and 

energy, available in virtually limitless supply, are the way of 

the future.”). 

649 CAIR: 70 Fed. Reg. 25,162, 25, 165, 25,256, 25, 279 (May 12, 

2005) (allowing use of allowance set-asides for renewables and 

energy efficiency); NOx SIP Call: 63 Fed. Reg. 57,356, 57,362, 

57438 (Oct. 27, 1998) (authorizing SIPs to rely on renewables 

and energy efficiency to meet the state budgets). 
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the time of the 1990 CAA Amendments, Congress had long been 

aware that emissions of carbon dioxide and other greenhouse 

gases put upward pressure on world temperatures and threatened 

to change the climate in destructive ways. In 1967, President 

Lyndon Johnson sent a letter to Congress recognizing that carbon 

dioxide was changing the composition of the atmosphere.650 The 

record for the 1970 CAA Amendments include hearings651 and a 

report by the National Academy of Sciences noting that carbon 

dioxide emissions could heat the atmosphere.652 A 1976 report 

notednoting the phenomenon was included in the record for the 

 

650 “Special Message to the Congress on Conservation and 

Restoration of Natural Beauty (Feb. 8, 1965). 

http://www.presidency.ucsb.edu/ws/?pid=27285 (“This generation 

has altered the composition of the atmosphere on a global scale 

through radioactive materials and a steady increase in carbon 

dioxide from the burning of fossil fuels.”). 

651 Administration Testimony, House Hearing (Mar. Testimony16, 

1970), 1970 CAA Legis. Hist. at 1381 (testimony of Charles 

Johnson, Jr., Administrator of the Consumer Protection and 

Environmental Health Service (Administration Testimony), Hearing 

of the House Subcommittee on Public Health and Welfare (Mar. 16, 

1970), 1970 CAA Legis. Hist. , at 1381 (stating that “the carbon 

dioxide balance might result in the heating up of the atmosphere 

whereas the reduction of the radiant energy through particulate 

matter released to the atmosphere might cause reduction in 

radiation that reaches the earth”). 

652 1970 CAA Legis. Hist. at 244, 257 SenS. Debate on S. 4358 

(Sept. 21, 1970) (statement of Sen. Boggs) (replicating Chapter 

IV of the Council on Environmental Quality’s first annual 

report, which states, “the addition of particulates and carbon 

dioxide in the atmosphere could have dramatic and long-term 

effects on world climate.”).”). 
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1977 CAA Amendments.653 A 1977 Report by the National Academy of 

Sciences warned that average temperatures would rise due to the 

burning of fossil fuel.654 By the time of the 1990 CAA 

Amendments, the dangers had become more clearly evident. Senate 

hearings beginning in 1988 had presented testimony from Dr. 

James E. Hansen of the National Aeronautics and Space 

Administration and other scientists that described the dangers 

of climate change caused by anthropogenic carbon dioxide and 

other greenhouse gas emissions and asserted that as a result of 

those emissions, the climate was in fact already changing.655 

 

653 122 Cong. Rec. S25194 (daily ed. Aug. 3, 1976) (statement of 

Sen. Bumpers) (inserting into the record, “Summary of Statements 

Received from Professional Societies for the Hearings on Effects 

of Chronic Pollution (in the Subcommittee on the Environment and 

the Atmosphere),” which stated, “there is near unanimity that 

carbon dioxide concentrations in the atmosphere are increasing 

rapidly. Though even the direction (warming or cooling) of the 

climate change to be caused by this is unknown, very profound 

changes in the balance of climate factors that determine 

temperature and rainfall on the earth are almost certain within 

100 years”). 

654 National Academy of Sciences, “Energy and Climate: Studies in 

Geophysics” viii (1977).),

http://www.nap.edu/openbook.php?record_id=12024 (noting that a 

fourfold to eightfold increase in carbon dioxide by the latter 

part of the twenty-second century would increase average world 

temperature by more than 6 degrees Celsius). 

655 SenS. Rep. No. 101-228, p.at 322 (Dec. 20, 1989), at 1990 

LegLegis. Hist. at 8662 (“In the last several years, the 

Committee has received extensive scientific testimony that 

increases in the human-caused emissions of carbon dioxide and 

other greenhouse gases will lead to catastrophic shocks in the 

global climate system.”); History, Jurisdiction, and a Summary 
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 In enacting the 1990 CAA Amendments, Congress identified 

reductions in carbon dioxide emissions as an important cobenefit of the reductions in coal use and stressed that the 

renewable energy measures would achieve those reductions. 

Senator Fowler, the author of the provision that established a 

renewable energy technology reserve within the allowance system, 

noted that renewable energy technologies, “can greatly reduce 

emissions of ... global warming gases. That makes them a potent 

weapon against catastrophic climate change....”656 In addition, 

the 1990 CAA Amendments required EGUs covered by the monitoring 

requirements of the Title IV acid rain program to report their 

CO2 emissions.657 

(5) Other EPA actions that rely on the building block 

measures. 

Another indication that it is reasonable to interpret the 

CAA section 111(d)(1) and (a)(1) provisions for the BSER to 

include the measures in building blocks 2 and 3 is that the EPA 

 

of Activities of the Committee on Energy and Natural Resources 

During the 100th Congress, SenS. Rep. No. 101-138, at 5 (Sept. 

1989); “Global Warming Has Begun, Expert Tells Senate,” New York 

Times, June 24, 1988,

http://www.nytimes.com/1988/06/24/us/global-warming-has-begunexpert-tells-senate.html. 

656 Sen. Fowler, SenS. Debate on S. 1630 (Apr. 3, 1990), 1990 CAA 

Legis. Hist. at 7106. 

657 1990 CAA Amendments, § 821, 104 Stat. at 2699. 
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and states have relied on these measures to reduce emissions in 

a number of other CAA actions. 

For example, in 2005, the EPA promulgated a rule to control 

mercury emissions from fossil fuel-fired power plants under 

section 111(d): the Clean Air Mercury Rule (CAMR).658 The EPA 

established a nationwide cap-and-trade program that took effect 

in two phases: In 2010, the cap was set at 38 tons per year, and 

in 2018, the cap was lowered to 15 tons per year. The EPA 

expected, on the basis of modeling, that sources would achieve 

the second phase, 15-ton per year cap cost-effectively by 

choosing among a set of measures that included shifting 

generation to lower-emitting units.659 CAMR was vacated by the 

 

658 70 FR 28606 (May 18, 2005) (“Under the CAMR scenario modeled 

by EPA, units [were] projected to meet their SO2 and NOx

requirements and take additional steps to address the remaining 

[mercury] reduction requirements under CAA section 111, 

including adding [mercury]-specific control technologies (model 

applies [activated carbon injection]), additional scrubbers and 

[selective catalytic reduction], dispatch changes, and coal 

switching.”). 70 FR 28606 (May 18, 2005).

659 70 FR 28606, 28619 (May 18, 2005). 70 FR 28606, 28619 (May 

18, 2005) (“Under the CAMR scenario modeled by EPA, units [were] 

projected to meet their SO2 and NOx requirements and take 

additional steps to address the remaining [mercury] reduction 

requirements under CAA section 111, including adding [mercury]-

specific control technologies (model applies [activated carbon 

injection]), additional scrubbers and [selective catalytic 

reduction], dispatch changes, and coal switching.”).
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D.C. Circuit on other grounds,660 but it provides a 

precedentshows that in the only other section 111(d) rule that 

the EPA attempted for relyingaffected EGUs, the EPA relied on 

shifting generation as part of the BSER in a CAA section 111(d) 

rulemaking for fossil fuel-fired EGUs. 

In 2011, the EPA promulgated the Cross State Air Pollution 

Rule (CSAPR),661 in which it set statewide emission budgets for 

NOx, SO2, and particulate matterSO2 emitted by fossil fuel-fired 

EGUs, and based those standards in part on shifts to lower -

emitting generation. CSAPR established state-wide emissions 

budgets based on a range of cost-effective actions that EGUs 

could take, and set the stringency of the deadlines for some 

required reductions in part because of the availability of 

“increased dispatch of lower-emitting generation which can be 

achieved by 2012.”662 The EPA developed a federal implementation 

plan (FIP) that established a trading program to meet the statewide emission budgets set by CSAPR. The EPA projected that 

sources would meet their emission reduction obligations by 

implementing a range of emission control approaches, including 

 

660 New Jersey v. EPA, 517 F.3d 574, 583-84 (D.C. Cir. 2008),

cert. denied sub nom. Util. Air Reg. Grp.Group v. New Jersey, 

555 U.S. 1169 (2009)). 661 76 Fed. Reg.FR 48208 (Aug. 8, 2011). 662 76 Fed. Reg.FR at 48452. 
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the operation of add-on controls, switches to lower-emitting 

coal, and “changes in dispatch and generation shifting from 

higher emitting units to lower emitting units.”663 The U.S. 

Supreme Court upheld CSAPR in EPA v. EME Homer v. EPACity 

Generation, L.P.664

 With respect to renewable energy, in 2004, the EPA provided 

guidance to states for adopting attainment SIPs under CAA 

section 110 that include renewable energy measures.665 Some 

 

663 76 FR at 48279-80. The exact mix of controls varied for 

different air pollutants and different time periods, but in all 

cases, shifting generation from higher to lower emitting units 

was one of the expected control strategies for the fossil fuelfired power plants. Prior to CSAPR, the EPA promulgated two 

other transport rules, the NOx SIP Call (1998) and the Clean Air 

Interstat1eInterstate Rule (CAIR) (2005). For both of those 

rules, the EPA), which similarly established the emission 

standards based on the basisanalysis of the availability and 

cost of emission reductions achievable through the use of add-on 

controls and the availability of trading, butgeneration 

shifting, and also authorized and encouraged the implementation 

of renewable energy and demand-side energy efficiency measures. 

CAIR: 70 Fed. Reg.FR 25162, 25165, 25256, 25279 (May 12, 2005) 

(allowing use of allowance set-asides for renewables and energy 

efficiency); NOx SIP Call: 63 Fed. Reg.FR 57356, 57362, 57436, 

57438, 57449 (Oct. 27, 1998) (authorizing and encouraging SIPs 

to rely on renewables and energy efficiency to meet the state 

budgets). 

664 134 S. Ct. 1584 (2014). 665See, e.g., Guidance on SIP Credits for Emission Reductions 

from Electric-Sector Energy Efficiency and Renewable Energy 

Measures (Aug. 2004), 

http://www.epa.gov/ttn/oarpg/t1/memoranda/ereseerem_gd.pdf; 

Incorporating Emerging and Voluntary Measures in a State 

Implementation Plan (SIP) (Sept. 2004), 

http://www.epa.gov/ttn/oarpg/t1/memoranda/evm_ievm_g.pdf. 
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states have done so. For example, Connecticut included in its 

SIP reductions from solar photovoltaic installations.666 In 2012, 

the EPA provided additional guidance on this topic.667 In 

addition, the EPA has partnered with the Northeast statesStates

for Coordinated Air Use Management (NESCAUM) and three states 

(Maryland, Massachusetts, and New York) to identify 

opportunities for including renewable energy in a SIP and to 

provide real-world examples and lessons learned through those 

states’ case studies.668

(6) Other rules that relied on actions by other entities. 

The EPA has promulgated numerous actions that establish 

control requirements for affected sources on the basis of 

actions by other entities or actions other than measures 

integrated into the design or operations of the affected 

 

666 CT 1997 8-hour ozone SIP Web site, 

http://www.ct.gov/deep/cwp/view.asp?a=2684&q=385886&depNav_GID=1

619 (see Attainment Demonstration TSD, Chapter 8 at 31, 

http://www.ct.gov/deep/lib/deep/air/

regulations/proposed_and_reports/section_8.pdf). 667 “Roadmap for Incorporating EE/RE Policies and Programs into 

SIPs/TIPs” (July 2012), 

http://epa.gov/airquality/eere/manual.html.

668 States’ Perspectives on EPA’s Roadmap to Incorporate Energy 

Efficiency/Renewable Energy in NAAQS State Implementation Plans: 

Three Case Studies, Final Report to the U.S. Environmental 

Protection Agency (Dec. 2013), 

http://www.nescaum.org/documents/nescaum-final-repttorept-toepa-ee-in-naaqs-sip-roadmap-case-studies-20140522.pdf. 
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sources. This section summarizes some of those actions. First, 

virtually all pollution control requirements require the 

affected sources to depend in one way or another on other 

entities, such as control technology manufacturers. Second, the 

EPA has promulgated numerous regulatory actions that are based 

on emissions trading or averagingof mass-based emission 

allowances or rate-based emission credits, in which many sources 

meet their emission limitation requirements by purchasing 

allowances or emission reduction credits from other sources that 

reduce emissions. 

(a) Third -party transactions. 

To reiterate, commenters’commenters argue that the “system 

of emission reduction” must be limited to measures taken by the 

affected source itself because only those measures are under the 

control of the affected source, as opposed to third parties, and 

therefore only those measures can assure that the affected 

source will achieve its emission limits. But this argument is 

belied by the fact that for a wide range of pollution control 

measures – including many that are indisputably part of a 

“system of emission reduction” – affected sources are in fact 

dependent on third parties. For example, to implement any type 

of add-on pollution control equipment that is available only 

from a third-party manufacturer, the affected source is 
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dependent upon that third party for developing and constructing 

the necessary controls, and for offering them for sale. Indeed, 

the affected sources may be dependent upon third parties to 

install (and in some cases to operate) the controls as well, and 

in fact, in the CAIR rule, the EPA established the compliance 

date based on the limited availability of the specialized 

workforce needed to install the controls needed by the affected 

EGUs.669 In addition, EGU owners and operators may be dependent 

on the actions of third- parties to finance the controls and 

third-party regulators to assure the mechanism for repaying that 

financing. However, this dependence does not mean that the 

emission limit based on that equipment is not achievable. 

Rather, the fact that the owner or operator of the affected 

source can engage in a market transactionarrange with the 

various third parties to acquire, install, and pay for the 

equipment means that emission limit is achievable. 

In this rule, as noted, the affected EGUs may, in many 

cases, implement the measures in building blocks 2 and 3 

directly, and, in other cases, implement those measures by 

engaging in market transactions with third parties that are as 

 

669 70 Fed. Reg.FR 25162, 25216–25225 (May 12, 2005). The EPA 

noted that its view was “based on the NOX SIP Call experience.” 

Id. at 25217. 
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much within the affected EGUs’ control as engaging in market 

transactions with the range of third- parties involved in 

pollution control equipment. By the same token, the market 

transactions that the affected EGUs engage in with third parties 

to implement the measures in building blocks 2 and 3 are 

comparable to the market transactions that affected EGUs engage 

in as part of their normal course of business, which include, 

among many examples, transactions with RTOs/ISOs or balancing 

authorities, entities in organized markets. 

(b) Emissions trading and averaging. . 

Additional precedent that the “system of emission 

reduction” may include the measures in building blocks 2 and 3 

and is not limited to measures that a source can integrate into 

its own design or operations, without being dependent on other 

entities, is found in the many rules that Congress has enacted 

or that the EPA has promulgated that allow EGUs and other 

sources to meet their emission limits by trading with other 

sources. In a trading rule, the EPA authorizes a source to meet 

its emission limit by purchasing mass-based emission allowances 

or rate-based emission reduction credits generated from other 

sources, typically ones that implement controls that reduce 

their emissions to the point where they are able to sell 

allowances or emission reduction credits. As a result, the 
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availability of trading reduces overall costs to the industry by 

focusing the controls on the particular sources that have the 

least cost to implement controls. For present purposes, what is 

relevant is that in a trading program, some affected sources 

choose to meet their emission limits not by implementing 

emission controls onintegrated into their own design or 

operations, but rather by purchasing allowances or emission 

reduction credits. These affected sources, therefore, are 

dependent on the actions of other entities, which are the ones 

that choose to meet their emission limits by implementing 

emission controls, which permits them to sell allowances or 

emission reduction credits.credits. They are dependent, however, 

in the same way that a source acquiring pollution control 

technology for the purposes of meeting a NSPS is dependent on a 

vendor of that technology to fulfill its contractual 

obligations. That is, the source operator purchasing a credit or 

an allowance is acquiring an equity in the technology or action 

applied to the credit-selling source for purposes of achieving a 

reduction in emissions occurring at the selling source. Trading 

programs have been commonplace under the CAA, particularly for 

EGUs, for decades. The rest of this subsection briefly describes 

some of the mainThey include the acid rain trading program in 

Title IV of the CAA, the trading programs, focusing in the 
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transport rules promulgated by the EPA under the “good neighbor 

provision” of CAA section 110(a)(2)(D)(i)(I), the Clean Air 

Mercury Rule, and the regional haze rules. In each of these 

actions, the Congress or the EPA recognized that some of the 

affected EGUs would implement controls or take other actions 

that would lower their emissions and thereby allow them to sell 

allowances to other EGUs, which were dependent on the ones that 

primarily involve EGUs.purchase of those allowances to meet 

their obligations.670 For the reasons just described, these 

trading rules refute commenters’ arguments for limiting the 

scope of the “system of emission reduction.” 

In the 1990 CAA Amendments, Congress enacted the Acid Rain 

Program, as Title IV of the CAA. The Acid Rain Program applied 

 

670 For example, in the enacting the acid rain program under CAA 

Title IV, Congress explicitly recognized that some sources would 

comply by purchasing allowances instead of implementing 

controls. S. Rep. No. 101-228, at 303 (Dec. 20, 1989). 

Similarly, in promulgating the NOx SIP Call in 1998, the EPA 

stated, “Since EPA's determination for the core group of sources 

is based on the adoption of a broad-based trading program, 

average cost-effectiveness serves as an adequate measure across 

sources because sources with high marginal costs will be able to 

take advantage of this program to lower their costs.” 63 FR at 

57399 (emphasis added). By the same token, in promulgating the 

Cross State Air Pollution Rule, the EPA stated, “the preferred 

trading remedy will allow source owners to choose among several 

compliance options to achieve required emission reductions in 

the most cost effective manner, such as installing controls, 

changing fuels, reducing utilization, buying allowances, or any 

combination of these actions.” 76 FR at 48272 (emphasis added). 
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to new and existing electric generating units in two phases. 

Phase II, which started in the year 2000, applies to more than 

2000 fossil fuel-fired EGUs across the continental U.S., and 

imposes an annual cap on SO2 emissions of 8.90 million tons, 

which was designed to achieve overall reductions of ten million 

tons of SO2 emissions or approximately a 50 percent reduction 

from 1980 emission levels. Under the program each affected EGU 

must surrender one allowance for each ton of SO2 that it emits. 

Each affected EGU is allocated a number of allowances for free. 

An affected EGU that implements controls may reduce its 

emissions to the point where it may have more allowances than 

tons of emissions, in which case it can sell the allowances it 

does not need for its own emissions. An affected EGU that does 

not implement controls may not have enough allowances for its 

emissions and may therefore need to buy some. 

In enacting the program, Congress explicitly recognized 

that some sources would comply by purchasing allowances instead 

of implementing controls. Indeed, the purpose of the program was 

to achieve emission reductions by focusing controls on the 

sources for which controls were most cost-effective, and allow 

other sources to avoid implementing controls directly, and 

instead to purchase allowances, which had the effect of 

defraying part of the costs of controls for the sources that did 
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implement controls.671 Prior to the development of the concept of 

trading, legislative efforts to reduce SO2 from fossil fuel-fired 

EGUs had failed because the cost of implementing controls were 

considered too expensive for some of the EGUs. Trading solved 

that problem. 

In addition, in enacting the trading program, Congress 

recognized that the power sector was particularly well-suited to 

implement a trading program because of the highly transactional 

nature of the industry.672

The EPA has promulgated a series of rulemakings that apply 

to EGUs and that are based on the acid rain program. The EPA has 

promulgated several of these rules under CAA section 

110(a)(2)(D)(i)(I), the “good neighbor provision,” which 

requires an upwind state to include in its SIP measures to 

 

671 Sen. Rep. No. 101-228, p. 303 (Dec. 20, 1989). 672 See Sen. Rep. No. 101-228, pp. 319-20 (Dec. 20, 1989) (“In 

the management of the power they produce and deliver, utilities 

already engage in power-pooling arrangements to ensure maximum 

flexibility and efficiency in supplying power. Allowance-pooling 

could easily track power-pooling activities. At the same time, 

utilities have substantial experience in making long-term power 

and capacity sales to other utilities and could to [sic] the 

same with allowances, enabling those with up-front capital costs 

to receive revenues at the time they are incurring their 

expenses. In fact, a utility seeking to obtain allowances in 

lieu of making on-site reductions in order to meet compliance 

could underwrite directly a portion of the control technology or 

other costs incurred by the utility from whom it was to obtain 

the additional allowances.”). 
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reduce emissions from its sources that adversely affect air 

quality in a downwind state. In 1998, the EPA promulgated the 

first of these transport rules, originally called the NOx SIP 

Call, and currently called the NOx Budget Trading Program. This 

rule set NOx emission budgets for certain states, and based each 

state’s budget on the cumulative emissions reductions that could 

be achieved primarily by the fossil fuel-fired EGUs in that 

state by implementing “highly cost-effective controls.” For 

EGUs, the emission rate was 0.15 lb/MMBtu for both oil/gas-fired 

EGUs and coal-fired EGUs. The EPA concluded that while it might 

be less cost-effective for some individual EGUs to meet that 

emission rate through installing on-site controls, those EGUs 

could purchase allowances through a trading program, so that 

overall the emission rate remained highly cost-effective.673 The 

EPA explained -- 

In this rulemaking, EPA has chosen to focus on an 

average cost-effectiveness measure in identifying 

highly cost-effective control options for several 

reasons. Since EPA's determination for the core group 

of sources is based on the adoption of a broad-based 

trading program, average cost-effectiveness serves as 

an adequate measure across sources because sources 

with high marginal costs will be able to take 

advantage of this program to lower their costs.674

 

673 63 Fed. Reg. 57356, 57399, 57413, 57457 (Oct. 27, 1998). 674 63 FR at 57399 (emphasis added). 
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In 2005, the EPA promulgated an expanded and more stringent 

transport rule, the CAIR, which regulated SO2 as well as NOx

emissions from fossil fuel-fired EGUs through a tradable 

allowance system. Similar to the NOx SIP Call, the state budgets 

set by CAIR were based on cost-effective controls on EGUs. The 

EPA’s evaluation of the cost impacts of CAIR assumed that EGUs 

would be participating in an interstate trading program.675 The 

EPA explained that -- 

In modeling the CAIR with the IPM, EPA assumes 

interstate emissions trading. While EPA is not 

requiring states to participate in an interstate 

trading program for EGUs, we believe it is reasonable 

to evaluate control costs assuming states choose to 

participate in such a program since that will result 

in less expensive reductions.676 

In 2011, the EPA promulgated the CSAPR, which regulated 

interstate transport of SO2, NOx, and particulate matter 

emissions from fossil fuel-fired EGUs through a tradable 

allowance system.677 Here, again, the EPA concluded that -- 

the preferred trading remedy will allow source owners 

to choose among several compliance options to achieve 

required emission reductions in the most cost 

effective manner, such as installing controls, 

changing fuels, reducing utilization, buying 

allowances, or any combination of these actions.678

 

675 70 Fed. Reg. 25162, 25196 (May 12, 2005). 676 70 Fed. Reg. at 25196. 677 76 Fed. Reg. 48208 (Aug. 8, 2011). 678 76 Fed. Reg. at 48272. 
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As with the previous two interstate transport programs, the EPA 

in CSAPR recognized that interstate trading was a particularly 

well-suited mechanism for addressing emissions from EGUs because 

of “the power sector’s ability to operate as an integrated, 

interstate system and to promote reliability.”679

In fact, the Acid Rain Program and the transport rules have 

resulted in large numbers of fossil fuel-fired EGUs purchasing 

allowances instead of implementing controls. For example, SO2

control options available to sources include switching to low 

sulfur coal, employing various types of flue gas desulfurization 

(FGDs), or utilizing fluidized bed limestone units, as well as 

purchasing allowances. As Table 5, below, shows, as of 2012, 

more than half the coal-fired EGUs in the ARP and CAIR annual SO2

program, which EGUs generate 33 percent of the electricity from 

coal-fired units in those programs, comply with their ARP and 

CAIR SO2 emission limits simply by holding allowances – many of 

which are purchased from other entities – and without 

implementing controls. 

Table 5. SO2 Controls in 2012 on Coal-Fired Units in the ARP and 

CAIR Annual SO2 Program680

 

679 76 Fed. Reg. at 48272. 680 http://epa.gov/airmarkets/progress/ARPCAIR12.html 
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SOx Control 

Type 

Number of 

Units 

Share of Units Share of MWh 

Generation 

FGD 468 44% 66% 

Other 43 49% 1% 

Uncontrolled 545 52% 33% 

Source: EPA, 2013 

By the same token, in 2005, the EPA promulgated rulemaking 

under CAA section 111(d) to control mercury emissions from 

affected EGUs: The CAMR. The rule promulgated a two-phase, 

nationwide, interstate, allowance-based cap-and-trade program 

for mercury. The EPA specified budgets for each state, based on 

the sum of allowances allocated to each existing EGU located in 

the state. The number of allowances allocated to a particular 

EGU were based on the EGU’s pro rata share of the overall 

national cap on mercury emissions. In the first phase, the cap 

was 38 tons per year, and in the second phase, the cap was 

reduced to 15 tons per year. The EPA recognized that in the 

second phase, not all sources could cost-effectively install 

pollution control technology, but that the trading program would 

allow some sources to meet their requirements by “buying 

allowances.”681 

 

681 70 Fed. Reg. 28606, 28619 (May 18, 2005). 
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The EPA’s regional haze rules provide another example of a 

trading program in which sources – primarily, fossil fuel-fired 

EGUs – choose to meet their emission limits by purchasing 

allowances from other sources in lieu of implementing controls. 

CAA section 169A required the EPA to promulgate regulations to 

assure reasonable progress toward meeting the national 

visibility goal. CAA section 169A(b)(2) required the EPA to 

include in its regulations a requirement that states revise 

their SIPs to include “emission limitations, schedules of 

compliance and other measures as may be necessary to make 

reasonable progress toward the national goal,” including a 

requirement that certain older stationary sources “procure, 

install, and operate ... the best available retrofit 

technology,” more commonly known as BART. A 1993 Ninth Circuit 

decision held that the EPA could decide “not to adopt the 

emission control limits indicated by BART analysis, but instead 

to adopt an emission limitations standard that would produce 

greater visibility improvement at a lower cost.”682 

In 1999, the EPA promulgated the Regional Haze Rule, which 

allowed states to adopt trading programs or other alternatives 

 

682 Central Arizona Water District v. EPA, 990 F.2d 1531, 1543 

(9th Cir. 1993). 
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in lieu of requiring retrofit controls at sources subject to 

BART.683 Specifically, the (c) NSPS rules for EGUs that depend on 

the integrated grid. 

The EPA has promulgated NSPS for EGUs that include 

requirements based on the fact that an EGU may reduce its 

generation, and therefore its emissions, because the integration 

of the grid allows another EGU to increase generation and 

thereby avoid jeopardizing the supply of electricity. For 

example, in 1979, the EPA finalized new standards of performance 

to limit emissions of SO2 from new, modified, and reconstructed 

EGUs. In evaluating the best system against concerns of electric 

service reliability, the EPA took into account the unique 

features of power transmission along the interconnected grid and 

the unique commercial relationships that rely on those 

features.684

Additionally, in 1982, the EPA recognized that utility turbines 

could meet a NOx emission limit without unacceptable economic 

 

683 64 FR 35,714 (July 1, 1999) (codified at 40 C.F.R. 51.308-

309). 

684 See 44 FR 33580, 33597-33600 (taking into account “the amount 

of power that could be purchased from neighboring interconnected 

utility companies” and noting that “[a]lmost all electric 

utility generating units in the United States are electrically 

interconnected through power transmission lines and switching 

stations” and that “load can usually be shifted to other 

electric generating units”). 
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consequences because “other electric generators on the grid can 

restore lost capacity caused by turbine down time.”685 We 

describe the relevant parts of these rules in greater detail in 

the Legal Memorandum. 

 Regional Haze Rule provides: 

A state may opt to implement or require participation in 

an emissions trading program or other alternative 

measure rather than to require sources subject to BART 

to install, operate, and maintain BART.686

In a challenge to revisions to the Regional Haze Rule in 2003, 

the D.C. Circuit held that the EPA had reasonably interpreted 

section 169A(b)(2) as permitting alternatives to BART, including 

trading programs, so long as they achieve greater reasonable 

progress than would the installation of retrofit controls.687 The 

EPA has since approved several regional haze trading programs in 

lieu of BART.688 

(7) Consistency with the pollution prevention goalspurposes

of the CAA. Clean Air Act. 

Interpreting the term “system of emission reduction” 

broadly to include the building blocks 2 and 3 (so that the 

 

685 47 FR 3767, 3768 (Jan. 27, 1982). 686 40 CFR 51.308(e)(2). 687 Ctr. for Econ. Dev. v. EPA, 398 F.3d 653, 660 (D.C. Cir. 

2005). 

688 See, e.g., 77 FR 33,642 (June 7, 2012) (codified at 40 C.F.R. 

§ 51.308(e)(4)) (authorizing eastern states to rely on CSAPR in 

lieu of BART). 
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“best system of emission reduction ... adequately demonstrated” 

may include those measures as long as they meet all of the 

applicable requirements) is also consistent with a primary 

purpose of the CAA, which is to encourage the purposes of the 

CAA. Most importantly, these purposes include protecting public 

health and welfare by comprehensively addressing air pollution, 

and, particularly, protecting against urgent and severe threats. 

In addition, these purposes include promoting pollution 

prevention measures, as well as the advancement of technology 

that reduces air pollution. 

(a) Purpose of protecting public health and welfare. 

The first provisions in the Clean Air Act set out Congress’s 

findings and the CAA’s purposes. They provide as follows, in 

relevant part: 

Section 101. Congressional findings and declaration of 

purpose 

(a) The Congress finds— 

* * * * 

(2) that the growth in the amount and complexity of 

air pollution brought about by urbanization, 

industrial development, and the increasing use of 

motor vehicles, has resulted in mounting dangers to 

the public health and welfare * * * * 

(3) that air pollution prevention (that is, the 

reduction or elimination, through any measures, of the 

amount of pollutants produced or created at the 

source) and air pollution control at its source is the 
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primary responsibility of States and local 

governments; and 

(4) that Federal financial assistance and leadership 

is essential for the development of cooperative 

Federal, State, regional, and local programs to 

prevent and control air pollution. 

(b) The purposes of this title are— 

(1) to protect and enhance the quality of the Nation’s 

air resources so as to promote the public health and 

welfare and the productive capacity of its population; 

(2) to initiate and accelerate a national research and 

development program to achieve the prevention and 

control of air pollution; 

(3) to provide technical and financial assistance to 

State and local governments in connection with the 

development and execution of their air pollution 

prevention and control programs; and 

(4) to encourage and assist the development and 

operation of regional air pollution prevention and 

control programs. 

(c) POLLUTION PREVENTION.—A primary goal of this Act 

is to encourage or otherwise promote reasonable 

Federal, State, and local governmental actions, 

consistent with the provisions of this Act, for 

pollution prevention. 

As just quoted, these provisions are explicit that the 

purpose of the CAA is “to protect and enhance the quality of the 

Nation’s air resources so as to promote the public health and 

welfare and the productive capacity of its population.” 

Moreover, Congress designed the CAA to be “the comprehensive 

vehicle for protection of the Nation’s health from air 
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pollution”689 and, in fact, designed CAA section 111(d) to 

address air pollutants not covered under other provisions, 

specifically so that “there should be no gaps in control 

activities pertaining to stationary source emissions that pose 

any significant danger to public health or welfare.”690

Furthermore, in these purpose provisions, Congress recognized 

that while pollution prevention and control are the primary 

responsibility of the States, “federal leadership” would be 

essential. 

At its core, Congress designed the CAA to address urgent 

and severe threats to public health and welfare. This purpose is 

evident throughout 1970 CAA Amendments, which authorized 

stringent remedies that were necessary to address those 

problems. By 1970, Congress viewed the air pollution problem, 

which had been worsening steadily as the nation continued to 

industrialize and as automobile travel dramatically increased 

 

689 H.R. Rep. No. 95-294, at 42 (May 12, 1977), 1977 CAA Legis. 

Hist. at 2509 (discussing a provision in the House Committee 

bill that became CAA section 122, requiring the EPA to study and 

regulate radioactive air pollutants and three other air 

pollutants). 

690 S. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA Legis. 

Hist. at 420 (discussing section 114 of the Senate Committee 

bill, which was the basis for CAA section 111(d)). 
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after World War II,691 as nothing short of a national crisis.692

With the 1970 CAA Amendments, Congress enacted a stringent 

response, designed to match the severity of the problem. At the 

same time, Congress did not foreclose the EPA’s ability to 

address new environmental concerns; in fact, Congress largely 

deferred to the EPA’s expertise in identifying pollutants and 

sources that adversely affect public health or welfare. In doing 

so, Congress authorized the EPA to establish national ambient 

air quality standards for the most pervasive air pollutants -- 

 

691 See Dewey, Scott Hamilton, Don’t Breathe the Air: Air 

Pollution and U.S. Environmental Politics, 1945-1970 (Texas A&M 

University Press 2000). 

692 1970 was a significant year in environmental legislation, but 

it was also marked as “a year of environmental concern.” Sen. 

Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA Legis. 

Hist. at 223. By mid-1970, Congress recognized that “[o]ver 200 

million tons of contaminants [were] spilled into the air each 

year in America.... And each year these 200 million tons of 

pollutants endanger the health of [the American] people.” Id. at 

224. “Cities up and down the east coast were living under clouds 

of smog and daily air pollution alerts.” Sen. Muskie, S. 

Consideration of the Conference Rep. (Dec. 18, 1970), 1970 CAA 

Legis. Hist. at 124. Put simply, America faced an “environmental 

crisis.” Sen. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 

1970 CAA Legis. Hist. at 224. The conference agreement, it was 

reported, “faces the air pollution crisis with urgency and in 

candor. It makes hard choices, provides just remedies, requires 

stiff penalties.” Sen. Muskie, S. Consideration of the 

Conference Rep. (Dec. 18, 1970), 1970 CAA Legis. Hist. at 123. 

“[I]t represents [Congress’] best efforts to act with the 

knowledge available ... in an affirmative but constructive 

manner.” Id. at 150. 
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including the precursors for the choking smog that blanketed 

urban areas693 --to protect public health with an ample margin of 

safety. Disappointed that the states had not taken effective 

action to that point to curb air pollution, “Congress reacted by 

taking a stick to the States”694 and including within the 1970 

CAA Amendments both the requirement that the states develop 

plans to assure that their air quality areas would meet those 

standards by no later than five years, and the threat of 

imposition of federal requirements if the states did not timely 

adopt the requisite plans. Congress also required the EPA to 

establish standards for hazardous air pollutants that could 

result in shutting sources down. Congress added stringent 

controls on automobiles, overriding industry objections that the 

standards were not achievable. In addition, Congress added CAA 

section 111(b), which required the EPA to list categories based 

 

693 See Dewey, Scott Hamilton, Don’t Breathe the Air: Air 

Pollution and U.S. Environmental Politics, 1945-1970 (Texas A&M 

University Press 2000) at 230 (“By the mid-1960s, top federal 

officials showed an increasing sense of alarm regarding the 

health effects of polluted air. In June, 1966, Secretary of 

Health, Education, and Welfare John W. Gardner testified before 

the Muskie subcommittee: “We believe that air pollution at 

concentrations which are routinely sustained in urban areas of 

the United States is a health hazard to many, if not all, 

people.”). 

694 Train v. NRDC, 421 U.S. 60, 64 (1975). 
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on harm to public health and regulate new sources in those 

categories. Congress then designed CAA section 111(d) to assure, 

as the Senate Committee Report for the 1970 CAA Amendments 

noted, that “there should be no gaps in control activities 

pertaining to stationary source emissions that pose any 

significant danger to public health or welfare.”695 

.Similarly, the 1977 and 1990 CAA Amendments were also 

designed to respond to new and/or pressing environmental issues. 

For example, in 1977 then-EPA Administrator Costle testified 

before Congress that the expected increase in coal use (in 

response to various energy crises, including the 1973-74 Arab 

Oil Embargo) “will make vigorous and effective control even more 

urgent.”696 Similarly, by 1990, Congress recognized that “many of 

 

695 S. Committee Rep. to accompany S. 4358No. 91-1196, at 20 

(Sept. 17, 1970), 1970 CAA Legis. Hist. at 420 (discussing 

section 114 of the Senate Committee bill, which was the basis 

for CAA section 111(d)). Note that in the 1977 CAA Amendments, 

the House Committee Report made a similar statement. House 

CommH.R. Rep. No. 95-294, at 41, Leg.42 (May 12, 1977), 1977 CAA 

Legis. Hist. vol. 4 at 2509 (discussing a provision in the House 

Committee bill that became CAA section 122, requiring EPA to 

study and then take action to regulate radioactive air 

pollutants and three other air pollutants). 

696 Statement of Administrator Costle, Hearings before the 

Subcommittee on Energy Production and Supply of the Senate 

Committee on Energy and Natural Resources (Apr. 5, 7, May 25, 

June 24 and 30, 1977), 1977 CAA Legis. Hist. at 3532 (discussing 

the relationship between the National Energy Plan and the 

Administration’s proposed CAA amendments). Some of the specific 

changes to the CAA include the addition of the PSD program, 
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the Nation’s most important air pollution problems [had] failed 

to improve or [had] grown more serious.”697 Indeed, President 

George H. W. Bush said that “‘progress has not come quickly 

enough and much remains to be done.’”698 

Climate change has become the nation’s most important 

environmental problem. We are now at a critical juncture to take 

meaningful action to curb the growth in CO2 emissions and 

forestall the impending consequences of prior inaction. CO2

emissions from existing fossil fuel-fired power plants are by 

far the largest source of stationary source emissions. They emit 

almost three times as much CO2 as do the next nine stationary 

source categories combined, and approximately the same amount of 

CO2 emissions as all of the nation’s mobile sources. The only 

controls available that can reduce CO2 emissions from existing 

power plants in amounts commensurate with the problems they pose 

are the measures in building blocks 2 and 3, or far more 

expensive measures such as CCS. 

 

visibility protections, requirements for nonattainment areas, 

and stratospheric ozone provisions. 

697 H.R. Rep. No. 101-490, at 144 (May 17, 1990). 698 H.R. Rep. No. 101-490, at 144 (May 17, 1990). Some of the 

changes adopted in 1990 include revisions to the NAAQS 

nonattainment program, a more aggressive and substantially 

revised CAA section 112, the new acid rain program, an operating 

permits program, and a program for phasing out of certain ozone 

depleting substances. 
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Thus, interpreting the “system of emission reduction” 

provisions in CAA section 111(d)(1) and (a)(1) to allow the 

nation to meaningfully address the urgent and severe public 

health and welfare threats that climate change pose is 

consistent with what the CAA was designed to do.699 This 

interpretation is also consistent with the cooperative purpose 

of section 111(d) to assure that the CAA comprehensively address 

those threats through the mechanism of state plans, where the 

states assume primary responsibility under federal leadership. 

See King v. Burwell, 576 U.S. (2015), No. 14-114 (2015), slip 

op. at 15 (“We cannot interpret federal statutes to negate their 

own stated purposes” (quoting New York State Dept. of Social 

Servs. v. Dublino, 413 U.S. 405, 419-20 (1973)); id. at 21 (“A 

 

699 In addition, as we have noted, in designing the 1970 CAA 

Amendments, Congress was aware that carbon dioxide increased 

atmospheric temperatures. In 1970, when Congress learned that 

“the carbon dioxide balance might result in the heating up of 

the atmosphere” and that particulate matter “might cause 

reduction in radiation,” the Nixon Administration assured 

Congress that “[w]hat we are trying to do, however, in terms of 

our air pollution effort should have a very salutary effect on 

either of these.” Testimony of Charles Johnson, Jr., 

Administrator of the Consumer Protection and Environmental 

Health Service (Administration Testimony), Hearing of the House 

Subcommittee on Public Health and Welfare (Mar. 16, 1970), 1970 

CAA Legis. Hist. at 1381. Many years later, scientific consensus 

has formed around the particular causes and effects of climate 

change; and the tools put in place in 1970 can be read fairly to 

address these concerns. 
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fair reading of legislation demands a fair understanding of the 

legislative plan.”).700

 (b) Purpose of encouraging pollution prevention. 

Interpreting “system of emission reduction” to include building 

blocks 2 and 3 is also consistent with the CAA’s purpose to 

encourage pollution prevention. CAA section 101(c) states that 

“[a] primary goal of [the CAA] is to encourage or otherwise 

promote reasonable federal, state, and local governmental 

actions, consistent with the provisions of this chapter, for 

pollution prevention.” Indeed, in the U.S. Code, in which the 

CAA is codified as chapter 85, the CAA is entitled, “Air 

 

700 This final rule is also consistent with the CAA’s purpose of 

protecting health and welfare. For example, the CAA authorizes 

the EPA to regulate air pollutants as soon as the EPA can 

determine that those pollutants pose a risk of harm, and not to 

wait until the EPA can prove that those pollutants actually 

cause harm. See H.R. Rep. No. 95-294, at 49 (May 12, 1977), 1977 

CAA Legis. Hist. at 2516 (describing the CAA as being 

designed... to assure that regulatory action can effectively 

prevent harm before it occurs; to emphasize the predominant 

value of protection of public health”).The protective spirit of 

the CAA extends to the present rule, in which the EPA regulates 

on the basis of building blocks 2 and 3 because the range of 

available and cost-effective measures in those building blocks 

achieves more pollution reduction than building block 1 alone. 

Indeed, add-on controls that are technically capable of reducing 

CO2 emissions at the scale necessitated by the severity of the 

environmental risk -– for example, CCS technology -- are not as 

cost-effective as building blocks 2 and 3 on an industry-wide 

basis, and while the costs of the add-on controls can be 

expected to be reduced over time, it is not consonant with the 

protective spirit of the CAA to wait.
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Pollution Prevention and Control.”701 CAA section 101(a)(3) 

describes “air pollution prevention” as “the reduction or 

elimination, through any measures, of the amount of pollutants 

produced or created at the source”. (Emphasis added.) The 

reference to “any measures” highlights the breadth of what 

Congress considered to be pollution prevention, that is, any and 

all measures that reduce or eliminate pollutants at the 

source.702 

The measures in building blocks 2 and 3 qualify as 

“pollution prevention” measures because they are “any measures” 

that “reduc[e] or eliminate[e] ... the amount of pollutants 

produced or created at the [fossil fuel-fired affected] 

source[s].” In light of one ofThus, consistent with the CAA’s 

primary goals, it is therefore reasonable to interpret a “system 

 

701 See Air Quality Act of 1967, Pub. L. 90-148, § 2, 81 Stat. 

485 (Nov. 21, 1967) (adding “Title I—Air Pollution Prevention 

and Control” to the CAA, along with Congress’ initial findings 

and purposes under CAA section 101). 

702 Section 101 emphasizes the importance of air pollution 

prevention in two other provisions: CAA section 101(b)(4) states 

that one of “the purposes of [title I of the CAA, which includes 

section 111] are ... (b) to encourage and assist the development 

and operation of regional air pollution prevention and control 

programs.” CAA section 101(a)(3) adds: “The Congress finds -- 

... (3) that air pollution prevention ... and air pollution 

control at its source is the primary responsibility of states 

and local governments.” In fact, section 101 mentions pollution 

prevention no less than 6 times.
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of emission reduction,” as including the pollution prevention 

measures in building blocks 2 and 3. 

(8) Additional considerations. Interpreting c) Purpose of 

advancing technology to control air pollution. 

This final rule is also consistent with CAA section 

111(d)(1) and (a)(1) to include building blocks 2 and 3 is 

consistent with111’s purpose of promoting the spirit of the CAA, 

including Congress’s intention to address urgent and severe 

environmental problems; to be precautionary in protecting public 

health and welfare against risks; and to promote technological 

advancement, of pollution control technology based on the 

expectation that American industry couldwill be able to come up 

with develop innovative solutions to thosethe environmental 

problems. 

The 1970 CAA Amendments were designed to address urgent and 

severe problems, and authorized stringent remedies that were 

necessary to address those problems. Congress viewed the air 

pollution problem in 1970 as a crisis,703 and enacted a stringent 

 

703 1970 was a significant year in environmental legislation, but 

it was also marked as “a year of environmental concern.” Sen. 

Muskie, Sen. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA Legis. 

Hist. at 223. By mid-1970, Congress recognized that “[o]ver 200 

million tons of contaminants [were] spilled into the air each 

year in America.... And each year these 200 million tons of 

pollutants endanger the health of [the American] people.” Id. at 
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response, designed to match the severity of the problem. At the 

same time, Congress did not foreclose the EPA’s ability to 

address new environmental concerns; in fact, Congress largely 

deferred to the EPA’s expertise in identifying pollutants and 

sources that adversely affect public health or welfare. In doing 

so, Congress authorized the EPA to establish ambient air quality 

standards to protect public health with an ample margin of 

safety, and required states to develop plans to assure that 

their air quality areas would meet those standards by no later 

than five years. Congress also required the EPA to establish 

standards for hazardous air pollutants that could result in 

shutting sources down. Congress added stringent controls on 

automobiles, overriding industry objections that the standards 

were not achievable. In addition, Congress added CAA section 

 

224. “Cities up and down the east coast were living under clouds 

of smog and daily air pollution alerts.” Sen. Muskie, Sen. 

Consideration of the Conference Rep. (Dec. 18, 1970), 1970 CAA 

Legis. Hist. at 124. Put simply, America faced an “environmental 

crisis.” Sen. Muskie, Sen. Debate on S. 4358 (Sept. 21, 1970), 

1970 CAA Legis. Hist. at 224. The conference agreement, it was 

reported, “faces the air pollution crisis with urgency and in 

candor. It makes hard choices, provides just remedies, requires 

stiff penalties.” Sen. Muskie, Sen. Consideration of the 

Conference Rep. (Dec. 18, 1970), 1970 CAA Legis. Hist. at 123. 

“[I]t represents [Congress’] best efforts to act with the 

knowledge available ... in an affirmative but constructive 

manner.” Id. at 150. 
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111(b), which required the EPA to list categories based on harm 

to public health and regulate new sources in those categories. 

Congress then designed CAA section 111(d) to assure, as the 

Senate Committee Report for the 1970 CAA Amendments noted, that 

“there should be no gaps in control activities pertaining to 

stationary source emissions that pose any significant danger to 

public health or welfare.”704 

Addressing CO2 emissions from the utility power sector as 

the EPA does in this rule is consistent with Congress’s 

recognition of the need to effectively address severe and urgent 

public health threats from air pollution. Moreover, this rule is 

consistent with the comprehensive approach of the CAA. Congress 

was clear that “the [CAA] is the comprehensive vehicle for 

protection of the Nation’s health from air pollution.”705 The 

building blocks are the methods available for meaningfully 

 

704 S. Committee Rep. to accompany S. 4358No. 91-1196, at 20 

(Sept. 17, 1970), 1970 CAA Legis. Hist. at 420 (discussing 

section 114 of the Senate Committee bill, which was the basis 

for CAA section 111(d)). Note that in the 1977 CAA Amendments, 

the House Committee Report made a similar statement. House 

CommH.R. Rep. No. 95-294, at 41, Leg.42 (May 12, 1977), 1977 CAA 

Legis. Hist. vol. 4 at 2509 (discussing a provision in the House 

Committee bill that became CAA section 122, requiring EPA to 

study and then take action to regulate radioactive air 

pollutants and three other air pollutants). 

705 House Comm. Rep. 95-294, at 41, Leg. Hist. vol. 4 at 2509 
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addressing CO2 emissions from existing affected EGUs on an 

industry-wide basis. 

This final rule is also consistent with the precautionary 

nature of the CAA. For example, the CAA authorizes the EPA to 

regulate air pollutants as soon as the EPA can determine that 

those pollutants pose a risk of harm, and not to wait until the 

EPA can prove that those pollutants actually cause harm.706

Similarly, as discussed next, the CAA generally is technologyforcing. The precautionary nature of the CAA extends to the 

present rule, in which the EPA regulates on the basis of 

building blocks 2 and 3, because the range of available and 

cost-effective measures in those building blocks achieves more 

pollution reduction than building block 1 alone. Indeed, add-on 

controls are not as cost-effective on an industry-wide basis, 

and while the costs of the add-on controls can be expected to be 

reduced over time, it is not consonant with the precautionary 

spirit of the CAA to wait. 

This final rule is also consistent with the purpose of CAA 

section 111 to advance technology. The legislative history and 

 

706 See 1977 House Comm. Rep. 95-294 at 49, 4 Leg. Hist. at 2516 

(describing the CAA as being designed to have a “preventive or 

precautionary nature..., i.e., to assure that regulatory action 

can effectively prevent harm before it occurs; to emphasize the 

predominant value of protection of public health”). 
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caselawcase law of CAA section 111 identify three different ways 

that Congress designed CAA section 111 to authorize standards of 

performance that promote technological improvement: (i) the 

development of technology that may be treated as the “best 

system of emission reduction ... adequately demonstrated;” under 

CAA section 111(a)(1));707; (ii) the expanded use of the best 

demonstrated technology;708 and (iii) the development of emerging 

technology.709 This rule is consistent with the second of those 

ways ––- it expands the use of the measures in building blocks 2 

and 3, which are already established and provide the 

mostsubstantial reductions at the leastreasonable cost. As 

discussed below, the use of the measures in these building 

blocks will be most fully expanded when organized markets 

develop, and our expectation that those markets will develop is 

consistent with the Congress’s view, just described, that CAA 

section CAA 111 should promote technological innovation. 

 

707 See Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 

(D.C. Cir. 1973) (the best system of emission reduction must 

“look[] toward what may fairly be projected for the regulated 

future, rather than the state of the art at present”). 

708 See 1970 Senate Committee ReportS. Rep. No. 91-1196, at 

15 (“The maximum use of available means of preventing and 

controlling air pollution is essential to the elimination 

of new pollution problems”). 

709 See Sierra Club v. Costle, 657 F.2d at 351 (upholding a 

standard of performance designed to promote the use of an 

emerging technology). 
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This final rule is also consistent with Congress’s overall 

view that the CAA Amendments as a whole were designed to promote 

technological innovation. In enacting the CAA, Congress 

articulated its expectation that American industry would be 

creative and come up with innovative solutions to the urgent and 

severe problem of air pollution. This is manifest in the wellrecognized technology-forcing nature of the CAA, and was 

expressed in numerous, sometimes ringing, statements in the 

legislative history about the belief that American industry will 

be able to develop the needed technology. For example, in the 

1970 floor debates, Congress recalled that the nation had put a 

man on the moon a year earlierbefore and had won World War II a 

quarter century earlier, and attributed much of the credit for 

those singular achievements to American industry and its ability 

to be productive and innovative. Congress expressed confidence 

that American industry could meet the challenges of developing 

air pollution controls as well.710 

 

710 Sen. Muskie, SenS. Debates on S. 4358 (Sept. 21, 1970), 1970 

CAA Legis. Hist. at 227 (“At the beginning of World War II 

industry told President Roosevelt that his goal of 100,000 

planes each year could not be met. The goal was met, and the war 

was won. And in 1960, President Kennedy said that America would 

land a man on the moon by 1970. And American industry did what 

had to be done. Our responsibility in Congress is to say that 

the requirements of this bill are what the health of the Nation 

requires, and to challenge polluters to meet them.”).”). See 
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(d) Response to commenters concerning purpose. 

Commenters have stated that the proposed rule “would 

transform CAA section 111 into something untethered to its 

statutory language and unrecognizable to the Congress that 

created it.”711 OnCommenters with this line of comments focused 

on the contrary, we believeramifications of building block 4, 

which the EPA has decided does not belong in BSER using EPA’s 

historical interpretation of BSER. Regardless of whether the 

comments are accurate with respect to building block 4 measures, 

they are certainly not accurate with respect to the three 

building blocks that this the EPA is defining as the BSER. This 

rule would be instantly recognizable to the Congresses that 

created and amended CAA section 111. and is carefully fashioned 

to the statutory text in CAA section 111(d) and (a)(1). This 

final rule would be recognizable to the Congress that adopted 

CAA section 111 in 1970 as part of a stringent, 

comprehensive,bold, far-reaching law designed to address the 

 

Blaime, A.J., The Arsenal of Democracy: FDR, Detroit, and an 

Epic Quest to Arm an America at War (Houghton Mifflin Harcourt 

2014); Carew, Michael G., Becoming the Arsenal: The American 

Industrial Mobilization for World War II, 1938-1942 (University 

Press of America, Inc. 2010).

711 UARG comment at 31. See id. at 18, 29, 49. This comment 

appears to be a reference to the Supreme Court’s statement in 

UARG. See Util. Air RegulatoryReg. Group v. EPA, 134 S. Ct. 

2427, 2444 (2014). 
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comprehensively an air pollution crisis, that 

challengedthreatened the health of millions of Americans; to 

have EPA and the States work cooperatively to develop statespecific approaches to address a national problem; to challenge

industry to meet that crisis with the same creative energy that 

won World War II,; and that gaveto give the EPA broad authority 

––- under section 111 and other provisions ––- to craft the 

needed emission limitations. This final rule would be 

recognizable to the Congress that revised CAA section 111 in 

1977 to explicitly authorize that standards be based on actions 

taken by third parties (fuel cleaners). And this final rule 

would be recognizable to the Congress that revised CAA section 

111 in 1990 to be linked to the Acid Rain Program that Congress 

adopted at the same time, which regulated the same industry 

(fossil fuel-fired EGUs) through some of the same measures 

(dispatchgeneration shifts and renewable energy), and that 

recognizedexplicitly acknowledged that those measures (renewable 

energy) would also reduce carbon dioxide and thereby address the 

dangers of climate change. To reiterate, for the reasons 

explained in this preamble, this rule is grounded in our 

reasonable interpretation of CAA section 111(d) and (a)(1). 

(9) Response8) Constraints on the BSER – treatment of 

building block 4 and response to comments concerning precedents. 
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Although the BSER provisions are sufficiently broad to 

include, for affected EGUs, the measures in building blocks 2 

and 3, they also incorporate significant constraints on the 

types of measures that may be included in the BSER. We discuss 

those constraints in this section. These constaints explain why 

we are not including building block 4 in the BSER. In addition, 

these constraints explain why our reliance on building blocks 2 

and 3 will have limited precedential effect for other 

rulemakings, and serve as precedents. Commentersour basis for 

responding to commenters who expressed concern that reliance on 

building blocks 2 and 3 would set a precedent for the EPA to 

rely on similar measures in promulgating future air pollution 

controls.712 For example, commenters asserted that the EPA could 

“develop standards of performance for tailpipe emissions from 

motor vehicles” by “requiring car owners to shift some of their 

travel to buses,” which the commenters considered analogous to 

building block 2; “or by requiring there to be more electric 

 

712 Most of the commenters’ concerns over what they viewed as the 

precedential effects of the building blocks concerned building 

block 4. Because the EPA is not finalizing building block 4 as 

part of the BSER, it is not necessary to address those concerns. 
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vehicle purchases,” which the commenters considered analogous to 

building block 3.713 for other sectors.714

As discussed above, the emission limits in the CAA section 

111(d) emission guidelines that this rule promulgates are based 

on the EPA’s determination, for the affected EGUs, of the 

“system of emission reduction” that is the “best,” taking into 

account “cost” and other factors, and that is “adequately 

demonstrated.” Those components include certain interpretations 

and applications. For example, because the affected EGUs must be 

able to achieve their emission standards through application of 

the BSER, the BSER must be something that the EGUs themselves 

can implement. The affected sources that are the subject of the 

emission guidelines can employ the BSER to achieve the emission 

limits that the guidelines prescribe and provide constraints on 

the types of measures or controls that the EPA may determine to 

include in the BSER. 

 

713 UARG comment at 2-3. 714 Commenters offered hypothetical examples to illustrate their 

concerns over precedential effects, discussed below. Some 

commenters objected that our proposed interpretation of the BSER 

failed to include limiting principles. In the Legal Memorandum, 

we discuss the relevance of limiting principles and note that 

the statutory constraints discussed in this section of the 

preamble constitute limits on the type of the BSER that the EPA 

is authorized to determine. 
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For the reasons discussed, building blocks 2 and 3 meet the 

definition of the BSER, as it has been interpreted and applied. 

As a result, they qualify as part of the basis for the emission 

limits in the emission guidelines promulgated in this rule. 

Moreover, as also discussed, the affected EGUs may meet those 

limits by implementing the BSER, including the measures in 

building blocks 2 and 3. Commenters’ concerns over precedential 

impact cannot be taken to mean that the building blocks should 

not be considered to meet the requirements of the BSER or that 

the affected EGUs cannot be considered to meet the emission 

limits by implementing those measures.

Moreover(a) Emission reductions from affected sources. 

The first constraint is that the BSER must assure emission 

reductions from the affected sources. Under section 111(d)(1), 

the states must submit state plans that “establish[] standards 

of performance for any existing source,” and, under section 

111(a)(1) and the EPA’s implementing regulations, those 

standards are informed by the EPA’s determination of the best 

system of emission reduction adequately demonstrated. Because 

the emission standards must apply to the affected sources, 

actions taken by affected sources that do not result in emission 

reductions from the affected sources –- for example, offsets 

(e.g., the planting of forests to sequester CO2) –- do not 
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qualify for inclusion in the BSER. Building blocks 2 and 3 

achieve emission reductions from the affected EGUs, and thus are 

not precluded under this constraint. 

(b) Controls or measures that affected EGUs can implement. 

The second constraint is that because the affected EGUs 

must be able to achieve their emission performance rates through 

the application of the BSER, the BSER must be controls or 

measures that the EGUs themselves can implement. Moreover, as 

noted, the D.C. Circuit has established criteria for 

achievability in the section 111(b) case law; e.g., sources must 

be able to achieve their standards under a range of 

circumstances. If those criteria are applicable in a section 

111(d) rule, the BSER must be of a type that allows sources to 

meet those achievability criteria. As noted, under this rule, 

affected EGUs can achieve their emission performance rates in 

the various circumstances under which they operate, through the 

application of the building blocks. 

(c) “Adequately demonstrated.” 

The third constraint is that the system of emission 

reduction that the EPA determines to be the best must be 

“adequately demonstrated.” To qualify as the BSER, controls and 

measures must align with the nature of the regulated industry 
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and the nature of the pollutant so that implementation of those 

controls or measures will result in emission reductions from the 

industry and allow the sources to achieve their emission 

performance standards. The history of the effectiveness of the 

controls or other measures, or other indications of their 

effectiveness, are important in determining whether they are 

adequately demonstrated. 

More specifically, the application of building blocks 2 and 

3 to affected EGUs has a number of unique characteristics that 

significantly limit their precedential impact. Building blocks 2 

and 3 entail the production of the same amount of the same 

product -- electricity, a highly substitutablefungible product 

that can be produced using a variety of highly substitutable

generation processes -- through the cleaner (that is, less CO2-

intensive) processes of shifting dispatch from steam generators 

to existing NGCC units, and from both steam generators and NGCC 

units to renewable generators. 

The physical properties of electricity and the highly 

integrated nature of the electricity system allow the use of 

these cleaner processes to generate the same amount of 

electricity. In addition, the electricity sector is primarily 

domestic -- little electricity is exported outside the U.S. -- 

and there is nolow capacity for substantial amounts of storage. 
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In addition, the electricity sector is highly regulated, 

planned, and coordinated. As a result, holding demand constant, 

an increase in one type of generation will result in a decrease 

in another type of generation. Moreover, the higher-emitting 

generators, which are fossil fuel-fired, have higher variable 

costs than renewable generators, so that increased renewable 

generation will generally back out fossil- fuel-fired 

generation. 

Because of these characteristics, the electricity sector 

has a long and well-established history of substituting one type 

of generation for another. This has occurred for various a wide 

variety of reasons, includingmany of which are directly related 

to the system’s primary purposes and functions, as well as for

environmental reasons. As a result, at present, there is a wellestablished network of business and operational relationships 

and past practices that supports building blocks 2 and 3. As 

noted elsewhere, a large segment of steam generators already 

have business relationships with existing NGCC units, and a 

large segment of all fossil fuel-fired EGUs already own, co-own, 

or have invested in renewable energy. 

Many of these characteristics are unique to the utility 

power sector. Moreover, this complex of characteristics, ranging 

from the physical properties of electricity and the integrated 
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nature of the grid to the institutional mechanisms that assure 

reliability and the existing practices and business 

relationships in the industry, combine to facilitate the 

implementation of building blocks 2 and 3 in a uniquely 

efficient manner. This supports basing the emission limits on 

the ability of owners and operators of fossil fuel-fired EGUs to 

replace their generation with cleaner generation in other 

locations, sometimes owned by other entities... 

 BecauseAs noted above, commenters offered hypothetical 

examples to illustrate their concerns over precedential effects. 

Most of their concerns focused on building block 4, and most of 

their hypothetical examples concerned reductions in demand for 

various types of products. We address these concerns in the 

response to comments document, but we note here that, in any 

event, these concerns are mooted because we are not finalizing 

building block 4. Some commenters offered hypothetical examples 

for building blocks 2 and 3 as well. For example, some 

commenters asserted that the EPA could “develop standards of 

performance for tailpipe emissions from motor vehicles” by 

“requiring car owners to shift some of their travel to buses,” 

which the commenters considered analogous to building block 2; 
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or by “requiring there to be more electric vehicle purchases,” 

which the commenters considered analogous to building block 3.715 

Commenters’ concerns over precedential impact cannot be 

taken to mean that the building blocks should not be considered 

to meet the requirements of the BSER or that the affected EGUs 

cannot be considered to meet the emission limits by implementing 

those measures. Moreover, because many of these individual 

characteristics, and their inherent complexity, are unique to 

the utility power sector, building blocks 2 and 3 as applied to 

fossil fuel-fired EGUs will have a limited precedent for other 

industries and other types of rulemakings. For example, the 

commenter’s hypothetical examples noted above are inapposite for 

several reasons. Title II standards are based on “the 

application of technology which the Administrator determines 

will be available for the model year...,” which is a narrower 

standard than the “best system of emission reduction ... 

adequately demonstrated.” Moreover, the examplesThe 

hypotheticals appear to be premised on government action 

(i.mandating actions not implementable by emitting sources 

(e.g., that a government would “require[e] car owners to shift 

some of their travel to buses, or ... require[e] there to be 

 

715 UARG comment at 2-3. 
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more electric vehicle purchases”), whereas the measures in 

building blocks 2 and 3 can be implemented by the affected EGUs. 

Nor have commenters attempted to address how car owners shifting 

travel to buses or purchasing more electric vehicles could be 

translated into lower tailpipe standards for motor vehicles.716

(d) “Best” in light of “cost ... nonair quality health and 

environmental impact and energy requirements” and EPA’s past 

practice and current policy. 

The fourth constraint, or set of constraints, is that the 

system of emission reduction must be the “best,” “taking into 

account the cost of achieving such reduction and any nonair 

quality health and environmental impact and energy 

requirements.” As noted, in light of the D.C. Circuit case law, 

the EPA has considered cost and energy factors on both an 

individual source basis and on the basis of the nationwide 

electricity sector. In determining what is “best,” the EPA has 

broad discretion to balance the enumerated factors.717 In 

interpreting and applying these provisions in this rulemaking to 

regulate CO2 emissions from affected EGUs under section 111(d), 

 

716 In any event, it is questionable whether measures such as 

those hypothesized by the commenters would be consistent with 

the provisions of Title II. 

717 See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 

Cir. 1999). 
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we are acting consistently with our past practice for applying 

these provisions in previous section 111 rulemakings and for 

regulating air pollutants from the electricity sector under 

other provisions of the CAA, as well as current policy. 

The great majority of our regulations under section 111 

have been 111(b) regulations for new sources. As discussed in 

the Legal Memorandum and briefly below, the BSER identified 

under section 111(b) is designed to assure that affected sources 

are well controlled at the time of construction, and that 

approach is consistent with the design expressed in the 

legislative history for the 1970 CAA Amendments that enacted the 

provision. 

Traditionally, CAA section 111 standards have been ratebased, allowing as much overall production of a particular good 

as is desired, provided that it is produced through an 

appropriately clean (or low-emitting) process. CAA section 111 

performance standards have primarily targeted the means of 

production in an industry and not consumers’ demand for the 

product. Thus, the focus for the BSER has been on how to most 

cleanly produce a good, not on limiting how much of the good can 

be produced. 

One example of the focus under section 111 on clean 

production, not limitation of product is provided by the 
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revised new source performance standards for electric utility 

steam generating units that we promulgated in 1979 following the 

1977 CAA Amendments to limit emissions of SO2, particulate 

matter, and NOx. In relevant part, the revised standards 

limited SO2 emissions to 1.20 lb/million BTU heat input and 

imposed a 90 percent reduction in potential SO2 emissions. This 

was based on the application of flue gas desulfurization (FGD) 

together with coal preparation techniques. In the preamble, we 

explain that “[t]he intent of the final standards is to 

encourage power plant owners and operators to install the best 

available FGD systems and to implement effective operation and 

maintenance procedures but not to create power supply 
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disruptions.”718,719 EPA has taken the same overall approach in its 

section 111(d) rules,720 including the CAMR rule noted below. 

Similarly, in a series of rulemakings regulating air 

pollutants from EGUs under several provisions of the CAA, we 

have focused our efforts on assuring that electricity is 

 

718 See, e.g., 44 FR 33580, at 33599 (June 11, 1979). In this 

rulemaking, the EPA recognized the ability of the integrated 

grid to minimize power disruptions: “When electric load is 

shifted from a new steam-electric generating unit to another 

electric generating unit, there would be no net change in 

reserves within the power system. Thus, the emergency condition 

provisions prevent a failed FGD system from impacting upon the 

utility company’s ability to generate electric power and 

prevents an impact upon reserves needed by the power system to 

maintain reliable electric service.” Id. 719 The EPA’s 1982 revised new source performance standards for 

certain stationary gas turbines provide another example of a 

rulemaking that focused controls on reducing emissions, as well 

as reliance on the integrated grid to avoid power disruptions. 

44 FR 33580 (June 11, 1979). In response to comments that 

requested a NOx emission limit exemption for base load utility 

gas turbines, the EPA explained that “for utility turbines ... 

since other electric generators on the grid can restore lost 

capacity caused by turbine down time” the NOx emission limit of 

1150 ppm for such turbines would not be rescinded. 44 FR 33580, 

at 33597-98. 

720 See “Phosphate Fertilizer Plants; Final Guideline Document 

Availability,” 42 FR 12022 (Mar. 1, 1977); “Standards of 

Performance for New Stationary Sources; Emission Guideline for 

Sulfuric Acid Mist,” 42 FR 55796 (Oct. 18, 1977); “Kraft Pulp 

Mills, Notice of Availability of Final Guideline Document,” 44 

FR 29828 (May 22, 1979); “Primary Aluminum Plants; Availability 

of Final Guideline Document,” 45 FR 26294 (Apr. 17, 1980); 

“Standards of Performance for New Stationary Sources and 

Guidelines for Control of Existing Sources: Municipal Solid 

Waste Landfills, Final Rule,” 61 FR 9905 (Mar. 12, 1996). 
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generated through cleaner or lower-emitting processes, and we 

have not sought to limit the aggregate amount of electricity 

that is generated. We describe those rules in section II, 

elsewhere in this section V.B.3., and in the Legal Memorandum. 

For example, as discussed in the Legal Memorandum, in the 

three transport rules promulgated under CAA section 

110(a)(2)(D)(i)(I) – the NOx SIP Call, CAIR, and CSAPR – which 

regulated precursors to ozone-smog and particulate matter, the 

EPA based certain aspects of the regulatory requirements on the 

fact that fossil fuel-fired EGUs could shift generation to 

lower-emitting sources. In CAMR, the 2005 rulemaking under 

section 111(d) regulating mercury emissions from coal-fired 

EGUs, the EPA based the first phase of control requirements on 

the actions the affected EGUs were required to take under CAIR, 

including shifting generation to lower-emitting sources. In 

addition, as also discussed in the Legal Memorandum, in the 

EPA’s 2012 MATS rule regulating mercury from coal-fired EGUs 

under section 112, at industry’s urging, the EPA allowed 

compliance deadlines to be extended for coal-fired EGUs that 

desired to substitute replacement power of any type, including 

NGCC units or renewable energy, for compliance purposes. 

While these and other rulemakings for fossil fuel-fired 

EGUs took different approaches towards lower-emitting generation 
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and renewable generation, they all were based on control 

measures that reduced emissions without reducing aggregate 

levels of electricity generation. It should be noted that even 

though some of those rules established overall emission limits 

in the form of budgets implemented through a cap-and-trade 

program, the EPA recognized that the fossil fuel-fired EGUs that 

were subject to the rules could comply by shifting generation to 

lower-emitting EGUs, including relying on renewable energy. In 

this manner, the rules limited emissions but on the basis that 

the industry could implement lower-emitting processes, and not 

based on reductions in overall generation. 

We are applying the same approach to this rulemaking. Our 

basis for this rulemaking is that affected EGUs can implement a 

system of emission reduction that will reduce the amount of 

their emissions without reducing overall electricity generation. 

This approach takes into account costs by minimizing economic 

disruption as well as the nation’s energy requirements by 

avoiding the need for environmental-based reductions in the 

aggregate amount of electricity available to the consumer, 

commercial, and industrial sectors. 

This approach is a reasonable exercise of the EPA’s 

discretion under section 111, consistent with the U.S. Supreme 

Court’s statements in its 2011 decision, American Electric Power 
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Co. v. Connecticut, that the CAA and the EPA actions it 

authorizes displace any federal common law right to seek 

abatement of CO2 emissions from fossil-fuel fired power plants. 

There, the Court emphasized that CAA section 111 authorizes the 

EPA –- which the Court identified as the “expert agency” -– to 

regulate CO2 emissions from fossil fuel-fired power plants based 

an “informed assessment of competing interests.... Along with the 

environmental benefit potentially achievable, our Nation's 

energy needs and the possibility of economic disruption must 

weigh in the balance.”721 

Similarly, the D.C. Circuit, in a 1981 decision upholding 

the EPA’s section 111(b) standards for air pollutants from 

fossil fuel-fired EGUs, stated that section 111 regulations 

concerning the electric power sector “demand a careful weighing 

of cost, environmental, and energy considerations.”722 This 

exercise of policy discretion is consistent with Congress’s 

expectation that the Administrator “should determine the 

achievable limits”723 and “would establish guidelines as to what 

 

721 American Electric Power Co. v. Connecticut, 131 S. Ct. 2527, 

2539-40 (2011). 

722 Sierra Club v. EPA, 657 F.2d 298, 406 (D.C. Cir. 1981). 

Id. at 406 n. 526. 723 S. Rep. No. 91-1196, at 15-16 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 415-16 (explaining that the “[Administrator] 

should determine the achievable limits and let the owner or 
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the best system for each such category of existing sources 

is.”724 As the D.C. Circuit explained, “[i]t seems likely that if 

Congress meant ... to curtail EPA’s discretion to weigh various 

policy considerations it would have explicitly said so in 

section 111, as it did in other parts of the statute.”725 

Our interpretation that CAA section 111 targets supply-side 

activities that allow continued production of a product through 

use of a cleaner process, rather than targeting consumeroriented behavior, also furthers Congress’ intent of promoting 

cleaner production measures “to protect and enhance the quality 

of the Nation’s air resources so as to promote the public health 

and welfare and the productive capacity of its population.”726

This principle is also consistent with promoting “reasonable ... 

governmental actions ... for pollution prevention.”727

In this rule, we are applying that same approach in 

interpreting the BSER provisions of section 111. That is, we are 

basing the regulatory requirements on measures the affected EGUs 

can implement to assure that electricity is generated with lower 

emissions, taking into account the integrated nature of the 

 

operator determine the most economic, acceptable technique to 

apply.”). 

724 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 725 Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. Cir. 1981). 726 CAA section 101(b)(1). 727 CAA section 101(c). 
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industry and current industry practices. Building blocks 1, 2 

and 3 fall squarely within this paradigm; they do not require 

reductions in the total amount of electricity produced. 

We recognize that commenters have raised extensive legal 

concerns about building block 4. We recognize that building 

block 4 is different from building blocks 1, 2, and 3 and the 

pollution control measures that we have considered under CAA 

section 111. Accordingly, under our interpretation of section 

111, informed by our past practice and current policy, today’s 

final action excludes building block 4 from the BSER. Building 

block 4 is outside our paradigm for section 111 as it targets 

consumer-oriented behavior and demand for the good, which would 

reduce the amount of electricity to be produced. 

Although numerous commenters urged us to include demandside energy efficiency measures as part of the BSER, as we had 

proposed to do, we conclude that we cannot do so under our 

historical practice, current policy, and current approach to 

interpreting section 111 as well as our historical practice in 

regulating the electricity sector under other CAA provisions. 

While building blocks 2 and 3 are rooted in our past practice 

and policy, building block 4 is not and would require a change 

(which we are not making) in our interpretation and 

implementation and application of CAA section 111. 
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Excluding demand-side energy efficiency measures from the 

BSER has the benefit of allaying legal and other concerns raised 

by commenters, including concerns that individuals could be 

“swept into” the regulatory process by imposing requirements on 

“every household in the land.”728 While building block 4 could 

have been implemented without imposing requirements on 

individual households, this final rule resolves any doubt on 

this matter and is not based on the inclusion of demand-side 

energy efficiency as part of the BSER. 

 By the same token, we are not finalizing reduced generation 

of electricity overall as the BSER. Instead, components of the 

BSER focus on shifting generation to lower- or zero-emitting 

processes for producing electricity.729 

(e) Constraints for new sources. 

For new sources, practical and policy concerns support the 

interpretation of basing the BSER on controls that new sources 

can install at the time of construction, so that they will be 

well-controlled throughout their long useful lives. This 

 

728 See Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2436 

(2014). 

729 As discussed below, however, reduced generation remains 

important to this rule in that it is one of the methods for 

implementing the building blocks. 
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approach is consistent with the legislative history. We discuss 

this at greater length in the Legal Memorandum. 

4. Relationship between a source’s implementation of building 

blocks 2 and 3 and its emissions. 

In this section, we discuss the relationship between an 

affected EGU’s implementation of the measures in building blocks 

2 and 3 and that affected EGU’s own generation and emissions. As 

discussed above, an affected EGU subject to a CAA section 111(d) 

state plan that imposes an emission rate-based standard may 

achieve that standard in part by implementing the measures in 

building block 2 (for a steam generator) and building block 3 

(for a steam generator or combustion turbine). That is, an 

affected EGU may invest in low- or zero-emitting generation and 

may apply credits from that generation against its emission 

rate. Those credits reduce the affected EGU’s emission rate and 

thereby help it to achieve its emission limit. 

In addition, the additional low- or zero-emitting 

generation that results from the affected EGU’s investment will 

generally displace higher-emitting generation. This is because, 

as described above, higher-emitting generation generally has 

higher variable costs, reflecting its fuel costs, than, at 

least, zero-emitting generation. Displacement of higher-emitting 
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generation will lower overall CO2 emissions from the source 

category of affected EGUs. 

If an affected EGU implements building block 2 or 3 by 

reducing its own generation, it will reduce its own emissions. 

However, the affected EGU may also or alternatively choose to 

implement building block 2 or 3 by investing in lower- or zeroemitting generation that does not, in and of itself, reduce the 

amount of its own generation or emissions. Even so, 

implementation of building blocks 2 and 3 will reduce CO2 from 

some affected EGUs, and therefore reduce CO2 on a source 

category-wide basis. 

This outcome is, however, consistent with the requirements 

of CAA section 111(d)(1) and (a)(1). To reiterate, CAA section 

111(d)(1) requires that “any existing source” have a “standard 

of performance,” defined under CAA section 111(a)(1) as “a 

standard for emissions of air pollutants which reflects the 

degree of emission limitation achievable through the application 

of the best system of emission reduction ... adequately 

demonstrated [BSER] ....” These provisions require by their 

terms that “any existing source” must have a “standard of 

performance,” but nothing in these provisions requires a 

particular amount –- or, for that matter, any amount -- of 

emission reductions from each and every existing source. That 
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the “standard of performance” is defined on the basis of the 

“degree of emission limitation achievable through the 

application of the [BSER]” does not mean that each affected EGU 

must achieve some amount of emission reduction, for the 

following reasons. 

The cornerstone of the definition of the term “standard of 

performance” is the BSER. In determining the BSER, the EPA must 

consider the amount of emission reduction that the system may 

achieve, and must consider the ability of the affected EGUs to 

achieve the emission limits that result from the application of 

the BSER. The EPA is authorized to include in the BSER, for this 

source category, the measures in building blocks 2 and 3 

because, when applied to the source category, these measures 

result in emission standards that may be structured to ensure 

overall emission reductions from the source category and remain 

achievable by the affected EGUs. This remains so regardless of 

whether the “degree of emission limitation achievable through 

the application of the [BSER]” by any particular source results 

in actual emission reductions from that source. 
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2. Legal justification for including emissions trading within 

the BSER. This section provides the legal justification for 

including trading or averaging within the BSER.730 

a. Background information. Emission trading may take one of two 

forms, depending on the form of the emission limitation to which 

the sources are subject. If the emission limitation is an 

emission rate (expressed, for example, in pounds of CO2 per MWh), 

then trading takes the form of buying or selling emission 

reduction credits (ERCs) that an affected EGU may generate if 

its actual emission rate is lower than its allowed emission 

rate. If the emission limitation is a mass-based limit 

(expressed, for example, in the form of a requirement that 

affected EGUs retire one allowance per ton of CO2 emissions), 

then trading takes the form of buying or selling allowances.731 

 (b) Emission trading within the BSER. Emissions trading, as 

applied in this rule, is within the “system of emission 

 

730 For convenience, in this section, references to “trading” 

include both trading and averaging. 

731 It should be noted that for affected EGUs subject to an 

emission rate, the BSER also includes purchase of ERCs from (i) 

existing NGCC units that increase their generation and (ii) 

renewable energy providers for new renewable energy, but 

although these ERCs may also be bought and sold, they are not 

covered by this present discussion of emission trading. Rather, 

this present discussion is focused on the trading of ERCs 

generated by an affected EGU whose actual emission rate is below 

its allowed emission rate, as well as allowances. 
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reduction” that is the “best” because it may operate in 

conjunction with the other types of emission reduction measures 

that are part of the BSER -- the building blocks -- to assure 

that the costs of those measures are lower and are allocated 

among the affected sources. In this final rule, the EPA has 

determined that the affected sources, taken as a whole, are able 

to implement building blocks 1, 2 and 3, and achieve the 

expected level of emission reduction. The EPA recognizes that it 

is not optimally efficient for each affected EGU to attempt to 

implement the measures in each building. Some affected EGUs are 

likely to be able to implement the control measures more costeffectively than other EGUs. Moreover, some EGUs may find it 

more cost-effective to implement other, non-BSER measures to 

reduce emissions, such as demand-side energy efficiency measures 

or co-firing. In addition, some sources may find it advantageous 

to retire. The EPA expects that through any of these avenues, 

some sources will reduce their emissions by more than they are 

required, which would enable them to sell ERCs or allowances 

they no longer need to other affected EGUs whose control costs 

are higher and who would find it advantageous instead to 

purchase the ERCs or allowances. 

In this manner, the opportunity to trade creates incentives 

that have the effect of focusing controls on the sources for 
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which those controls are the most cost-effective.732 The fact 

that emissions trading reduces overall costs is an important 

reason why it must be considered within the “system of emission 

reduction” that is the “best.” In addition, the inclusion of 

trading is feasible and has no adverse impacts on energy 

considerations for the individual affected EGUs or on a 

nationwide basis, nor does it result in emissions of non-air 

quality pollutants. Moreover, trading is especially effective 

for reducing CO2 emissions, due to the ubiquitous nature of CO2 

as a pollutant. 

Of particular importance, a trading program offers an 

affected EGU additional options for achieving its emission rate: 

In addition to implementing control measures to reduce its 

emissions, the source can purchase ERCs or allowances from other 

affected sources. Because under section 111(a)(1), a standard of 

performance is defined, in general, as an emission standard that 

reflects emission limits achievable through the application of 

the BSER, the fact that a source can rely on trading -- 

 

732 In enacting the cap-and-trade provisions of the Title IV Acid 

Rain Program in the 1990 CAA Amendments, Congress explicitly 

recognized that trading reduces overall program costs through 

the mechanism described in the text accompanying this footnote. 

The legislative history explained that the trading program was 

estimated to reduce overall costs by at least 20 percent. Sen. 

Rep. No. 101-228, p. 303 (Dec. 20, 1989). 
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specifically, the acquisition of credits or allowances -- to 

achieve its emission limits, supports treating trading within 

the BSER. 

Trading is well-established, particularly for fossil fuelfired EGUs. As we discuss next, for the past 25 years, Congress 

and the EPA have adopted successful emissions trading programs 

for different air pollutants for these sources. Because trading 

is so well-established, it is reasonable to expect that states 

will allow trading as part of the emission standards they may 

adopt for their CAA section 111(d) state plans. 

Congress enacted the Acid Rain Program in Title IV of the 

1990 CAA Amendments as a nationwide cap–and-trade program for 

fossil fuel-fired EGUs to reduce SO2 emissions. In doing so, 

Congress expressed its understanding that emission trading would 

lower overall costs and assure that all the EGUs subject to the 

requirements would have a mechanism for achieving their emission 

limits. CAA section 401(b) provides: 

It is the intent of this subchapter to effectuate such 

reductions by requiring compliance by affected sources 

with prescribed emission limitations by specified 

deadlines, which limitations may be met through 

alternative methods of compliance provided by an 

emission allocation and transfer system. 

The legislative history elaborates: 

[T]hrough a system of marketable allowances, the 

reduction programs established by the title maximize 
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the range of choices sources have for complying with 

their emissions limitation requirements. An individual 

source may emit more than required if another source 

emits less than it, the latter, is permitted to emit. 

Through this flexibility, the bill minimizes costs and 

maximizes flexibility and efficiency. The EPA 

estimates that this added flexibility could reduce the 

total costs of the program by at least 20 percent. 

On a regional basis, this may allow areas with 

substantial reduction obligations and total costs to 

lower their net costs by producing and selling ‘extra’ 

reductions (i.e., reductions beyond those they are 

required to achieve) to sources seeking to emit more 

than is permitted. At the same time, areas facing 

growth in the energy demand or units with high 

emissions control cost on a per ton basis find that 

purchasing excess emissions reductions from plants in 

other areas, rather than making on-site reductions, 

enables them to comply with their emissions 

limitations at a significantly lower cost. 

Allowing sources to market ‘extra’ emissions 

reductions should also yield important environmental 

benefits as sources will have strong incentives to 

make greater-than-required reductions earlier than 

required. Since sources will enjoy maximum flexibility 

in responding to those incentives, this approach 

should also stimulate innovation in pollution-control 

technology and practices.733

Similarly, in CSAPR, the EPA addressed interstate transport 

of SO2, NOx, and particulate matter emitted by fossil fuel-fired 

EGUs by promulgating a tradable allowance system, and stated as 

follows: 

[T]his [trading] approach provides the most 

flexibility for sources while meeting the [CAA] 

requirements and protecting public health... EPA 

believes that the preferred trading remedy will allow 

source owners to choose among several compliance 

options to achieve required emission reductions in the 

 

733 Sen. Rep. No. 101-228, p. 303 (Dec. 20, 1989). 
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most cost effective manner, such as installing 

controls, changing fuels, reducing utilization, buying 

allowances, or any combination of these actions.734 

As described above in this section, CSAPR is merely the most 

recent in a line of EPA interstate transport rules that took 

into account trading as a method for EGUs to reduce emissions. 

For example, the NOX SIP Call set state budgets based on a 

uniform emission standard for EGUs in part because those 

standards were “based on the adoption of a broad-based trading 

program” that would allow sources with higher marginal costs to 

more cost-effectively comply.735 Similarly, in CAIR, the EPA set 

state budgets based on cost-effective controls on EGUs and, in 

evaluating the cost impacts, “assume[d] interstate emissions 

trading” because of the reasonable likelihood that states and 

EGUs would use trading as the way to meet emission 

requirements.736 

By the same token, in the 2005 rulemaking the EPA 

promulgated under CAA section 111(d) to control mercury 

emissions from affected EGUs -- the CAMR -- the EPA identified a 

nationwide cap-and-trade program as part of the BSER, along with 

add-on controls to reduce mercury emissions. The EPA projected 

 

734 76 Fed. Reg. at 48272. 735 63 Fed. Reg. 57356, 57399 (Oct. 27, 1998). 736 70 Fed. Reg. 25162, 25196 (May 12, 2005). 
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that with a cap-and-trade program, mercury reductions would 

“result from units that are most cost effective to control, 

which enables those units that are not cost effective to use 

other approaches for compliance including buying allowances, 

switching fuels, or making dispatch changes.”737 This program 

enabled the EPA to set the cap’s stringency at a level 

commensurate with widespread compliance, whereas if the cap were 

based solely on the installation of control technologies, the 

cap would not be cost-effective for the source category.738 

In establishing the Title IV trading program, Congress 

recognized that fossil fuel-fired EGUs are well-suited to engage 

in emission trading: “[B]y their business nature,” Congress 

explained, “utilities appear to be well-suited to create, and to 

take advantage of, an active market in emissions allowances.”739

In fact, Congress added, “utilities already engage in powerpooling arrangements to ensure maximum flexibility and 

 

737 70 Fed. Reg. 28606, 28619 (May 18, 2005). 738 In addition, in a 1995 rulemaking for municipal solid waste 

incinerators, the EPA also authorized states to allow large 

municipal waste combustors to average their emission rates and 

trade NOx emission credits. “Standards of Performance for New 

Stationary Sources and Emission Guidelines for Existing Sources; 

Municipal Waste Combustors,” 60 Fed. Reg. 65,387 at 28616-24, 

(Dec. 19, 1995). 

739 Sen. Rep. No. 101-228, at 319 (Dec. 20, 1989). 
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efficiency in supplying power.”740 Moreover, Congress added, the 

allowance system enabled parties to “transfer between them and 

among themselves pursuant to a wide variety of commercial 

agreements such as under leases, sales agreements and exchanges 

between emissions and electric power or capacity.”741

The Energy Information Agency of the Department of Energy, 

in its annual report on electric power for the year 2000, noted 

that allowance purchases were one of the means by which the EGUs 

achieved their Title IV emission limits: 

On January 1, 2000, the electric industry came under 

Phase II regulations of the [CAA] Amendments of 1990. 

This Act was primarily designed to reduce power plant 

emissions, specifically sulfur dioxide and nitrogen 

oxides. Phase I, which began on January 1, 1995, 

affected 435 generating units and allowed the release 

of 2.5 pounds of sulfur dioxide per each million Btu 

of fuel consumed. Under Phase II, coverage increased 

to more than 2,000 units, while restrictions on 

emissions were set at 1.2 pounds of sulfur dioxide per 

million Btu of fuel consumed. Since 1995, some 

generators have over complied with Phase I in order to 

create excess allowances. This has allowed them to 

delay enacting additional strategies that would be 

necessary for compliance with Phase II. Strategies 

that are being used for compliance include fuel 

switching/ blending, co-firing with natural gas, 

allowance acquisitions, scrubbers, repowering, and 

plant retirements.742

 

740 Sen. Rep. No. 101-228, at 319 (Dec. 20, 1989). 741 Sen. Rep. No. 101-228, at 320 (Dec. 20, 1989). 742 EIA, “Electric Power Annual 2000,” vol. 1 (August 2001) 13 

http://www.eia.gov/electricity/annual/archive/vol1/0348001.pdf 

(emphasis added, citations omitted). 
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In addition, beginning in 1998, the EPA has promulgated 

allowance trading programs in a series of rulemakings to reduce 

interstate transport in the eastern part of the U.S. of SO2, NOx, 

and particulate matter emissions from fossil fuel-fired EGUs in 

upwind states that jeopardize the ability of downwind states to 

attain and maintain the NAAQS.743 States and the EPA have 

implemented those requirements through SIPs and FIPs under CAA 

section 110. 

In addition, states have adopted allowance-based trading 

programs to control CO2 emissions from fossil fired EGUs.744 These 

programs have established the structural components of a trading 

program, including mechanisms to allocate allowances and track 

their ownership and use, and have operated trading programs, and 

have thereby demonstrated that a trading program for CO2

emissions from fossil fuel-fired EGUs can operate effectively. 

It should also be noted that states have adopted other 

emission trading programs -- both rate-based trading programs 

and allowance trading programs -- that control a range of 

 

743 For the NOx SIP Call, see 63 Fed. Reg. 57,356, XXXXX (Oct. 27, 

1998). For CAIR, see 70 Fed. Reg. 25,162, XXXXX (May 12, 2005) 

(Clean Air Interstate Rule); For CSAPR, see 76 Fed. Reg. 48,208 

XXXX (Aug. 8, 2011) (Cross-State Air Pollution Rule). 

744 The RGGI program regulates CO2 from fossil fuel-fired EGUs. 

The California AB32 program regulates CO2 from fossil fuel-fired 

EGUs and other sources. 
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emissions from a range of sources. In some cases, these state 

programs have been included as part of SIPs and the EPA has 

approved them. For example, the South Coast Air Quality 

Management District adopted the Regional Clean Air Incentives 

Market (RECLAIM) program in October 1993 to establish a NOx and 

SOx emissions cap-and-trade program in the South Coast air basin. 

RECLAIM, which is codified in SCAQMD Regulation XX (Rules 2000 

through 2020), generally applies to stationary sources that emit 

4 tons or more per year of NOx or SOx in the year 1990 or 

subsequent years and establishes emissions caps for NOx and SOx

that decline over time. The program was designed to provide 

sources with incentives to reduce emissions and advance 

pollution control technologies by giving sources added 

flexibility in meeting emission reduction requirements.745 The 

EPA approved RECLAIM as a discretionary Economic Incentive 

program in June, 1998.746 The EPA has issued comprehensive 

guidance to states for adopting emission trading programs.747 

 

745 See http://www.aqmd.gov/home/programs/business/businessdetail?title=reclaim. 

746 63 FR 32621 (June 15, 1998). 747 Environmental Protection Agency, Office of Air and Radiation, 

“Improving Air Quality with Economic Incentive Programs,” EPA452/R-01-001 (2001). 

http://www.epa.gov/airquality/advance/pdfs/eipfin.pdf 
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3The application of the building blocks has an impact that 

is similar to that of an emissions trading program, under which, 

overall, the affected sources reduce emissions, but any 

particular source does not need to reduce its emissions and, in 

fact, may increase its emissions, as long as it purchases 

sufficient credits or allowances from other sources. In fact, we 

expect that that many states will carry out their obligations 

under this rule by imposing standards of performance that 

incorporate trading or other multi-entity generation-replacement 

strategies. Indeed, any emission rate-based standard may not 

necessarily result in emission reductions from any particular 

affected source (or even all of the affected sources in the 

category) as a result of the ability of the particular source 

(or even all of them) to increase its production and, therefore, 

its emissions, even while maintaining the required emission 

rate. 

5. Reduced generation and implementation of the BSER 

In the proposed rulemaking, we described the BSER as the 

measures included in building block 1 as well the set of 

measures included in building blocks 2, 3 and 4 or, in the 

alternative, reduced generation or utilization by the affected 

EGUs in the amount of building blocks 2, 3 and 4. In this final 

rule, based on the comments and further evaluation, we are 
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refining our approach to the BSER. Specifically, viewing the 

BSER through either the source-category perspective or the 

source-specific perspective, we are determining the BSER as the 

measures included in building block 1, as well as the set of 

combination of measures included in building blocks 1, 2, and 3, 

which incorporate reduced generation, along with the 

purchase.Building blocks 2 and 3 entail substitution of emission 

reduction credits or allowances. Reducedlower-emitting 

generation for higher-emitting generation qualifies as part of 

the BSER because of the unique characteristics of this industry, 

which tie it closely, which ensures that aggregate production 

levels can continue to the measures in building blocks 2 and 3. 

meet demand even where an individual affected EGU decreases its 

own output to reduce emissions. The amount of generation from 

the increased utilization of existing NGCC units would 

determinedetermines a portion of the amount of thereduced

generation reduction component of the BSER for that affected 

fossil fuel-fired steam EGUs could undertake to achieve building 

block 2, and the amount of generation from the use of expanded 

renewable energylower- or zero-emitting generating capacity that 

could be provided, would determinedetermines a portion of the 

amount of thereduced generation reduction component of the BSER 

for allthat affected fossil fuel-fired steam EGUs. , as well as 
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the entire amount of reduced generation that affected NGCC units 

could undertake to implement building blocks 2 and 3. This 

section discusses whythe reasons that reduced generation is a 

partone of the set of reasonable and well-established actions 

that an affected EGU can implement to achieve its emission 

limits. We are not finalizing our proposal that reduced overall 

generation of electricity may by itself be considered the BSER, 

for the reason that reduced generation by itself does not fit 

within our historical and current interpretation of the BSER. 

Specifically, reduced generation by itself is about changing the 

amount of the BSER under this formulation.product produced 

rather than producing the same product with a process that has 

fewer emissions. 

a. Background. As noted, for both rate-based and allowancemassbased state plans, affected EGUs may take a set of actions to 

comply with their emission standards. An affected EGU may comply 

with an emission rate-based standard (e.g., a limit on the 

amount of pounds of CO2 per MWh) by acquiring, through one means 

or another, credits from lower- or zero-emitting generation 

(building blocks 2 or 3, respectively) to reduce its actual 

emission rate. for compliance purposes. In addition, the 

affected EGU may reduce its generation, and if it does so, it 

then needs to acquire fewer of those credits to meet its 
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emission rate.748 Under these circumstances, the affected EGU 

would in effect replace part of its higher -emitting generation 

with lower- or zero-emitting generation. On the other hand, an 

affected EGU that is subject to an allowance a mass-based 

standard -- for example, a requirement -- under which it mustto

hold enough allowances to cover its emissions (e.g., one 

allowance for each ton of emissions in any year) -- may comply 

at least in part by reducing its generation and, thus, its 

emissions. Therefore, one type of action that an affected EGU 

may take to achieve either of these emission limits is to reduce 

its generation. 

Reduced generation is part of the BSER for affected EGUs 

for the following reasons, which generally must be understood 

against the backdrop of the integrated power sector: First, it 

is part of a “system of emission reduction” within the meaning 

of the BSER provisions because it is an action within the 

control of an affected EGU that reduces emissions. Indeed, it is 

a commonly used method for fossil fuel-fired EGUs to meet CAA 

 

748 An affected EGU that is subject to an emission rate, e.g., 

pounds of CO2 per MWh generated, cannot achieve that rate simply 

by reducing its generation (unless it shuts down, in which case 

it would achieve a zero emission rate). This is because although 

reducing generation results in fewer emissions, it does not, by 

itself, result in fewer emissions per MWh generated.
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obligations. Both Congress and the EPA have relied on it in 

establishing other CAA obligations, and there are wellestablished mechanisms for implementing it. Second, it meets the 

other components of the definition of BSER because it is 

feasible, results in fewer emissions, is of reasonable cost, 

does not have adverse implications for energy or non-air quality 

pollutants, and is adequately demonstrated. Third, in the 

context of this rule, it would lead to cleaner forms of 

generation and would not result in adverse impacts on the 

utility power sector. 

b. System of emission reduction. Reduced generation is part of 

the “system of emission reduction” under CAA section 111(d)(1) 

and (a)(1) for this industry. Reduced generation is encompassed 

by the terms of the phrase “system of emission reduction” in CAA 

section 111(a)(1), as a matter of Chevron step 1, because, in 

accordance with the above-discussed definition of 

“system,”Further, reduced generation is a “set of things” == 

which include reduced use of generating equipment and therefore 

reduced fuel input == that the affected EGU may by individual 

sources offers a pathway to compliance in and of itself take. 

That is, a state may adopt a mass-based goal, assign mass-based 

standards to reduce its CO2 emissions. If that phrase is not 

considered clear by its terms, then, under Chevron step 2, 
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itsources, and those sources may reasonably be interpretedcomply 

with their mass-based limits by, in addition to include reduced 

generation. As noted above, to achieve its emission standard, an 

affected EGU subject to an emission rate must combine reduced 

generation with the acquisition of sufficient emission reduction 

credits (so that it is, in effect, replacing its higher emitting 

generation with low- or zero-emitting generation), and an 

affected EGU subject to an allowance requirement must acquire 

sufficient allowances to cover its remaining 

emissions.implementing building block 1 measures, reducing their 

generation in the appropriate amounts, and without taking any 

other actions. 

b. Well-established use of reduced generation to comply with 

environmental requirements. Reduced generation is a wellestablished method for individual fossil fuel-fired power plants 

to comply with their emission limits. 

 Reduced generation in the amounts contemplated in this 

rule, as undertaken by individual sources to achieve their 

emission limits, reduces emissions from the affected sources, 

but because of the integrated and interconnected nature of the 

power sector, can be accommodated without significant cost or 

disruption. The electric transmission grid interconnects the 

nation’s generation resources over large regions. Electric 
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system operators coordinate, control, and monitor the electric 

transmission grid to ensure cost-effective and reliable delivery 

of power. These system operators constantlycontinuously balance 

electricity supply and demand, ensuring that needed generation 

and/or demand resources are available to meet electricity 

demand. Diverse resources generate electricity that is 

transmitted and distributed through a complex system of 

interconnected components to end-use consumers. 

The electricity system was designed to meet these core 

functions. The three components of the electricity supply system 

-- generation, transmission and distribution -- coordinate to 

deliver electricity from the point of generation to the point of 

consumption. This interconnectedness is a fundamental aspect of 

the nation’s electricity system, requiring a complicated 

integration of all components of the system to balance supply 

and demand and a federal, state and local regulatory network to 

oversee the physically interconnected network. Electricity from 

a diverse set of generation resources such as natural gas, 

nuclear, coal and renewables is distributed over high-voltage 

transmission lines. The system is planned and designedoperated

to ensure that there are adequate resources to meet electricity 

demand plus additional available capacity over and above the 

capacity needed to meet normal peak demand levels. System 
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operators have a number of resources potentially available to 

meet electricity demand, including electricity generated by 

electric generation units such as coal, nuclear, renewables and 

natural gas,of various types as well as demand-side resources. 

IfImportantly, if generation is reduced from one generator, 

safeguards are in place to ensure that adequate supply is still 

available to meet demand. We describe these safeguards in the 

background section of this preamble.

Both Congress and the EPA have recognized reduced 

generation as one of the measures that fossil fuel-fired EGUs 

may implement to reduce their emissions of air pollutants and 

thereby achieve emission limits. Congress, in enacting the 

allowance requirements in CAA Title IV, under which fossil fuelfired EGUs must hold an allowance for each ton of SO2 emitted, 

explicitly recognized that fossil fuel-fired EGUs could meet 

this requirement by reducing their generation. In fact, Congress 

anticipated that fossil fuel-fired EGUs may choose to comply 

with the SO2 emission limits by reducing utilization, and 

included provisions that specifically addressed reduced 

utilization. For example, CAA section 408(c)(1)(B) includes 

requirements for an owner or operator of an EGU that meets the 

Phase 1 SO2 reduction obligations and the NOx reduction 
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obligations “by reducing utilization of the unit as compared 

with its baseline or by shutting down the unit.” 

The EPA has also recognized in several rulemakings limiting 

emissions from fossil fuel-fired EGUs that reduced generation is 

one of the methods of emission reduction that the EGUs werean 

EGU was expected to rely on to achieve theirits emission 

limitations. One example is includesExamples include rulemakings 

to impose requirements that sources implement BART to reduce 

their emissions of air pollutants that cause or contribute to 

visibility impairment. As explained earlier, for certain older 

stationary sources that cause or contribute to visibility 

impairment, including fossil fuel-fired EGUs, states must 

determine BART on the basis of five statutory factors, such as 

costs and energy and non-air quality impacts.749 In 1980, the EPA 

promulgated a regulatory definition of BART: “an emission 

limitation based on the degree of reduction achievable through 

the best system of continuous emission reduction for each 

pollutant which is emitted by an existing stationary 

facility.”750 Both the statutory factors and the regulatory 

definition resemble the definition of the BSER under CAA section 

111(a)(1). In their regional haze SIPs, several states 

 

749 CAA section 169A(g)(2). 750 40 C.F.R. §CFR 51.301. 
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determined that BART included reduced generation, in the form of 

either capacity limitations or plant closures. For example, the 

State of Oklahoma determined that BART for the SO2 emissions from 

two coal-fired boilers at a power plant contained several 

elements, including “interim emission limits, the installation 

of Dry Sorbent Injection (DSI) and a fabric filter baghouse, 

phased reductions in capacity utilization, and enforceable 

deadlines by which [the boilers] must be shut down entirely.”751

Similarly) (although, as noted, the statutory definition of BART 

is more technology focused than the definition of BSER). In its 

regional haze SIP, the State of New York determined that BART 

for the NOX emissions from two coal-fired boilers that served as 

peaking units was caps on baseline emissions rates and annual 

capacity factors of 5 percent and 10 percent, respectively.752 

There have been numerous other instances in which fossil 

fuel-fired EGUs have reduced their individual generation, or 

placed limits on their generation, in order to achieve, or 

obviate, emission standards. In fact, it is common for 

thesethere are numerous examples of EGUs tothat take 

restrictions on hours of operation in their permits for the 

purpose of avoiding CAA obligations, including avoiding 

 

751 78 FR 51,686, 51,690 (Aug. 21, 2013) (emphases added). 752 77 Fed. Reg. 24,794, 24,810FR 24794, 24810 (Apr. 25, 2012). 
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triggering the requirements of the Prevention of Significant 

Deterioration (PSD), Nonattainment New Source Review (NNSR), or 

Title V programs (including Title V fees), and avoiding 

triggering HAPsHAP requirements. Such restrictions may also be 

taken to limit emissions of pollutants, such as limiting 

emissions of criteria pollutants for attainment purposes. 

More specifically, EPA’s regulations for a number of air 

programs expressly recognize that certain sources may take 

enforceable limits on hours of operation in order to avoid 

triggering CAA obligations that would otherwise apply to the 

source. Stationary sources that emit or have the potential to 

emit a pollutant at a level that is equal to or greater than 

specified thresholds are subject to major source requirements.753

A source may voluntarily obtain a synthetic minor limitation –- 

that is, a legally and practicably enforceable restriction that 

has the effect of limiting emissions below the relevant level -- 

to avoid triggering a major stationary source requirement. 754

 

753 See, e.g., CAA sections 112(a)(1), 112(d)(1), 165(a), 169(1), 

172(c)(5), 173(a) &(c), 501(2), 502(a), 302(j). 

754 See, e.g., Memorandum from Terrell Hunt, Assoc. Enforcement 

Counsel, U.S. EPA, & John Seitz, Director, Stationary Source 

Compliance Div., U.S. EPA, Guidance on Limiting Potential to 

Emit in New Source Permitting, at 1-2, 6 (June 13, 1989), 

available at 

http://www.epa.gov/region07/air/nsr/nsrmemos/lmitpotl.pdfhttp://

www.epa.gov/region07/air/nsr/nsrmemos/lmitpotl.pdf
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Such synthetic minor limits may be based on restrictions on the 

hours of operation, as provided in EPA’s regulations defining 

“potential to emit,” as well as on air pollution control 

equipment. “Potential to emit” is defined, for instance, in the 

regulations for the PSD program for permits issued under federal 

authority as: “the maximum capacity of a stationary source to 

emit a pollutant under its physical and operational design. Any 

physical or operational limitation on the capacity of the source 

to emit a pollutant, including air pollution control equipment 

and restrictions on hours of operation ... shall be treated as 

part of its design if the limitation or the effect it would have 

on emissions is federally enforceable,”755 or “legally and 

practicably enforceable by a state or local air pollution 

control agency." .”756 The regulations for other air programs 

similarly recognize that potential to emit may be limited 

 

(“Restrictions on production or operation that will limit 

potential to emit include limitations on quantities of raw 

materials consumed, fuel combusted, hours of operation, or 

conditions which specify that the source must install and 

maintain controls that reduce emissions to a specified emission 

rate or to a specified efficiency level.”) (emphasis added). 

755 40 CFR 52.21(b)(4)(emphasis added). 756 John Seitz, Director, Office of Air Quality Planning and 

Standards, and Robert Van Heuvelen, Director, Office of 

Regulatory Enforcement, Release of Interim Policy on Federal 

Enforceability of Limitations on Potential to Emit, at 3 (Jan. 

22, 1996), available at 

http://www.epa.gov/region07/air/nsr/nsrmemos/pottoemi.pdf. 
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through restrictions on hours of operations in their 

corresponding definitions of “potential to emit.”757 These 

regulatory provisions make clear that restrictions on potential 

to emit include both “air pollution control equipment” and 

“restrictions on hours of operation,” and indicate that these 

are equally cognizable means of restricting emissions to comply 

with, or avoid, CAA requirements.758

As one of many examples of a fossil-fuel fired EGU taking 

restrictions on hours of operation for the purpose of avoiding 

CAA obligations, Manitowoc Public Utilities in Wisconsin 

obtained a titleTitle V renewal permit that limited the 

operating hours of the single simple-cycle combustion turbine to 

not more than 194 hours per month, averaged over any consecutive 

12 month period, as part of limiting its potential to emit for 

volatile organic compounds below the titleTitle V threshold of 

100 tpy, and carbon monoxide, nitrogen oxides and sulfur dioxide 

below the PSD threshold of 250 tpy.759 As another example, 

 

757 See 40 CFR 51.166(b)(4) (addressing SIP approved PSD 

programs), 51.165(a)(1)(iii) (addressing SIP approved NNSR 

programs), 70.2 (addressing titleTitle V operating permit 

programs), and 63.2 (addressing hazardous air pollutants). 

758 See, e.g., 40 CFR 52.21(b)(4). 759 See Final Operation Permit No. 436123380-P10 for Manitowoc 

Public Utilities --- Custer Street (Wis. Dept. Nat. Res., 

8/19/2013), Condition ZZZ.1.a(1) at p. 9 (Limiting potential to 

emit) and n. 11 (“These conditions are established so that the 
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Sunbury Generation LP in Pennsylvania obtained a minor new 

source preconstruction permit, called a plan approval, for a 

repowering project from the Pennsylvania Department of 

Environmental Protection in 2013 that limited the hours of 

operation of three combined cycle combustion turbines that were 

planned for construction in order to remain below the 

significance threshold for GHGs.760 The Legal Memorandum includes 

numerous other examples of power plants accepting permit limits 

 

potential emissions for volatile organic compounds will not 

exceed 99 tons per year and potential emissions for carbon 

monoxide, nitrogen oxides and sulfur dioxide emissions from the 

facility will not exceed 249 tons per year.”). See also Analysis 

and Preliminary Determination for the Renewal of Operation 

Permit 436123380-P01 (Wis. Dept. Nat. Res., 5/21/2013) at p. 5 

(noting that the “existing facility is a major source under Part 

70 because potential emissions of sulfur dioxide, nitrogen 

oxides and carbon monoxide exceed 100 tons per year. The 

existing facility is a minor source under PSD and an area source 

of federal HAP” and further noting that after renewal, “the 

facility will continue to be a major source under Part 70 

because potential emissions of sulfur dioxide, nitrogen oxides 

and carbon monoxide exceed 100 tons per year. The facility will 

also continue to be a minor source under PSD and an area source 

of federal HAP.”). 

760 See Plan Approval No. 55-00001E for Sunbury Generation LP 

(Pa. Dept. Env. Protection, 4/1/2013), Conditions #016 on pp. 

24, 32 and 40 (limiting turbine units to operating no more than 

7955, 6920, or 8275 hours in any 12 consecutive month period 

depending on which of three turbine options was selected); 

Memorandum from J. Piktel to M. Zaman, Addendum to Application 

Review Memo for the Repowering Project (Pa. Dept. Env. 

Protection, 4/1/2013) at p. 2 of 10 (noting that source had 

“calculated a maximum hours per year (12 consecutive month 

period) of operation for the sources proposed for each of the 

turbine options in order to remain below the significance 

threshold for GHGs.”). 
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that reduce generation to meet, or avoid the need to meet, 

emission limits.

There are several ways that an affected EGU may implement 

reduced utilizationgeneration. For example, an EGU may accept a 

permit requirement that specifically limits its operating hours. 

In addition, an EGU may treat the cost of its generation as 

including an additional amount associated with environmental 

impacts, which requires it to raise its bid price, so that the 

EGU is dispatched less].. 

c. Other BSER requirements and considerations. Reduced 

generation meets the criteria to be considered part of the 

“best” system of emission reduction that is “adequately 

demonstrated.” It is a feasible method of emission control 

because an affected EGU may reduce its generation by operating 

fewer hours, and may implement reduced generation through the 

methods just described. In addition, reduced generation results 

in fewer emissions, is of reasonable cost, and does not have 

adverse implications for energy use at the affected EGUs or 

result in non-air quality pollutants. 

Furthermore, reduced generation as a means for fossil fuelfired EGUs to reduce emissions is adequately demonstrated. As 

noted above, Congress recognized its use in enacting Title IV, 

the EPA has established emission limits in other rulemakings 
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based in part these EGUs’ ability to achieve those limits by 

reducing generation, and in numerous instances, these EGUs have 

accepted limits on their generation in permits. 

At the levels proposed, these measuresc. Other aspects of 

reduced generation. The amounts of increased existing NGCC 

generation and new renewables, in the amounts reflected in 

building blocks 2 and 3, can be substituted for generation at 

affected EGUs at reasonable cost. The NGCC capacity necessary to 

accomplish the levels of generation reduction proposed for 

building block 2 is already in operation or under construction. 

Moreover, it is reasonable to expect that the incremental 

resources reflected in building block 3 will develop at the 

levels requisite to ensure an adequate and reliable supply of 

electricity at the same time that affected EGUs may choose or be 

required to reduce their CO2 emissions by means of reducing their 

generation.761

 

761 It should be noted that in light of the low current and 

projected near term prices for natural gas, market forces may 

lead investors to choose to build new NGCC units, rather than 

new renewable resources. This result would not call into 

question the technical feasibility of a BSER that included 

reductions in fossil fuel-fired generation by the amount of a 

specified amount of new renewable resources. This is because 

under these circumstances, the fossil fuel-fired generators 

could still reduce their generation without causing reliability 

or other problems in the electric power system. 
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d. Impacts on utility power sector. Reduced generation by 

affected EGUs, in the amounts that affected EGUs may rely on to 

comply with this ruleimplement the selected building blocks, 

will not have adverse effects on the utility power sector. and 

will not reduce overall electricity generation. In light of the 

emission limits of this rule, because of the availability of the 

measures in building blocks 2 and 3, and because the grid is 

interconnected and the electricity system is highly planned, 

reductions in generation by fossil fuel-fired EGUs in the amount 

contemplated under this ruleif they were to implement the 

building blocks, and occurring over the lengthy time frames 

provided under this rule, will result in replacement generation 

that generally is lower- or zero- emitting. Mechanisms are in 

place in both regulated and deregulated electricity markets to 

assure that substitute generation will become available and/or 

steps to reduce demand will be taken to compensate for reduced 

generation by affected EGUs. As a result, reduced generation 

will not give rise to reliability concerns or have other adverse 

effects on the utility power sector. Because of the availability 

of the measures in building blocks 2 and 3, the proposed levels 

of reduced generation and are of reasonable cost for the 

affected source category and the nationwide electricity system, 

do not jeopardize reliability, and result in the appropriate 
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amount of emission reductions..762 All these results come about 

because the operation of the electrical grid through integrated 

generation, transmission, and distribution networks creates 

fungibilitysubstitutability for electricity and electricity 

services, which allows decreases in generation at affected 

fossil fuel-fired steam EGUs to be replaced by increases in 

generation at affected NGCC units (building block 2) and allows 

decreases in generation at all affected EGUs to be replaced by 

increased generation at new lower- and zero-emitting EGUs 

(building block 3)). Further, this fungibilitysubstitutability

increases over longer timeframes with the opportunity to invest 

in infrastructure improvements, and as noted elsewhere, this 

rule provides an extended state plan and source compliance 

 

762 Although, as discussed in the text in this section of the 

preamble, we are not treating reduced overall generation of 

electricity as the BSER (because it does not meet our historical 

and current approach of defining the BSER to include methods 

that allow the same amount of production but with a loweremitting process) we note that reduced generation by individual 

higher-emitting EGUs to implement building blocks 2 and 3 meets 

the following criteria for the BSER: as the examples in the text 

and in the Legal Memorandum make clear, reduced generation is 

“adequately demonstrated” as a method of reducing emissions 

(because Congress and the EPA have recognized it and on numerous 

occasions, power plants have relied on it); it is of reasonable 

cost; it does not have adverse effects on energy requirements at 

the level of the individual affected source (because it does not 

require additional energy usage by the source) or the source 

category or the U.S.; and it does not create adverse 

environmental problems. 
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horizon. These characteristics of the integrated electricity 

system assure that reduced generation in specified amounts meets 

the criteria to qualify as the “best” system of emission 

reduction.

ed. Comments concerning limiting principles. A commenter stated 

that “an interpretation of [‘system of emission reduction’] that 

relies primarily on reduced utilization has no clear limiting 

principle.”763 We disagree with this concern, for the following 

reasons. 

As discussed, in this final rule, we are identifying the 

BSER as the combination of the three building blocks. 

BuildingsBuilding blocks 2 and 3 entail substitution of loweror zero-emitting generation for higher-emitting generation, and 

aone component of that substitution is reduced generation, which 

is limited in several respects discussed below. Accordingly, our 

identification of the BSER in this final rule does not “rel[y] 

primarily” on reduced utilization as the BSER. 

Moreover, as also discussed, building blocks 2 in and 3, as 

well as of itself (and therefore reduced generation, meet the 

requirements for of the product overall, electricity) as the 

BSER. Rather, the BSER, and therefore may serve as the basis for 

 

763 EEI comment, at 284. 
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the emission guidelines in this rule is, in accordance with CAA 

section 111(d)(addition to building block 1) and (a)(1). By, the 

same token, reducedsubstitution of lower- or zero-emitting

generation for higher emitting generation, and reduced 

utilization may be a way to implement that substitution and is 

one of severalnumerous methods that affected EGUs may employ to 

achieve or help achieve the emission limits established by these 

emission guidelines.764 The commenter’s concerns over a perceived 

 

764 Indeed, load shifting -- as substitute generation is 

sometimes called -- is an “easy and fairly inexpensive strategy” 

that “may be used in conjunction with other control measures” 

for “emission reduction.” Donald S. Shepard, “A Load Shifting 

Model for Air Pollution Control in the Electric Power Industry,” 

Journal of the Air Pollution Control Association, Vol. 20, No. 

11, p. 760 (Nov. 1970). In fact, load shifting has been 

recognized as a pollution control technique as early as 1968, 

when it was included in the “Chicago Air Pollution System Model” 

for controlling incidents of extremely high pollution. E.J. 

Croke, et al., “Chicago Air Pollution System Model, Third 

Quarterly Progress Report,” Chicago Department of Air Pollution 

Control, p. 186 (1968) (discussing the feasibility of “Control 

by Load Reduction” in combination with load shifting as applied 

to the Commonwealth Edison Company), available at 

http://www.osti.gov/scitech/servlets/purl/4827809. The report also considered 

“combining fuel switching and load reduction” as a possible air 

pollution abatement technique. See id. at 188. The report 

recognized, as an initial matter, that the Commonwealth Edison 

Company (CECO) was “constrained to meet the total load demand” 

but that “load reduction at one plant or even a number of plants 

is usually feasible by shifting the power demand to other plants 

in the system.” Id. As a result, the report noted, “load 

shifting within the physical limits of the CECO system ... may 

be a highly desirable control mechanism.” Id. The report also 

predicted that “[i]n the future, it may be possible to form 

reciprocal agreements to obtain ‘pollution abatement’ power from 
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lack of a limiting principle cannot be taken to mean that 

reduced generation by higher-emitting EGUs cannot be considered 

to be a component of the BSER or constitute a method for 

affected EGUs to achieve their emission limits.

Moreover, reduced generation, as applied to affected EGUs 

in this rule, is limited in a number of respects. The amount of 

reduced generation is prescribed. It is the amount of 

replacement generation that is lower- or zero- emitting, that is 

of reasonable cost, that can be generated without jeopardizing 

reliability, and that meets the other requirements for the BSER. 

As discussed, that amount is the amount of generation in 

building blocks 2 and 3.765

MoreoverFinally, as discussed, the integrated nature of the 

electricity system, coupled with the high substitutability of 

electricity, allows EGUs to reduce their generation without 

adversely affecting the availability of their product. Those 

characteristics facilitate replacement of generation that has 

 

neighbor companies during a pollution incident and return this 

borrowed power at some later date.” Id. at 187. 765 The EPA notes that affected EGUs are not actually required to 

collectively reduce generation by the amount represented in the 

BSER, and may collectively reduce generation by more or less 

than that amount. Individual affected EGUs are free to choose 

reduced generation or other means of reducing emissions, as 

permitted by their state plans, in order to achieve the 

standards of performance established for them by their states. 
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been reduced, and for that reason, EGUs have a long history of 

reducing their generation and either replacing it directly or 

having it replaced through the operation of the interconnected 

electricity system through measures similar to those in building 

blocks 2 and 3. Thus, an EGU can either directly replace its 

generation, or simply reduce its generation, and in the latter 

case, the integrated grid, combined with the high degree of 

planning and various reliability safeguards, will result in 

entities providing replacement generation. This means that 

consumers receive exactly the same amount of the same product, 

electricity, after the reduced generation that they received 

before it. No other industry is both physically interconnected 

in this manner and manufactures such a highly substitutable 

product; as a result, the use of reduced generation as a “system 

of emission reduction” is not easily transferrable to another 

industry. 

 4. The EPA authority to determine the BSER. In this 

section, we explain why the EPA, and not the states, has the 

authority to determine the BSER and, therefore, the amount6. of 

emission limitation required from the existing sources in the 

source category in section 111(d) rulemaking and the associated 

state plans. 
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CAA section 111(d)(1) requires the EPA to establish a 

section 110-like procedure under which each state submits a plan 

that “establishes standards of performance for any existing 

source of air pollutant” and “provides for the implementation 

and enforcement of such standards of performance.” As CAA 

section 111(d) was originally adopted, in the 1970 CAA 

Amendments, state plans were required to establish “emission 

standards” -- an undefined term -- rather than “standards of 

performance,” a term that was limited to CAA section 111(b).766

Prior to this change, however, the EPA issued regulations 

implementing CAA section 111(d) in 1975.767 These regulations 

established a cooperative framework, similar to that under CAA 

section 110, where the EPA first develops “emission guidelines” 

for source categories -- defined as a final guideline document 

reflecting “the degree of emission reduction achievable through 

the application of the best system of emission reduction which 

... the Administrator has determined has been adequately 

demonstrated” -- and states then submit implementation plans to 

regulate any existing sources.768 

 

766 See “Clean Air Act Amendments of 1970,” Pub. L. 91-604, § 4, 

84 Stat. 1676, 1683-84 (Dec. 31, 1970). 

767 See “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53,340 (Nov. 17, 1975). 

768 See ”State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 F.R. 53340 (Nov. 17, 1975). 
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The 1975 implementing regulations carefully considered the 

allocation of responsibilities as between the EPA and the states 

in regulatory actions under CAA section 111(d), and concluded 

that the EPA had the responsibility of determining the amount of 

emission limitation from the source category, while the states 

had the responsibility of assigning emission requirements to 

their sources that assured that amount of emission limitation. 

In issuing the regulations, the EPA explained “that some 

substantive criterion was intended to govern not only the 

Administrator’s promulgation of standards but also [her] review 

of state plans.”769 The EPA added, “it would make no sense to 

interpret [CAA] section 111(d) as requiring the Administrator to 

base approval or disapproval of state plans solely on procedural 

criteria. Under that interpretation, states could set extremely 

lenient standards -- even standards permitting greatly increased 

emissions -- so long as [the] EPA’s procedural requirements were 

met.”770 The EPA concluded that “emission guidelines, each of 

which will be subjected to public comment before final adoption, 

will serve [the] function” of providing substantive criteria “in 

 

769 “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340, 53342 (Nov. 17, 1975). 

770 “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340, 53343 (Nov. 17, 1975). 
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advance to the states, to industry, and to the general public” 

to aid states in “developing and enforcing control plans under 

[CAA] section 111(d).”771

In 1977, Congress revised CAA section 111(d) to require 

that the states adopt “standards of performance,” as defined 

under CAA section 111(a)(1). Currently, standards of performance 

are defined as “a standard for emissions of air pollutants which 

reflects the degree of emission limitation achievable through 

the application of the best system of emission reduction which 

... the Administrator determines has been adequately 

demonstrated.” (Emphasis added.)772 By its terms, this provision 

provides that the EPA has the responsibility of determining 

whether the “best system of emission reduction” is “adequately 

demonstrated.” While this provision does not explicitly assign 

the responsibility to the EPA of identifying the “best system of 

emission reduction” in the first instance to the EPA, it is a 

logical inference that Congress intended that interpretation in 

 

771 “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340, 53343 (Nov. 17, 1975). 

772 As noted, the 1977 version of CAA section 111(a)(1) differed 

from the current version, which was adopted in the 1990 CAA 

Amendments, but those differences do not call into the question 

the proposition that the EPA has the responsibility of 

determining the “best system of emission reduction ... 

adequately demonstrated” and, therefore, the amount of required 

emission limitation from the source category. 
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light of the fact that the Administrator must make the 

“adequately demonstrated” determination. Even if the provision 

is considered to be silent on that question, the EPA reasonably 

interprets the provision under Chevron step 2 to assign that 

responsibility of identifying the “best system of emission 

reduction” to the EPA for the same reasons as discussed in the 

EPA’s explanation of the implementing regulations. 

In addition, in the legislative history of the 1977 CAA 

Amendments, Congress endorsed the overall approach of the 

implementing regulations, which lends further credence to the 

proposition that the EPA has the responsibility of determining 

the “best system of emission reduction” and the amount of 

emission limitation from the existing sources. Specifically, in 

the House report that introduced the substantive changes to CAA 

section 111, the Committee explained that “[t]he Administrator 

would establish guidelines as to what the best system for each 

category of existing sources is.” (Emphasis added.)773 States, on 

the other hand, “would be responsible for determining the 

applicability of such guidelines to any particular source or 

sources.” (Emphasis added.)774 The use of the term “guidelines,” 

which does not expressly appear in CAA section 111(d), indicates 

 

773 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 774 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 
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Congress was aware of and approved of the overall approach the 

EPA promulgated in its implementing regulations for determining 

the BSER. 

Commenters argued that the states should be given the 

authority to determine the best system of emission reduction 

and, therefore, the amount of emission limitation from their 

sources. For the reasons described above, this is an incorrect 

interpretation of CAA section 111(d)(1) and (a)(1). 

5. Relative stringency of requirements for existing sources and 

new and modified sources. Commenters also objected that the 

proposed CAA section 111(d) standards are more stringent than 

the standards for new, modified or reconstructed sources, and 

they assert that setting section 111(d) standards that are more 

stringent than 111(b) standards would be illogical, contrary to 

precedent, contrary to the intent of the remaining useful life 

exception, and arbitrary and capricious.775 We disagree with 

these comments. 

Comparing the control requirements of the two sets of rules 

-- CAA section 111(d) and 111(b) –- is an “apples-to-oranges” 

comparison and, as a result, it is not possible to conclude that 

 

775 ACC et al. (Associations) comments at 40, Luminant comments 

at 89. 
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the 111(d) requirements are more stringent that the 111(b) 

requirements. 

 Most importantly, the two sets of rules have significantly 

different compliance times and compliance periods. The 

compliance time for the CAA section 111(b) rule for both new and 

modified sources is immediately upon construction or 

modification and, in fact, by operation of section 111(e) and 

(a)(2), new or modified sources that commenced construction 

prior to the effective date of the section 111(b) rule must also 

be in compliance upon the effective date of the rule. In 

contrast, the compliance time for the CAA section 111(d) rule 

does not begin until 7 years after promulgation of the rule, 

when the interim compliance period begins in 2022, and the final 

compliance time is not until 2030. Moreover, the compliance 

period for the interim requirements is 8 years. This longer 

compliance time and compliance period for existing sources 

accommodates a requirement that, on average, those sources have 

a lower nominal emissions limit than the requirements for new or 

modified sources, which those sources must comply with 

immediately. Indeed, it should be noted that under the schedule 

required under CAA section 111(b)(1)(B), the EPA would be 

required to review and revise the CAA section 111(b) rule 

shortly after the interim compliance time for the CAA section 
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111(d) rule begins in 2022, and well before the final compliance 

date in 2030, which heightens the significance of the different 

compliance period. 

 In addition, for any individual source, the CAA section 

111(d) rule includes more flexible means of compliance. The 

state may assign emission limits differently than the EPA’s 

guidelines, and may be expected to authorize emissions trading 

or averaging. These flexibilities are not included in the CAA 

section 111(b) rule, rather, new and modified EGUs must meet the 

emission standard at all times. This distinction is another 

reason why the CAA section 111(d) rule cannot be said to be more 

stringent than the CAA section 111(b) rule. 

6. Relationship between a source’s implementation of building 

blocks 2 and 3 and its emissions. In this section, we discuss 

the relationship between an affected EGU’s implementation of the 

measures in building blocks 2 and 3 and that affected EGU’s own 

generation and emissions. As discussed above, an affected EGU 

subject to a CAA section 111(d) state plan that imposes an 

emission rate may achieve that rate in part by implementing the 

measures in building block 2 (for a steam generator) and 

building block 3 (for a steam generator or combustion turbine). 

That is, an affected EGU may invest in low- or zero-emitting 

generation and may apply credits from those things against its 
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emission rate. Those credits reduce the affected EGU’s emission 

rate and thereby help it to achieve its emission limit. 

In addition, the additional low- or zero-emitting 

generation that result from the affected EGU’s investment will 

generally displace higher-emitting generation. This is because, 

as described above, higher-emitting generation generally has 

higher variable costs, due to the fuel costs, than, at least, 

zero-emitting generation. Displacement of higher-emitting 

generation will lower overall CO2 emissions from the source 

category of affected EGUs. 

If an affected EGU implements building block 2 or 3 by 

reducing its generation, it will reduce its own emissions. 

However, it may invests in other types of building block 2 or 3 

measures that do not, in-and-of-themselves, reduce the amount of 

its own emissions or, for that matter, its own generation. This 

is because the interconnected grid includes numerous generators, 

and electricity generation becomes undifferentiated the moment 

it is dispatched, so that it is not possible to trace 

electricity to any particular generator. Moreover, absent a 

limit on generation, such as, for example, one included in a 

permit, an affected EGU’s generation generally depends on where 

it falls on the dispatch curve. Even so, implementation of 
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building blocks 2 and 3 will reduce CO2 from some affected EGUs, 

and therefore reduce CO2 on a source category-wide basis. 

This outcome is consistent with the requirements of CAA 

section 111(d)(1) and (a)(1). To reiterate, CAA section 

111(d)(1) requires that “any existing source” have a “standard 

of performance,” defined under CAA section 111(a)(1) as “a 

standard for emissions of air pollutants which reflects the 

degree of emission limitation achievable through the application 

of the best system of emission reduction ... adequately 

demonstrated [BSER] ....” These provisions require by their 

terms that “any existing source” must have a “standard of 

performance,” but nothing in these provisions requires a 

particular amount – or, for that matter, any amount -- of 

emission reductions from each and every existing source. That 

the “standard of performance” is defined on the basis of the 

“degree of emission limitation achievable through the 

application of the [BSER]” does not mean that each affected EGU 

must achieve some amount of emission reduction, for the 

following reasons. 

The cornerstone of the definition of the term “standard of 

performance” is the BSER. In determining the BSER, the EPA must 

consider the amount of emission reduction that the system may 

achieve, and must consider the ability of the affected EGUs to 
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achieve the emission limits that result from the application of 

the BSER. The EPA is authorized to include in the BSER, for this 

source category, the measures in building blocks 2 and 3 

because, when applied to the source category, these measures 

result in emission standards that may be structured to ensure 

overall emission reductions from the source category and remain 

achievable by the affected EGUs. This remains so regardless of 

whether the “degree of emission limitation achievable through 

the application of the [BSER]” by any particular source results 

in actual emission reductions from that source. 

The application of the building blocks has an impact that 

is similar to that of a trading program, under which, overall, 

the affected sources reduce emissions, but any particular source 

does not need to reduce its emissions and, in fact, may increase 

its emissions, as long as it purchases sufficient credits or 

allowances from other sources. Indeed, any emission rate-based 

standard may not necessarily result in emission reductions from 

any particular affected source (or even all of the affected 

sources in the category) due to the ability of the particular 

source (or even all of them) to increase its production and, 

therefore, its emissions, even while maintaining the required 

emission rate. 
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7. Approach to subcategorization. As noted above, in this rule, 

we are treating all fossil fuel-fired EGUs as a single category, 

and, in the emission guidelines that we are promulgating with 

this rule, we are treating steam EGUs and combustion turbines as 

separate subcategories. We are determining the BSER for steam 

EGUs and the BSER for combustion turbines, and applying the BSER 

to each subcategory to determine a performance rate for that 

subcategory. We are not further subcategorizing among different 

types of steam EGUs or combustion turbines. 

 This approach is fully consistent with the provisions of 

section 111(d), which simply require the EPA to determine the 

BSER, do not prescribe the method for doing so, and are silent 

as to subcategorization. This approach is also fully consistent 

with other provisions in CAA section 111, which require the EPA 

first to list source categories that may reasonably be expected 

to endanger public health or welfare776 and then to regulate new 

sources within each such source category,777 and which grant the 

EPA discretion whether to subcategorize new sources for purposes 

of determining the BSER.778 

 

776 CAA section 111(b)(1)(A). 777 CAA section 111(b)(1)(B). 778 CAA section 111(b)(2). 
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 Subcategorization may be appropriate when certain types of 

sources could not achieve the same emission limit as other types 

of sources, but here, each affected EGU can achieve the 

performance rate by implementing the BSER. Specifically, as 

noted, each affected EGU may take a range of actions –- some of 

which depend on whether the state imposes an emission rate or a 

mass limit -- including investment in the building blocks, 

replaced or reduced generation, and emissions trading. Further, 

in the case of a rate-based state plan, several other compliance 

options not included in the BSER for this rule are also 

available to all affected sources, including investment in 

demand-side energy efficiency measures. Such compliance options 

may also indirectly help affected sources achieve compliance 

under a mass-based plan. 

 Our approach of subcategorizing between steam EGUs and 

combustion turbines is reasonable because building blocks 1 and 

2 apply only to steam EGUs. Moreover, our approach of not 

further subcategorizing as between different types of steam EGUs 

or combustion turbines reflects the reasonable policy that 

affected EGUs with higher emission rates should reduce their 

emissions by a greater percentage than affected EGUs with lower 

emission rates. 
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 Of course, a state retains great flexibility in assigning 

standards of performance to its affected EGUs and can, if it 

wishes impose different emission reduction obligations on its 

sources, as long as the overall level of emission limitation is 

at least as stringent as the emission guidelines, as discussed 

below. 

8. Reasons that this rule is within the EPA’s statutory 

authority and does not represent over-reaching. 

In this section, we respond to adverse comments that the 

EPA is overreaching in this rulemaking by attempting to direct 

the energy sector. These commenters construed the proposed 

rulemaking as the EPA proposing to mandate the implementation of 

the measures in the building blocks, including investment in 

renewable energy and implementation of a broad range of state 

and utility demand-side energy efficiency programs. Commenters 

added that in some instances, the affected EGUs and states would 

have no choice but to take the actions in the building blocks 

because they would not otherwise be able to achieve their 

emission standards. Commenters also emphasized that with the 

proposed portfolio approach, the rule would impose federally 

enforceable requirements on a wide range of entities that do not 

emit CO2 and have not previously been subject to CAA regulation. 

Commenters cite the U.S. Supreme Court’s statements in Utility 
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Air Regulatory Group v. EPA (UARG)779 that caution an agency 

against interpreting its statutory authority in a way that 

“would bring about an enormous and transformative expansion in 

[its] regulatory authority without clear congressional 

authorization,” and that add, “When an agency claims to discover 

in a long-extant statute an unheralded power to regulate ‘a 

significant portion of the American economy,’ ... we typically 

greet its announcement with a measure of skepticism.”780

Commenters assert that in this rule, the EPA is taking the 

actions that the UARG opinion cautioned against. For the reasons 

discussed below, these comments are incorrect and misunderstand 

fundamental aspects of this rule. In addition, to the EPA is not 

finalizingextent these comments address either building block 4 

or the portfolio approach they are moot, because the EPA is not 

finalizing those elements of the proposal. 

In this rule, the EPA is following the same approach that 

it uses in any rulemaking under CAA section 111(d), which is 

designed to regulate the air pollutants from the source category 

at issue. First, the EPA identifies the BSER to reduce harmful 

air pollution. Second, based on the BSER, the EPA promulgates 

 

779 134 S. Ct. 2427 (2014). 780 Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427, 2444 

(2014) (citations omitted). 
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emission guidelines, which generally take the form of emission 

rates applicable to the affected sources. In this case, the EPA 

is promulgating a uniform CO2 emission performance rate for 

steam-generating EGUs and a uniform CO2 emission performance rate 

for combustion turbines, and the EPA is translating those rates 

into a combined emission rate and equivalent mass limit for each 

state. These emission guidelines serve as the guideposts for 

state plan requirements. The states, in turn, promulgate 

emission standards of performance and, in doing so, retain 

significant flexibility to either to promulgate rate-based 

emission standards that mirror the emission performance rates in 

the guidelines, promulgate rate-based emission standards that 

are equivalent to the emission performance rates in the 

guidelines, or promulgate the equivalent mass limits.-based 

emission standards. The sources, in turn, are required to comply 

with their emission limitsstandards, and may do so through any 

means they choose. Alternatively, the state may adopt the statemeasures approach, which provides additional flexibility. 

Thus, the EPA is not requiring that the affected EGUs take 

any particular action, such as implementation of the building 

blocks. Rather, as just explained, the EPA is regulating the 

affected EGUs’ emissions by requiring that the state submit 

state plans that achieve specified emission 
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limitations.performance levels. The states may choose from a 

wide range of emission limits to impose on their sources, and 

the sources may choose from a wide range of compliance options 

to achieve their emission limits. Those options include various 

means of implementing the building blocks as well as numerous 

other compliance options, ranging from -- depending in part on 

whether the state imposes a rate-based or mass-based emission 

limit -- implementation of demand-side energy efficiency 

measures to natural gas co-firing.781

Moreover, inAs some indication of the diverse set of 

actions we expect to comply with the requirements of this rule, 

we note that demand-side energy efficiency programs, in 

particular, are expected to be a significant compliance method, 

in light of their low costs. In addition, the National 

Association of Clean Air Agencies (NACAA) has issued a report 

that provides a detailed discussion of 25 approaches to CO2

 

781 In fact, the EPA is expressly precluded from mandating 

specific controls except in certain limited circumstances. See 

42 U.S.C. § 7411(b)(5). For instance, the EPA is authorized to 

mandate a particular “design, equipment, work practice, or 

operational standard, or combination thereof,” when it is “not 

feasible to prescribe or enforce a standard of performance” for 

new sources. 42 U.S.C. § 7411(h)(1). CAA section 111(h) also 

highlights for us that while “design, equipment, work practice, 

or operational standards” may be directly mandated by the EPA, 

CAA section 111(a)(1) encompasses a broader suite of measures 

for consideration as the BSER. 
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reduction in the electricity sector.782 In addition, we note that 

the nine RGGI states -- Connecticut, Delaware, Maine, Maryland, 

Massachusetts, New Hampshire, New York, Rhode Island and Vermont 

-– have indicated that they intend to maintain their current 

state programs, which this rule would allow, and there are 

reports that other states may seek to join RGGI.783 Similarly, 

California has indicated that it intends to maintain its current 

state program, which this rule would allow. Other states could 

employ the types of methods used in Oregon, Washington, 

Colorado, or Minnesota, described in the background section of 

this preamble. 

As a practical matter, we expect that for some affected 

EGUs, implementation of the building blocks will be the most 

attractive option for compliance. This does not mean, contrary 

to the adverse comments noted above, that this rule constitutes 

a redesign of the energy sector. As discussed above, the 

building blocks meet the criteria to be part of the best system 

 

782 NACAA, “Implementing EPA’s Clean Power Plan: A Menu of 

Options (May 2015), http://www.4cleanair.org/NACAA_Menu_of_Options. NACAA 

describes itself as “the national, non-partisan, non-profit 

association of air pollution control agencies in 41 states, the 

District of Columbia, four territories and 116 metropolitan 

areas.” Id. 783 Martinson, Erica, “Cap and trade lives on through the 

states,” Politico (May 27, 2014), 

http://www.politico.com/story/2014/05/cap-and-trade-states107135.html. 
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of emission reduction ... adequately demonstrated. The fact that 

some sources will implement the building blocks and that this 

may result in changes in the electricity sector does not mean 

that the building blocks cannot be considered the BSER under CAA 

section 111(d). 

In this rule, as with all CAA section 111(d) rules, the EPA 

is not directly regulating any entities. Moreover, the EPA is 

not finalizing the proposed portfolio approach. Accordingly, not 

only is the EPA notis neither requiring thatnor authorizing the 

states to regulate non-affected EGUs, the EPA is in their CAA 

section 111(d) plans.784

Moreover, contrary to adverse comments, this rule does not 

authorizing states to include in their CAA 111(d)require the 

states to adopt a particular type of energy policy or implement 

particular types of energy measures. Under this rule, a state 

may comply with its obligations by adopting the emission 

standards approach to its state plan regulations covering nonaffected EGUsand imposing rate-based or mass-based emission 

standards on its affected EGUs. In this manner, this rule is 

consistent with prior section 111(d) rulemaking actions, in 

which the states have complied by promulgating one or both of 

 

784 A state may regulate non-EGUs as part of a state measures 

approach, but those measures would not be federally enforceable. 
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those types of standards of performance. In this rulemaking, as 

an alternative, the state may adopt the state measures approach, 

under which the state could, if it wishes, adopt particular 

types of energy measures that would lead to reductions in 

emissions from its EGUs. But again, this rule does not require 

the state to implement a particulate type of energy policy or 

adopt particular types of energy measures. 

It is certainly truereasonable to expect that compliance 

with these air pollution controls will have costs, and those 

costs will affect the electricity sector by discouraging 

generation of fossil fuel-fired electricity and encouraging less 

costly alternative means of generating electricity. or reducing 

demand. But for affected EGUEGUs, air pollution controls 

necessarily entail costs that affect the electricity sector and, 

in fact, the entire nation, regardless of what BSER the EPA 

identifies as the basis for the controls. For example, had some 

type of add-on control such as CCS been identified as the BSER 

for coal-fired EGUs, sources that complied by installing that 

control would incur higher costs. As a result, generation from 

coal-fired EGUs would be expected to decrease and be replaced at 

least in part by generation from existing NGCC units and new 

renewables because those forms of generation would see their 

competitive positions improved. 
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This basic fact that the EPA regulationsregulation of air 

pollutants from affected EGUs invariably affectaffects the 

utility sector is well-recognized and in no way indicates that 

such regulation exceed the EPA’s authority. In revising CAA 

section 111 in the 1977 CAA Amendments, Congress explicitly 

acknowledged that the EPA’s rules under CAA section 111 for EGUs 

would significantly impact the energy sector.785 The Courts have 

recognized that, too. The U.S. Supreme Court, in its 2011 

 

785 The D.C. Circuit acknowledged this legislative history in 

Sierra Club v. EPA, 657 F.2d 298, 331 (D.C. Cir. 1981). There, 

the Court stated: 

The legislative history clearly supports our reading 

of amended section 111 as authorizing EPA to balance 

long term national and regional impacts of alternative 

standards. The Conferees defined the best technology 

in terms of “long-term growth,” “long-term cost 

savings,” effects on the “coal market,” including 

prices and utilization of coal reserves, and 

“incentives for improved technology.” [Citing CAA 

Conference Report: Statement of Intent; Clarification 

of Select Provisions, 123 Cong. Rec. 27071 (1977), 3 

L.H. at 324 (referring to H.R.Rep.No.95-294, 95th 

Cong., 1st Sess. 188 (1977), at 183-95, 4 L.H. at 

2651-62, Remarks of Senator Muskie introducing S. 252 

for debate, 123 Cong.Rec. 18018 (1977), 3 L.H. at 

717.] Indeed, the[T]he Reports from both Houses on the 

Senate and House bills illustrate very clearly that 

Congress itself was using a long-term lens with a 

broad focus on future costs, environmental and energy 

effects of different technological systems when it 

discussed section 111. [Citing S. Rep. No. 95-127, 

95th Cong., 1st Sess. (1977), 3 L.HLegis. Hist. 1371; 

H.R.Rep.No.95-294,H.R. Rep. No. 95-294, 95th Cong., 

1st Sess. 188 (1977), 4 L.HLegis. Hist. 2465.]
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decision that the CAA and the EPA actions it authorizes displace 

any federal common law right to seek abatement of CO2 emissions 

from fossil- fuel -fired power plants, emphasized that CAA 

section 111 authorizes the EPA ––- which the Court identified as 

the “expert agency” –-– to regulate CO2 emissions from these 

sources in a manner that balances “our Nation’s energy needs and 

the possibility of economic disruption:” 

The appropriate amount of regulation in any particular 

greenhouse gas-producing sector cannot be prescribed 

in a vacuum: as with other questions of national or 

international policy, informed assessment of competing 

interests is required. Along with the environmental 

benefit potentially achievable, our Nation's energy 

needs and the possibility of economic disruption must 

weigh in the balance. 

The [CAA] entrusts such complex balancing to EPA 

in the first instance, in combination with state 

regulators. Each “standard of performance” EPA sets 

must “tak[e] into account the cost of achieving 

[emissions] reduction and any nonair quality health 

and environmental impact and energy requirements.” § 

7411(a)(1), (b)(1)(B), (d)(1); see also 40 C.F.R. § 

60.24(f)§ 7411(a)(1), (b)(1)(B), (d)(1); see also 40 

C.F.R. § 60.24(f) (EPA may permit state plans to 

deviate from generally applicable emissions standards 

upon demonstration that costs are “[u]n-reasonable”). 

EPA may “distinguish among classes, types, and sizes” 

of stationary sources in apportioning responsibility 

for emissions reductions. § 7411(b)(2), (d); see also 

40 C.F.R. § 60.22(b)(5).§ 7411(b)(2), (d); see also 40 

C.F.R. § 60.22(b)(5). And the agency may waive 

compliance with emission limits to permit a facility 

to test drive an “innovative technological system” 

that has “not [yet] been adequately demonstrated.” § 

7411(j)(1)(A). The Act envisions extensive cooperation 

between federal and state authorities, see § 7401(a), 

(b),§ 7411(j)(1)(A). The Act envisions extensive 
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cooperation between federal and state authorities, see 

§ 7401(a), (b), generally permitting each state to 

take the first cut at determining how best to achieve 

EPA emissions standards within its domain, see § 

7411(c)(1), (d)(1)-(§ 7411(c)(1), (d)(1)-(2). 

It is altogether fitting that Congress designated 

an expert agency, here, EPA, as best suited to serve 

as primary regulator of greenhouse gas emissions. The 

expert agency is surely better equipped to do the job 

than individual district judges issuing ad hoc, caseby-case injunctions.786

Similarly, the D.C. Circuit, in its 1981 decision upholding the 

EPA’s rules to reduce SO2 emissions from new coal-fired EGUs 

under the version of CAA section 111(b) adopted in the 1977 CAA 

Amendments, stated: 

[S]ection 111 most reasonably seems to require that 

EPA identify the emission levels that are “achievable” 

with “adequately demonstrated technology.” After EPA 

makes this determination, it must exercise its 

discretion to choose an achievable emission level 

which represents the best balance of economic, 

environmental, and energy considerations. It follows 

that to exercise this discretion EPA must examine the 

effects of technology on the grand scale in order to 

decide which level of control is best.... The standard 

is, after all, a national standard with long-term 

effects.787

The D.C. Circuit added: “Regulations such as those involved here 

demand a careful weighing of cost, environmental, and energy 

considerations. They also have broad implications for national 

 

786 American Electric Power Co. v. Connecticut, 131 S. Ct. 2527, 

2539-40 (2011). 

787 Sierra Club v. EPA, 657 F.2d 298, 330 (D.C. Cir. 1981). 
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economic policy.”788 This rule has “economic, environmental, and 

energy” impacts, as Congress and the Courts expect in a CAA 

 

788 Sierra Club v. EPA, 657 F.2d 298, 406 (D.C. Cir. 1981). The 

Court supported this statement with a lengthy quotation from a 

scholarly article, which stated, in part: 

Consider for a moment the chain of collective 

decisions and their effects just in the case of 

electric utilities. Petroleum imports can be conserved 

by switching from oil-fired to coal-fired generation. 

But barring other measures, burning high-sulfur 

Eastern coal substantially increases pollution. Sulfur 

can be “scrubbed” from coal smoke in the stack, but at 

a heavy cost, with devices that turn out huge volumes 

of sulfur wastes that must be disposed of and about 

whose reliability there is some question. Intermittent 

control techniques (installing high smokestacks and 

switching off burners when meterologicalmeteorological 

conditions are adverse) can, at lower cost, reduce 

local concentrations of sulfur oxides in the air, but 

cannot cope with the growing problem of sulfates and 

widespread acid rainfall. Use of low-sulfur Western 

coal would avoid many of these problems, but this coal 

is obtained by strip mining. Strip-mining reclamation 

is possible, but substantially hindered in large areas 

of the West by lack of rainfall. Moreover, in some 

coal-rich areas the coal beds form the underground 

aquifer and their removal could wreck adjacent farming 

or ranching economies. Large coal-burning plants might 

be located in remote areas far from highly populated 

urban centers in order to minimize the human effects 

of pollution. But such areas are among the few left 

that are unspoiled by pollution and both 

environmentalists and the residents (relatively few in 

number compared with those in metropolitan localities 

but large among the voting population in the 

particular states) strongly object to this policy. 

Id. at 406 n. 526. 
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section 111 rule, but those impacts do not mean that the EPA is 

precluded from promulgating the rule. 

economic policy.”789 This rule has “economic, environmental, and 

energy” impacts, as Congress and the Courts expect in a CAA 

 

789 Sierra Club v. EPA, 657 F.2d 298, 406 (D.C. Cir. 1981). The 

Court supported this statement with a lengthy quotation from a 

scholarly article, which stated, in part: 

Consider for a moment the chain of collective 

decisions and their effects just in the case of 

electric utilities. Petroleum imports can be conserved 

by switching from oil-fired to coal-fired generation. 

But barring other measures, burning high-sulfur 

Eastern coal substantially increases pollution. Sulfur 

can be “scrubbed” from coal smoke in the stack, but at 

a heavy cost, with devices that turn out huge volumes 

of sulfur wastes that must be disposed of and about 

whose reliability there is some question. Intermittent 

control techniques (installing high smokestacks and 

switching off burners when meterologicalmeteorological 

conditions are adverse) can, at lower cost, reduce 

local concentrations of sulfur oxides in the air, but 

cannot cope with the growing problem of sulfates and 

widespread acid rainfall. Use of low-sulfur Western 

coal would avoid many of these problems, but this coal 

is obtained by strip mining. Strip-mining reclamation 

is possible, but substantially hindered in large areas 

of the West by lack of rainfall. Moreover, in some 

coal-rich areas the coal beds form the underground 

aquifer and their removal could wreck adjacent farming 

or ranching economies. Large coal-burning plants might 

be located in remote areas far from highly populated 

urban centers in order to minimize the human effects 

of pollution. But such areas are among the few left 

that are unspoiled by pollution and both 

environmentalists and the residents (relatively few in 

number compared with those in metropolitan localities 
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section 111 rule, but those impacts do not mean that the EPA is 

precluded from promulgating the rule. 

 As noted above, in this rule, to control CO2 emissions from 

affected EGUs, the EPA first considered more traditional air 

pollution control measures, including supply-side efficiency 

improvements, fuel-switching (for CO2 emissions, that entails cofiring with natural gas), and add-on controls (for CO2 emissions, 

that entails CCS). However, it became apparent that even if the 

EPA could have finalized those controls as the BSER790 and 

established the same uniform CO2 emission performance rates, the 

affected EGUs would rely on less expensive ways to achieve their 

emission limits. Specifically, instead of relying on co-firing 

and CCS, the affected EGUs generally would replace their 

generation with lower- or zero-emitting generation– the measures 

in building blocks 2 and 3 -- because those measures are 

significantly less expensive and already well-established as 

pollution control measures. Indeed, some affected EGUs have 

 

but large among the voting population in the 

particular states) strongly object to this policy. 

Id. at 406 n. 526. 790 For the reasons explained, we did not finalize those measures 

because significantly less expensive control measures -- 

building blocks 2 and 3 -- are available for these affected 

EGUs. 
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stated that while they oppose including in the BSER generation 

shifts to lower- or zero-emitting sources (or, as proposed, 

demand-side energy efficiency), they request that those measures 

be available for compliance, which indicates their interest in 

implementing those measures.791

Specifically, instead of relying on co-firing and CCS, the 

affected EGUs generally would replace their generation with 

lower- or zero-emitting generation– the measures in building 

blocks 2 and 3 -- because those measures are significantly less 

expensive and already well-established as pollution control 

measures. Indeed, some affected EGUs have stated that while they 

oppose including in the BSER generation shifts to lower- or 

zero-emitting sources (or, as proposed, demand-side energy 

efficiency), they request that those measures be available for 

compliance, which indicates their interest in implementing those 

measures.792

 

791 See the proposal for this rule, 79 FR at 34888 (“during the 

public outreach sessions, stakeholders generally recommended 

that state plans be authorized to rely on, and that affected 

sources be authorized to implement, re-dispatch, renewable 

energy measures, and demand-side energy efficiency measures in 

order to meet states’ and sources’ emission reduction 

obligations.”). 

792 See the proposal for this rule, 79 FR at 34888 (“during the 

public outreach sessions, stakeholders generally recommended 

that state plans be authorized to rely on, and that affected 

sources be authorized to implement, re-dispatch, renewable 
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We expect that many sources will choose to comply with 

their emission limits through the measures in building blocks 2 

and 3 (as well as 4),, but contrary to the assertions of some 

commenters, this will not result in unprecedented and 

fundamental alterations to the energy sector. As discussed 

above, Congress relied on the same measures as those the EPA is 

including in building blocks 2 and 3 as essential parts of the 

basis for the Title IV emission limits for fossil fuel-fired 

EGUs, and the EPA did the same for the emission limits in 

various rules for those same sources. 

In addition, as discussed elsewhere, reliance on the 

measures in building blocks 2 and 3 is fully consistent with the 

recent changes and current trends in electricity generation, and 

as a result, would by no means entail fundamental redirection of 

the energy sector. As indicated in the RIA for this rule, we 

expect that the main impact of this rule on the nation’s mix of 

generation will be to reduce coal-fired generation, but in an 

amount and by a rate that is consistent with recent historical 

declines in coal-fired generation. Specifically, from 

approximately 2005 to 2014, coal-fired generation declined at a 

 

energy measures, and demand-side energy efficiency measures in 

order to meet states’ and sources’ emission reduction 

obligations.”). 
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rate that was greater than the rate of reduced coal-fired 

generation that we expect to result from this rulemaking from 

2015 to 2030. In addition, under this rule, the trends for all 

other types of generation, including natural gas-fired 

generation, nuclear generation, and renewable generation, will 

remain generally consistent with what their trends would be in 

the absence of this rule. In addition, this rule is expected to 

result in increases in demand-side energy efficiency.

In addition, contrary to claims of some commenters, in this 

rule, the EPA is not attempting to expand its authorities by 

attempting to expand the jurisdiction of the CAA to previously 

unregulated sectors of the economy, in contravention of the UARG

decision. In addition, contrary to claims of some commenters, in 

this rule, the EPA is not attempting to expand its authorities 

by attempting to expand the jurisdiction of the CAA to 

previously unregulated sectors of the economy, in contravention 

of the UARG decision. In UARG, the U.S. Supreme Court struck 

down the EPA’s interpretation of the PSD provisions of the CAA 

thatbecause the interpretation had the effect of applying the 

PSD requirements to large numbers of small sources that 

previously had not been subject to PSD, and with respect to 

whichbecause, according to the Court, the EPA acknowledged that 

Congress did not intend that such sources be subject to the PSD 
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requirements.793 Commenters appear to interpret this decision to 

preclude the EPA from including at least building block 3 in the 

BSER because it includes measures that involve entities (such as 

renewable energy developers) that do not emit CO2 and have not 

previously been subject to the CAA. be subject to the PSD 

requirements.794 Commenters appear to interpret this decision to 

preclude the EPA from including at least building block 3 in the 

BSER because it includes measures that involve entities (such as 

renewable energy developers) that do not emit CO2 and have not 

previously been subject to the CAA. However, in this rule, the 

EPA is not attempting to subject any entity other than the 

affected EGUs in the source categoriescategory to CAA section 

111 requirements. As discussed below, the EPA is not finalizing 

the proposed portfolio approach, under which states were 

authorized to include, in their CAA section 111(d) state plans, 

federally enforceable requirements on entities other than 

affected EGUs. Thus, as noted above, this final rule does not 

require or authorize the states to include entities other than 

affected EGUs in their CAA section 111(d) state plans, and as a 

 

793 Util. Air RegulatoryReg. Group v. EPA, 134 S. Ct. 2427, 2443 

(2014). 

794 Util. Air RegulatoryReg. Group v. EPA, 134 S. Ct. 2427, 2443 

(2014). 
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result, those entities will not come under CAA jurisdiction795

and the parts of the economy that they represent will not be 

regulated by the EPA. 

7. Relative stringency of requirements for existing sources and 

new, modified, and reconstructed sources. 

Commenters also objected that the proposed CAA section 

111(d) standards are more stringent than the standards for new, 

modified or reconstructed sources, and they assert that setting 

section 111(d) standards that are more stringent than 111(b) 

standards would be illogical, contrary to precedent, contrary to 

the intent of the remaining useful life exception, and arbitrary 

and capricious.796 We disagree with these comments. Comparing the 

control requirements of the two sets of rules, CAA section 

111(d) and 111(b), is an “apples-to-oranges” comparison and, as 

a result, it is not possible – and it is overly simplistic - to 

conclude that the 111(d) requirements are more stringent that 

the 111(b) requirements. 

 Most importantly, the two sets of rules become applicable 

at different points in time and have significantly different 

 

795 States may regulate non-affected EGUs through a state 

measures approach, but those regulations would not be federally 

enforceable. 

796 ACC et al. (Associations) comments at 40, Luminant comments 

at 89. 
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compliance periods. The CAA section 111(b) rule becomes 

applicable for new, modified and reconstructed sources 

immediately upon construction, modification, or reconstruction 

and, in fact, by operation of section 111(e) and (a)(2), new, 

modified, or reconstructed sources that commenced construction 

prior to the effective date of the section 111(b) rule must also 

be in compliance upon the effective date of the rule. In 

contrast, the requirements under the CAA section 111(d) rule do 

not become applicable to existing affected EGUs until seven 

years after promulgation of the rule, when the interim 

compliance period begins in 2022, and the final compliance 

period does not begin until 2030. Moreover, the compliance 

period for the interim requirements is eight years. This later 

applicability date and longer compliance period for existing 

sources accommodates a requirement that, on average, those 

sources have a lower nominal emission limit than the standards 

for new or modified sources, which those latter sources must 

comply with immediately. 

In addition, the timetables for compliance with the section 

111(b) and 111(d) rules should be considered in light of the 8-

year review schedule required for section 111(b) rules under CAA 

section 111(b)(1)(B). Under CAA section 111(b)(1)(B), the EPA is 

required to “review and, if appropriate, revise” the section 
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111(b) standards “at least every 8 years.” This provision 

obligates the EPA to review the section 111(b) rule for CO2 

emissions from new, modified, and reconstructed power plants by 

the year 2023. That mandatory review will reassess the BSER to 

determine the appropriate stringency for emission standards for 

new, modified, and reconstructed sources into the future. 

Therefore, for present purposes of comparing the stringency of 

the section 111(b) and 111(d) rules, the year 2023 presents an 

important point of comparison. 

Specifically, as noted above, the section 111(b) standards 

apply to new, modified and reconstructed sources beginning in 

2015, while the section 111(d) rule does not take effect until 

2022, which happens to fall on the cusp of the 8-year review for 

the 111(b) standards. 

 Even after the section 111(d) rule takes effect in 2022, 

the flexibility that this rule offers the states has important 

implications for its stringency and for any comparison to the 

section 111(b) rule. Although the requirements for the 111(d) 

rule begin in 2022, they are phased in, in a flexible manner, 

over the 2022-2030 period. That is, states are required to meet 

interim goals for the 2022-2029 period by 2029, and the final 

goals by 2030, but states are not required to impose 

requirements on their sources that take effect in 2022. In fact, 
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states may, if they prefer, impose business-as-usual emission 

standards on their sources that do not require emission 

reductions in 2022 and apply emission standards on their sources 

that do require emission reductions and that take effect no 

earlier than 2023. Moreover, because emission standards may have 

an annual compliance period, the states may allow their sources 

to delay having to comply with any emission reduction 

requirements until the end of 2023.797

Therefore, while the section 111(b) standards apply to new, 

modified, and reconstructed sources beginning in 2015, the 

section 111(d) standards may not apply to existing sources until 

2023.As a result, by 2023 – the year that the 111(b) standards 

are required to be reviewed for possible revision – affected 

EGUs subject to the 111(d) standards may remain uncontrolled. 

Under those circumstances, the 111(d) rule cannot be said to be 

more stringent than the 111(b) rule.798 

 

797 A state that chooses to allow its sources to remain 

uncontrolled through 2023 would still be able to meet its 

interim goal by 2029, although it would need to impose more 

stringent requirements on its sources over the 2024-2029 period 

than it would if it had imposed requirements beginning in 2022. 

It should also be noted that in fact, most states could allow 

their sources to remain uncontrolled for 2022 and 2023, and 

require controls beginning in 2024, and still be able to meet 

their interim goal. 

798 In addition, because the section 111(d) requirements are 

phased in, states may choose to apply a gradual phase-in of the 
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Another reason why the section 111(d) rule cannot be said 

to be more stringent than the section 111(b) rule is that for 

any individual source, the 111(d) rule is applied more flexibly 

and includes more flexible means of compliance. Whereas the 

section 111(b) rule entails an emission rate that each affected 

EGU must meet on a 12-month (rolling) basis, the section 111(d) 

is more flexible. For example, states may adopt the state 

measures approach and refrain from imposing any requirements on 

their affected EGUs. In addition, under the section 111(d) rule, 

sources have more flexible means of compliance. For an emission 

standards approach, depending on the form of the state 

requirements (mass-based or rate-based), the state may be 

expected to authorize trading of mass-based emission allowances 

or rate-based emission credits, and in addition, the purchase of 

ERCs. These flexibilities are not included in the section 111(b) 

 

reductions. This means that the nominal emission rates for 

section 111(d) sources would be significantly less stringent for 

the first several years of the compliance period. We estimate 

that if states choose to impose the section 111(d) requirements 

in a proportional amount each year, beginning in 2022, the 

requirements for steam generators by 2022 would result in an 

average emission performance rate of 1,764 lb. CO2/MWh net and 

by 2023, an average emission rate of 1,698 lb. CO2/MWh net (In 

2030, the rate falls to 1,305 lb. CO2/MWh net.) For existing 

NGCC units, if states choose to implement the 111(d) 

requirements proportionally, in 2022, the average rate would be 

910 lb. CO2/MWh net, and in 2023 it would be 899 lb. CO2/MWh 

net. (In 2030, this rate falls to 771 lb. CO2/MWh net.) 
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rule, rather, as noted, each new, modified, and reconstructed 

EGU must individually meet its emission standard on a 12-month 

(rolling) basis. The EPA has frequently required that sources 

meet a more stringent nominal limit when they are allowed 

compliance flexibility, particularly, the opportunity to 

trade.799 In addition, states have the discretion to allow their 

sources to meet emission standards over a longer time period. 

This distinction between the two rules is another reason why the 

section 111(d) rule cannot be said to be more stringent in fact 

than the section 111(b) rule. 

 There are other reasons why the section 111(d) rule cannot 

be said to be more stringent. With respect to the 111(d) and 

111(b) rules for existing and new NGCC units, we note the 

 

799 See, e.g., EPA, “Improving Air Quality with Economic 

Incentive Programs,” EPA-452/R-01-001, at 82 (2001) (requiring 

that Economic Incentive Programs show an environmental benefit, 

such as “reducing emission reductions generated by program 

participants by at least 10 percent”), available at 

http://www.epa.gov/airquality/advance/pdfs/eipfin.pdf; “Economic Incentive 

Program Rules: Final Rule,” 59 FR 16690 (April 7, 1994) (same); 

“Certification Programs for Banking and Trading of NOx and PM 

Credits for Heavy-Duty Engines: Final Rule,” 55 FR 30584 (July 

26, 1990) (requiring that for programs for banking and trading 

of NOx and PM credits for gasoline, diesel and methanol powered 

engines, all trading and banking of credits must be subject to a 

20 percent discount “as an added assurance that the incentives 

created by the program will not only have no adverse 

environmental impact but also provide an environmental 

benefit.”). 
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following: as explained in the section 111(b) preamble, the 

standard for new NGCC units is designed to accommodate a wide 

range of unit types, including small units and rapid-start 

units, which are a small part of the expected new NGCC 

generation capacity. As such, the 111(b) standard (1,000 lb 

CO2/MWh gross, which equates to 1,030 lb CO2/MWh net) will not 

constrain the emissions of the great majority of expected new 

NGCC generation capacity, which is expected to consist of larger 

base load units (with a capacity of 100 MW or greater) that are 

not intended to cycle frequently. Their initial emissions are 

expected to be below 800 lb. CO2/MWh gross, their emissions over 

time may be somewhat higher due to equipment deterioration, and 

as a result, their PSD permits are expected to include emission 

limits at approximately the 800 lb. CO2/MWh gross level. A very 

small amount of the new NGCC generation is expected to be small 

units (with a capacity of approximately 25 MW) or rapid-start 

units. Their initial emissions are expected to be approximately 

950 lb. CO2/MWh gross, their emissions over time are expected to 

be somewhat higher due to equipment deterioration, and it these 

units that the standard of 1,000 lb. CO2/MWh gross is designed to 
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constrain.800 As a result, the 1,000 lb. CO2/MWh gross limit 

applies to all new NGCC units, including the great majority of 

the expected new capacity consisting of larger, non-rapid start 

units, even though, as just noted, the great majority of the 

units are expected to emit at significantly lower emission 

rates. The section 111(d) standard for existing sources, in 

contrast, is generally expected to constrain existing NGCC units 

on average. Moreover, very little of the existing NGCC 

generation includes small units or, in particular, rapid-start 

units because the latter are a recently developed technology. To 

some extent, the same is true for the 111(b) standard for 

reconstructed NGCC units. The average NGCC rate was 

approximately 850 lb CO2/MWh gross in 2014 and, as a result, 

most sources are emitting below the section 111(b) standard for 

reconstructed sources. For these reasons, too, the 111(b) 

standards for new and reconstructed NGCC units cannot be 

compared to the 111(d) standards for existing NGCC units.801

 

800 As explained in the 111(b) preamble, any attempt to 

subcategorize and assign a lower emission limit to larger, nonrapid start NGCC units could cause market distortions. 

801 The section 111(b) standards for modified and reconstructed 

steam generation units are generally lower than the emission 

rates of existing stream generation units, but for the reasons 

explained earlier, those standards cannot be compared to the 

section 111(d) standards for existing steam generation units. 
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 Moreover, even if commenters were correct that the section 

111(d) requirements for existing sources are more stringent than 

the section 111(b) requirements for new sources, that would not, 

by itself, call into question the reasonableness of either 

standard. The stringency of the requirements for each source 

subcategory is, of course, a direct function of the BSER 

identified for that source subcategory. In this rulemaking, we 

explain the basis for the BSER for existing sources, and why we 

do not include certain measures, such as CCS; and in the section 

111(b) rulemaking, we explain the basis for the BSER for new 

sources, and why we do not include certain measures, such as the 

building blocks. As long as the BSER determination is reasonable 

and the resulting emission limits meet other applicable 

requirements, those emission limits are valid, even if the one 

for new sources is less stringent than the one for existing 

sources. No provision in section 111, nor any statement in its 

legislative history, nor any of its case law, indicates that the 

standards for new sources must be more stringent than the 

standards for existing sources. 

C. Building Block 1—Efficiency Improvements at Affected CoalFired Steam EGUs 

The first category of approaches to reducing CO2 emissions 

at affected fossil fuel-fired EGUs consists of measures that 
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reduce the carbon intensity of generationimprove heat rate at 

individual coal-fired steam EGUs by improving their heat rate. 

Heat rate improvements are changes implemented at an EGU that 

increase the efficiency with which the EGU converts fuel energy 

to electric energy, thereby reducing the amount of fuel needed 

to produce the same amount of electricity and consequently 

lowering the amount of CO2 produced as a byproduct of fuel 

combustion. Heat rate improvements yield important economic 

benefits to affected sourcesEGUs by reducing their fuel costs. 

An EGU’s heat rate is the amount of fuel energy input 

needed (Btu, higher heating value basis) to produce 1 kWh of net 

electrical energy output.802 In 2012, the generation-weighted 

average annual heat rate of domesticthe 884 coal-fired EGUs 

included in EPA’s building block 1 analysis was approximately 

9,732 Btu per netgross kWh.803 Because an EGU’s CO2 emissions are 

driven primarily by the amount of fuel consumed, improving 

 

802 Typically, the units of measure used for heat rate (e.g., 

Btu/kWh-net) indicate whether a given value is based on the 

gross output or net output. Net heat rate is always higher than 

gross heat rate; in coal-steam units, net heat rate can be 5–10% 

higher than gross heat rate. 

803 Similarly, in 2012within each interconnection, the 

generation-weighted average annual heat rates for those coalfired EGUs in each interconnectionour study population were 

9,700 Btu per netgross kWh (Eastern); 9,888 Btu per netgross kWh 

(Western); and 9,789 Btu per netgross kWh (Texas). 
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(i.e., decreasing) heat rate at a coal-fired EGU inherently 

reduces the carbon-intensity of generation. 

As discussed above in section V.A and in the June 2014 

proposal,804 it is critical to recognize that affected coal-fired 

EGUs operate in the context of the integrated electricity 

system. Because of this reality, applying building block 1 in 

isolation can result in a “rebound effect” that undermines the 

emissions reductions otherwise achieved by heat rate 

improvements. As already noted, the building block 1 measures 

described below cannot by themselves constitute the BSER because 

the quantity of emission reductions achieved -- which is a 

factor that the courts have required EPA to consider in 

determining the BSER -- would be of insufficient magnitude in 

the context of this pollutant and this industry. The potential 

rebound effect, if it occurred, would exacerbate the 

insufficiency of the emission reductions. However, applying 

building block 1 in combination with other building blocks can 

address this concern for the reasons stated in section V.A.4. 

We conducted several analyses to assess the potential for 

heat rate improvements from the coal-fired EGU fleet. As in the 

proposal, we employed a unit-specific approach that compared 

 

804 See, e.g., 79 FR 34830, 34859 (June 18, 2014). 
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each EGU’s performance against its own historical performance in 

lieu of directly comparing an EGU’s performance against other 

EGUs with similar characteristics. Accordingly, as described 

below, our method effectively controls for the characteristics 

and factors of an EGU that typically remain constant over time 

(e.g., a unit is unlikely to dramatically increase or decrease 

in size). Our methodology for determining the amount of heat 

rate improvement appropriately included in the BSER as building 

block 1 is discussed in the next section, below. 

1. Summary of measures comprising the BSER in building block 1 

a. Measures under building block 1 - heat rate improvements. In 

finalizing the building block 1 portion of this rule, we 

considered over a thousand individual comments from the public, 

including individual EGUs and state agencies, on heat rate 

improvement, which are discussed below and also in the responses 

to comments document and the GHG Mitigation Measures TSD for the 

CPP Final Rule [Docket ID No. EPA-HQ-OAR-2013-0602]. Based on 

these public comments, we have refined the statistical analyses 

used in the proposal to identify the potential heat rate 

improvement that can be achieved on average by affected coalfired EGUs. 

In the proposal, we used two approaches to analyze the 

variability of an EGU’s gross heat rate using a robust dataset 
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comprised of 11 years of hourly gross heat rate data for 884 

coal-fired EGUs -- over 11 million hours of data collected 

between 2002 and 2012. The foundation of our first approach was 

an analysis of the variability of each EGU’s gross heat rate, 

which was accomplished in large part by grouping each EGU’s 

hourly data by similar ambient temperature and capacity factor 

(i.e., hourly operating level as a percentage of nameplate 

capacity) conditions. The second approach analyzed the 

difference between an EGU’s average gross heat rate and its best 

historical gross heat rate performance. We proposed that, on a 

nationwide basis, affected coal-fired EGUs should be able to 

achieve 6-percent heat rate improvement: 4-percent improvement 

from best practices, and an additional 2-percent improvement 

from equipment upgrades. 

We received many comments asserting that the 11-year 

dataset we had used to determine the 4-percent best practices 

figure likely reflected some portion of the 2-percent equipment 

upgrades figure we had separately identified. Accordingly, these 

commenters claim that the EPA double-counted equipment upgrades 

in arriving at the full estimate of 6-percent heat rate 

improvement. Commenters also noted the difficulty, in some 

cases, of determining whether a heat rate improvement measure is 

an “equipment upgrade” or “best practice,” such as optimizing 
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soot blowing with intelligent systems, using CO monitors for 

optimizing combustion, or applying air heater and duct leakage 

controls. Based on commenters’ concerns over the potential for 

double-counting, the EPA has decided not to add a separate 

equipment upgrade component to its estimate of heat rate 

improvement potential. 

As noted below in sections V.C.1.b and V.C.3, the EPA 

acknowledges that some equipment upgrades implemented by EGUs 

during the 11-year study period are reflected in the hourly heat 

rate data. Therefore, we made two refinements to our analyses of 

heat rate improvement potential. First, we refined our 

statistical approaches to use each EGU’s gross heat rate from 

2012 -- the final year of the 11-year study period -- as the 

baseline for calculating heat rate improvement potential. By 

comparing each EGU’s best historical gross heat rate with its 

2012 gross heat rate, our analyses account for the enduring 

effects on heat rate of any equipment upgrades or best practices 

that an EGU implemented during the study period. Heat rate 

improvement measures that an EGU maintains in 2012 are reflected 

in that baseline, and thus are not treated as evidence that the 

EGU can further improve heat rate. Additionally, in part because 

of limitations on the information available to us regarding 

which equipment upgrades have been or could be implemented at 
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individual EGUs, as well concerns about double-counting, we have 

conservatively decided not to add a separate equipment upgrade 

component to our estimate of heat rate improvement potential.

Nonetheless, we remain confident that additional equipment 

upgrades (including measures that are unambiguously equipment 

upgrades, such as turbine overhauls) are possible at many coalfired EGUs, as supported by numerous commenters, the Sargent & 

Lundy study805 (S&L) and other industry reports and studies, 

many. Many of whichthese reports and studies are referenced in 

the TSD developed for the proposed rule, as well as in the GHG 

Mitigation Measures TSD supporting the final CPP. 

Several commenters criticized the fact that the proposal 

assessed potential heat rate improvement on a nationwide basis. 

These commenters suggested instead that we narrow the geographic 

scope of our analysis, generally identifying a state-by-state 

approach as a preferred alternative. In light of commenters’ 

concerns about using a single nationwide approach, as well as 

for reasons described in Section V.A and elsewhere in this 

preamble, the final rule assesses potential heat rate 

 

805 Sargent and Lundy 2009, Coal-Fired Power Plant Heat Rate 

Reductions, SL-009597, Final Report, January 2009, Docket ID No. 

EPA–HQ–OAR–2013–0602-XXXX, available at: 

http://www.epa.gov/airmarkets/resource/docsdocuments/ipm/coalfir

ed.pdf. 
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improvement regionally, within the Eastern, Western and Texas 

Interconnections.806

For the final rule, we performed several analyses to 

determine what heat rate improvement was achievable in each 

interconnection from best practices and equipment upgrades. As 

in the proposal, these analyses used the 11-year dataset of EGU 

hourly gross heat rate data from 2002 to 2012. As discussed 

further in the GHG Mitigation Measures TSD, our reliance on 

these gross heat rate data was reasonable given that (1) these 

data are the only comprehensive data available to the EPA, and 

(2) heat rate is proportional to CO2 emission rate. 

As in the proposal, we used more than one analytical method 

to evaluate the opportunity for EGUs to reduce their CO2

emissions through heat rate improvements. Our final methodology 

uses three different analytical approaches based on refinements 

of the two approaches described at the proposal stage. We call 

these final approaches: (1) the “efficiency and consistency 

improvements under similar conditions” approach; (2) the “best 

historical average performance” approach; and (3) the “best 

 

806 The geographic area within the Texas Interconnection 

generally corresponds to the portion of the state of Texas 

covered by ERCOT (the Electric Reliability Council of Texas). 

Additional portions of the state of Texas are located within the 

Eastern and Western Interconnections. 
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historical average performance under similar conditions” 

approach. As described below and in the GHG Mitigation Measures

TSD, each approach provides an independently reasonable way to 

estimate the potential for heat rate improvements by EGUs in 

each region. However, rather than select a potential heat rate 

improvement value supported by one or only some of these 

independently reasonable analytical approaches, we 

conservatively based our final determination for each region on 

the value for that region supported by all three approaches. 

The first approach, referred to here as theThe “efficiency 

and consistency improvements under similar conditions” approach,

is a slight refinement of an approach discussed at length in the 

proposal. As in the proposal, we distributed each hour of gross 

heat rate data for each EGU into a matrix comprised of 168 bins, 

based on the ambient temperature and hourly capacity factor of 

the EGU at the time that hour of gross heat rate data was 

generated. Each bin represented a 10-degree Fahrenheit (oF) range 

in ambient temperature (from -20oF to greater than 110oF), and a 

10-percent range in capacity factor (from 0 percent to greater 

than 110 percent807). Thus, for example, one bin mightwould

 

807 Because an EGU’s rated nameplate capacity is based on a 

maximum continuous rating, EGUs may operate for periods of time 

“over” 100 percent of their capacity factor. The EPA’s dataset 

of hourly operating data reflected some such instances. 
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contain all of an EGU’s hourly gross heat rate data generated 

during the 11-year study period while that EGU was operating at 

80- to 89-percent capacity while ambient temperatures were 

between 70oF and 79oF. 

As we explained at proposal and as discussed further in the

GHG Mitigation Measures TSD, ambient temperature and hourly 

capacity factor are important conditions that influence heat 

rate at individual EGUs. By separating the EGU-specific data 

into bins based on these variables, and only directly comparing 

data within a bin, we were largely able to control for the 

influence of those variables on an EGU’s heat rate. Accordingly, 

having controlled for these two external factors, and having 

already controlled for unit-specific factors affecting heat rate 

by analyzing the data for each EGU in isolation, we are 

confident that the remaining variation in each bin’s data was 

primarily driven by factors under the EGU operator’s control. 

After allocating an individual EGU’s data across the bins, 

we next established a benchmark for each bin based on the best 

hourly gross heat rate accounting for outliers (i.e., we set the 

benchmark at the 10th percentile hourly gross heat rate value) 
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during any consecutive two-year period.808 We compared the hourly 

gross heat rate data within each bin to the EGU’s benchmark 

value. As inSimilar to the proposal, within each bin we assessed 

the effect on heat rate of improving the consistency of that EGU 

by reducing hourly gross heat rate values that were greater than 

the benchmark by a percentage of the distance between each of 

those higher hourly values and the benchmark.809 We refer to this 

percentage improvement value as the “consistency factor,” 

because applying it results in values for heat rate that are 

marginally more consistent with the EGU’s benchmark for that 

bin. Based on engineering judgement, inIn our proposal we 

selected a consistency factor of 30 percent after 

evaluatingevaluated the heat rate improvement that would result 

from applying consistency factors of 10, 20, 30, 40 and 50 

percent of the distance between those less-efficient hourly 

gross heat rate values and the benchmark.; using engineering 

judgment, we selected a consistency factor of 30 percent, which 

 

808 As described below, we also conducted this regionalized 

approach using a benchmark based on the best hourly gross heat 

rate accounting for outliers during any one-year period. See the 

GHG Mitigation Measures TSD supporting the final CPP for more 

details. 

809 In the proposal, we used heat input values rather than gross 

heat rate values. See the GHG Mitigation Measures TSD supporting 

the final CPP for more details. 
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produced results comparable to those obtained using other 

approaches for analyzing heat rate. For our final analysis under 

this approach, we refined the consistency factor based on a 

statistical assessment of the overall variability of heat rate 

in that EGU’s region, as described in the GHG Mitigation 

Measures TSD.810 As in the proposal, we applied the consistency 

factor to each bin of each EGU’s hourly gross heat rate data, 

and averaged the result across all bins in that EGU’s matrix, 

giving us marginally. The net result was an improved gross heat 

rate forreflecting what that EGU during the 11-year period 

fromwould have achieved between 2002 toand 2012. if, under 

certain ambient temperature and capacity factor conditions, the 

EGU had improved its gross heat rate during less-efficient hours 

to be slightly more consistent with the relevant benchmark 

value. We then compared the improved gross heat rate for each 

EGU to its actual 2012 historichistorical average gross heat 

rate. We chose 2012 as the year of comparison because 2012 was 

 

810 For the Eastern Interconnection, the consistency factor is 

38.1 percent. For the Western Interconnection, the consistency 

factor is 38.4 percent. For the Texas Interconnection, the 

consistency factor is 37.1 percent. Conducting this analysis on 

a nationwide basis would have resulted in application of a 

consistency factor of 38.2 percent. As described below, we also 

conducted this regionalized approach using consistency factors 

determined based on one-year figures. See the GHG Mitigation 

Measures TSD supporting the final CPP for more details. 
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the latest year for which the EPA had data at the time of the 

proposal, and because using the most recent data reflects the 

EGU’s current operating level and accounts for improvements the 

EGU may have undertaken over the 11-year study period. 

Applying this procedure to all units in our database and 

averaging the generation-weighted results, we determined that it 

would be reasonable to conclude that, through application of 

best practices and equipment upgrades, EGUs on average are at 

least capable of reducing their CO2 emissions by improving heat 

rate 4.3 percent in the Eastern Interconnection, 2.1 percent in 

the Western Interconnection, and 2.3 percent in the Texas 

Interconnection.811 

In addition to the statistical approach described above, we 

employed a “best annualhistorical performance” approach refined 

from the proposal, which compared each EGU’s best two-year 

rolling average gross heat rate to that EGU’s 2012 average 

annual gross heat rate.812 We then calculated the differences 

 

811 Conducting this analysis on a nationwide basis would have 

resulted in a finding that EGUs nationwide are capable on 

average of reducing their CO2 emissions by improving heat rate 

4.0 percent. See the table in this section and the GHG 

Mitigation Measures TSD for the results of this approach using 

benchmarks and consistency factors based on one-year averages. 

812 As described below, we also conducted this regionalized 

approach using each EGU’s best one-year rolling average. See the 

GHG Mitigation Measures TSD supporting the final CPP for more 

details. 
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across all EGUs in a region to determine the potential heat rate 

improvement that would result if, in 2012, each EGU had 

performed at the best two-year rolling average gross heat rate 

that the EGU achieved between 2002 and 2012. Under this analysis 

of historical gross heat rate, we determined that it would be 

reasonable to conclude that the average heat rate improvement 

potential from best practices and equipment upgrades is at least 

4.9 percent in the Eastern Interconnection, 2.6 percent in the 

Western Interconnection and 3.1 percent in the Texas 

Interconnection.813 

Our third and final approach,Finally, we employed the “best 

annualhistorical performance under similar conditions” approach, 

which combines aspects of the firstother two approaches. First, 

as with the “efficiency and consistency improvements under 

similar conditions approach,” we grouped hourly data for each 

EGU by ambient temperature conditions and hourly capacity 

factor. Next, we calculated each EGU’s best two-year gross heat 

rate for each of the 168 ambient temperature-capacity factor 

 

813 Conducting this approach on a nationwide basis would have 

resulted in a finding that EGUs nationwide are capable on 

average of reducing their CO2 emissions by improving heat rate 

4.6 percent. As described below, we also conducted this 

regionalized approach using one-year averages. See the GHG 

Mitigation Measures TSD supporting the final CPP for more 

details. 
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binbins.814 Similar to the “best historical average performance” 

approach, to calculate the potential heat rate improvement, the 

EPA then compared each EGU’s 2012 gross heat rate for each of 

the ambient temperature-capacity factor bins to the EGU’s best 

two-year gross heat rate for the corresponding bin. Accounting 

for differences in ambient temperature and capacity factor, we 

determined that under this analytical approach the average heat 

rate improvement potential from best practices and equipment 

upgrades was at least 5.3 percent in the Eastern 

Interconnection, 3.1 percent in the Western Interconnection and 

3.5 percent in the Texas Interconnection.815

As in the proposal, we additionally analyzed the data with 

our analytical approaches using one-year averaging periods in 

place of the two-year averaging periods described above.816

However, because our conservative overall methodology adopts the 

lowest value that is identified for a region by any of our 

 

814 As described below, we also conducted this approach using 

one-year averages for each EGU instead of two-year averages. See 

the GHG Mitigation Measures TSD supporting the final CPP for 

more details. 

815 Conducting this approach on a nationwide basis would have 

resulted in a finding that EGUs nationwide are capable on 

average of reducing their CO2 emissions by improving heat rate 

5.0 percent. 

816 The GHG Mitigation Measures TSD describes in more detail our 

rationale for using one- and two-year averaging periods in our 

analytical approaches and methodology as a whole. 
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reasonable analytical approaches, the inherently less 

conservative results obtained with one-year averaging periods 

(reproduced below) could not influence the outcome of our 

methodology as a whole. Overall, applying these three analytical 

approaches resulted in six heat rate improvement values 

generated for each region, each of which represents a reasonable 

estimate of the potential for heat rate improvements by EGUs in 

that region. Those values ranged from 4.3 to 6.9 percent in the 

Eastern Interconnection, from 2.1 to 4.7 percent in the Western 

Interconnection, and from 2.3 to 4.9 percent in the Texas 

Interconnection. In all three regions, the most conservative 

values were generated using the “efficiency and consistency 

improvements under similar conditions” approach with two-year 

averaging periods and consistency factors. As shown in the Table 

6, the values produced by that approach were the minimum values 

for each region produced by any of the three approaches: 

Table 6. Heat Rate Improvement Potential by Region and Averaging 

Period. 

Analytical approach 

Heat rate improvement potential 

(percent) 

by region and averaging period 

Western Texas Eastern 

1 

year 

2

year 

1

year 

2

year 

1

year 

2

year

Efficiency and 

consistency improvements 

under similar conditions 

3.5% 2.1%*

% 3.7% 2.3%*% 5.6% 4.3%*%
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Best annualhistorical

performance 4.1% 2.6% 4.2% 3.1% 6.3% 4.9%

Best annualhistorical

performance under 

similar conditions 

4.7% 3.1% 4.9% 3.5% 6.9% 5.3%

Accordingly, we have concluded that the an appropriatelya 

well-supported and conservative estimate of the potential heat 

rate improvements (and accompanying reductions in CO2 emission 

rates) that EGUs can achieve on average through best practices 

and equipment upgrades is a 4.3-percent improvement in the 

Eastern Interconnection, a 2.1-percent improvement in the 

Western Interconnection and a 2.3-percent improvement in the 

Texas Interconnection. The decision to use these values as the 

building block 1 potential in each region is based on the weight 

of evidence that these are conservative values; for each region, 

each of the three analytical approaches in our methodology 

supports our determination that the heat rate improvement value 

we selected is achievable. Taken individually, each approach 

provides an independently reasonable estimate of the potential 

for heat rate improvement. Furthermore, as described in the GHG 

Mitigation Measures TSD, these approaches are conservative on 

even an individual basis because they do not account for the 

full extent of heat rate improvements available through 

additional equipment upgrades. While some and best practices. 
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Some EGUs may not have achievedfaced difficulties achieving

significant heat rate improvement in the past and EGU owners may 

feel they face challenges in the future. Nevertheless, our 

methodology as a whole indicates that, on average, coal-fired 

EGUs on average can at minimumleast achieve the percentage heat 

rate improvement selected for their region through application 

of best practices and some of the available equipment upgrades. 

A more detailed discussion of the EPA’s analysis in determining 

the heat rate improvement potential for existing coal-fired EGUs 

may be found in the GHG Mitigation Measures TSD forsupporting

the final CPP Final Rule. 

No affected coal-fired EGU is specifically required to 

improve heat rate by any amount as a result of this rule. 

Rather, as described in section VI, the potential for heat rate 

improvement is used to determine a CO2 emission performance rate. 

Those affected EGUs that have done the most to reduce their heat 

rate will tend to be closer to that CO2 emission rate. In this 

sense, our approach to determining potential CO2 reductions 

through heat rate improvements is similar to the way EPA 

ordinarily approaches standards of performance.817 

 

817 To give an illustrative example, imagine a population of 

sources that emit Pollutant X. Half of the sources emit 

Pollutant X at 2500 lbs/hour, while the other half of the 
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In this final analysis, we do not delineate what proportion 

of the potential heat rate improvement can be expected from 

equipment upgrades versus best practices;818 only that these heat 

 

sources have scrubbers installed that reduce their emission 

rates to 1500 lbs/hour. Because the sources are evenly divided 

between those with and without scrubbers, the average emission 

rate for the population as a whole is 2000 lbs/hour. In this 

hypothetical, EPA decides to base requirements on the emission 

rate achievable through use of a scrubber, meaning that all 

sources will have to meet an emission rate of 1500 lbs/hour. 

Because the fleet as a whole has an average emission rate of 

2000 lbs/hour, it would be accurate for EPA to say that the 

fleet as a whole can reduce its emission rate by 25 percent -- 

from 2000 lbs/hour on average (only half the sources with 

scrubbers), to 1500 lbs/hour on average (all the sources with 

scrubbers). This description of what is possible for the fleet 

as a whole -- a 25-percent reduction in emission rate -- should 

not be misinterpreted as a statement that every individual

source is capable of further reducing its emissions by 25 

percent. The sources that have already installed scrubbers, and 

which are thus already operating at 1500 lbs/hour, would not be 

required to further improve their emission rate. 

818 Examples of the many types of best practices and equipment 

upgrades available to coal-fired EGUs include air heater 

baskets; air heater seals; automate steam system drains; heat 

rate optimization software; coal drying systems; 

combustion/optimization monitoring system; condenser cleaning 

system; condenser retubing; fan and pump variable frequency 

drives; steam seal and path upgrades; turbine internals 

replacement; turbine steam seal upgrades;adopting sliding 

pressure operation to reduce turbine throttling losses; 

installing intelligent sootblowing system software; the adoption 

and training of O&M staff on upgrading the combustion 

control/optimization system; installing heat rate optimization 

software; installing a production cost optimization program that 

benchmarks plant thermal performance using historical plant 

data; establishing centralized remote monitoring centers with 

thermal performance software for monitoring heat rates 

systemwide; repairing steam and water leaks; automating steam 

system drains; performing an on-site performance appraisal to 
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rate improvements are achievable in the regions through a 

combination of these methods. As discussed in section V.C.3 

below, we believe that a single heat rate improvement goal for 

each region incorporating both best practices and upgrades, 

based on the 11 years of hourly heat rate data for 884 coalfired EGUs available to the EPA, is a reasonable approach that 

is supported by our analysis, and is particularly conservative 

given that it does not account for the full range of heat rate 

 

identify potential areas for improved performance; developing 

heat rate improvement procedures; alignment of and training O&M 

staff on their use; aligning the cycle by isolating as much as 

possible of theto isolate or capture high-energy fluid leakage 

from the steam cycle; repairing utility boiler air in-leakage; 

performing utility boiler chemical cleaning; cleaning air 

preheater coils; production cost optimization programs that 

benchmark plant thermal performance using historical plant data 

along with an on-site performance appraisal to identify 

potential areas for improved performance; remote monitoring 

centers with thermal performance software for monitoring heat 

rate; repairing boiler air in-leakage; high pressure feedwater 

pump overhaul; repairing installing condenser tube cleaning 

system; retubing condenser; repairing/upgrading flue gas 

desulfurization systems; repairing steam and water leaks; 

cleaning air preheater coils; adjusting/replacing worn air 

heater seals; replacing corroded air heater baskets; replacing 

feed pump turbine steam seals; and sliding pressure operation to 

reduce turbine throttling lossesoverhauling high pressure 

feedwater pumps; installing fan and pump variable 

speed/frequency drives; upgrading turbine steam seals; upgrading 

all turbine internals; and installing coal drying systems. These 

and additional heat rate improvement measures are discussed 

further in the GHG Mitigation Measures TSD for the CPP Final 

Rule. 
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improvements achievable through additional equipment upgrades

and best practices. 

The performance rates quantified in section VI, below, 

reflect the region-specific values for heat rate improvement. 

Although the performance rates are based on the least stringent 

overall performance rate determined to be reasonable for any 

region, and are thus based in part on the percentage heat rate 

improvement identified for the region, this rule does not itself 

require any specific EGU to implement measures resulting in a 

specific percentage heat rate improvement. Rather, the 

percentage heat rate improvement value is merely reflected in 

the CO2 emission performance rates and equivalent CO2 emission 

corresponding mass-based and rate-based state goals provided to 

the states. Each state has the flexibility to develop a plan 

that achieves those CO2 performance rates or emission goals by 

assigning the emission standards the state considers appropriate 

to its affected coal-fired EGUs. Similarly, depending on the 

content of the applicable plan, sourcesaffected EGUs may achieve 

their emission standards through use of any of the building 

block measures described in this rule or any other measures 

permitted under the plan. 

b. Changes from the proposal. In the proposed rule, we 

determined that building block 1 measures could on average 
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achieve a 6-percent heat rate improvement from coal-fired EGUs 

in the U.S. based on a 4-percent heat rate improvement from 

implementation of best practices and a 2-percent heat rate 

improvement from equipment upgrades. Based on comments received 

and refinements made to our methodology for determining 

potential heat rate improvement from the hourly gross heat rate 

dataset of 884 coal-fired EGUs, we have conducted our analysis 

on a regional basis and reduced the overall expected percent 

heat rate improvement for coal-fired EGUs to 4.3 percent in the 

Eastern Interconnection, 2.1 percent in the Western 

Interconnection, and 2.3 percent in the Texas Interconnection.819

These values reflect improvements achievable through both best 

practices and equipment upgrades because, as described above, we 

also no longer include a separate estimation of the potential 

heat rate improvement achievable solely through equipment 

upgrades. 

We received comments on our proposed statistical 

methodology for determining the CO2 emission reductions 

opportunities achievable by coal-fired EGUs through heat rate 

improvements. We have closely reviewed those comments and, for 

 

819 Had the EPA maintained a nationwide approach to analyzing the 

potential reductions under building block 1, the result would 

have been 4.0 percent. 
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the final rule, have made refinements to our methodology, as 

described above and explained in more detail in the TSD.GHG 

Mitigation Measures TSD supporting the final CPP. 

In the final rule, the EPA extends the implementation 

deadline from 2020 to 2022. This additional time will be helpful 

to the states seeking to conduct more targeted analyses of the 

nature and extent of heat rate improvements that specific coalfired EGUs can make, considering specific recent improvements or 

upgrades, planned retirements of older coal-fired EGUs, and 

other relevant considerations. The extended deadline will also 

provide additional time to accommodate changes to heat rate 

monitoring methods at EGUs and for the installation of new 

pollution controls that comply with other rules, as discussed 

below in the summary of key comments. 

2. Costs of heat rate improvements 

By definition, any heat rate improvement made by EGUs for 

the purpose of reducing CO2 emissions will also reduce the amount 

of fuel that EGUs consume to produce the same electricity 

output. The cost attributable to CO2 emission reductions, 

therefore, is the net cost of achieving heat rate improvements 

after any savings from reduced fuel expenses. As summarized 

below, we estimate that, on average, the savings in fuel cost 

associated with the percentage heat rate improvements we 
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identified for each region would be sufficient to cover much of 

the associated costs. Accordingly, the net costs of heat rate 

improvements associated with reducing CO2 emissions from affected 

EGUs are relatively low. We recognize that this cost analysis 

will represent the costs for some EGUs better than others 

because of differences in individual circumstances. We further 

recognize that reduced generation from coal-fired EGUs due to 

the implementation of other building block measures would tend 

to reduce the fuel savings associated with heat rate 

improvements, thereby raising the effective cost of achieving 

the CO2 emission reductions from the heat rate improvements. 

Nevertheless, we still expect that the majoritya significant 

fraction of the investment required to capture the technical 

potential for CO2 emission reductions from heat rate improvements 

would be offset by fuel savings, and that the net costs of 

implementing heat rate improvements as an approach to reducing 

CO2 emissions from affected EGUs are reasonable. Even if we 

conservatively estimate that EGUs will largely rely on equipment 

upgrades rather than cheaper best practices to reduce heat rate, 

those reductions can generally be achieved at $100 or less per 

kW, or $5.81 to $11.63approximately $23 per metric ton of CO2

removed, as previously estimated in the proposal and described 

in detail in the GHG Mitigation Measures TSD supporting the 
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final CPP.820 Depending on the balance between equipment upgrades 

and best practices, improving heat rate would even result in a 

net savings for some EGUs. 

Based on the analyses of technical potential and cost 

summarized above and in the proposalChapter 2 of the GHG 

Mitigation Measures TSD, we find that heat rate improvements of 

4.3, 2.1 and 2.3 percent are reasonable and conservative 

estimates of what coal-fired EGUs in the Eastern, Western and 

Texas Interconnections, respectively, can achieve at a 

reasonable cost. 

3. Response to key comments 

Many commenters said that the EPA should have 

subcategorized by EGU design or operating characteristics for 

purposes of evaluating potential heat rate improvements under 

building block 1. 

Several studies categorize EGUs broadly by capacity, 

thermodynamic cycle, fuel rank or other characteristics. We 

considered subcategorizing the EGUs by their design and fuel 

characteristics under building block 1. Although grouping by 

 

820 TheseThe $100/kW cost figuresfigure from the proposal areis

now particularly conservative because they includeit included

the cost of significant equipment upgrades that improve heat 

rate, whereas building block 1 is now largely quantified based 

on low- or no-cost best practices, with a smaller portion of the 

remainder comprised of equipment upgrades. 
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categories does not account for all of the factors that may 

affect heat rate, it can provide a useful way of understanding 

the operating profile of classes of coal-fired EGUs and the 

fleet as a whole. HoweverHowever, we have declined to 

subcategorize among affected coal-fired EGUs for both technical 

and practical reasons. First, as discussed above, our assessment 

of heat rate improvement potential uses a unit-specific data 

methodology that compares each EGU’s performance against its own 

historical performance. By substantially basing our analysis on 

these unit-specific assessments, we inherently factor in the 

effect of numerous design conditions. We also conducted a 

regression analysis that evaluated the effect of numerous 

factors on heat rate, and found that subcategorizing would 

generally make little difference in our analysis. Additionally, 

subdividing the EGUs into subcategories would reduce the 

quantity of EGUs used to calculate each average, which would 

increase the influence of random and atypical variations in the 

data on the overall averages, and would thus decrease our 

confidence in the accuracy of the results. Furthermore, as a 

practical matter, states in determining the emission limitation 

for individual EGUs are free to apportion reductions in a way 

that reflects any subcategories of their choice.choosing when 

determining the emission standards for individual affected EGUs. 
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Additionally, commenters assert that because building block 1 is 

calculated on an average basis, some affected EGUs will have 

greater potential than others to reduce CO2 emissions through 

heat rate improvements. If an affected EGU cannot meet its 

particular emission standard because it has below-average 

potential to reduce emissions through heat rate improvements, 

then in instances where the EGU’s state plan allows emissions 

trading, the EGU can acquire credits or allowances from affected 

EGUs that have above-average potential. For a more detailed 

explanationfurther discussion of our reasonable decision not to 

subcategorize among coal-fired EGUs for purposes of determining 

building block 1, see the TSDGHG Mitigation Measures TSD 

supporting the final CPP. 

Many commenters told the EPA that EGUs already have 

undertaken significant efforts to operate efficiently to provide 

reliable electric service at the lowest reasonable cost; that 

they believe they cannot significantly improve heat rate; that 

best practice maintenance activities are performed on a daily 

basis, including during maintenance outages that allow for the 

inspection, cleaning and repair of all equipment; that extensive 

capital investments have been made to install state-of-the art 

equipment and replace equipment that is beyond repair; and that 

their employees continuously monitor and control operating 
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levels in the combustion process to maintain maximum combustion 

of fuel and to avoid wasting available heat energy. In summary, 

these commenters say they have expended considerable effort and 

resources to maintain peak boiler efficiency at all times and, 

therefore, the 6-percent heat rate improvement proposed for 

building block 1 is unreasonable to apply to EGUs across the 

board; the EPA should develop a rule that allows treatment of 

affected EGUs on a case-by-case basis. 

We commend the efforts of those who strive to operate and 

maintain EGUs in the best possible manner to minimize heat loss 

and CO2 emissions. This rule does allow for treatment of EGUs on 

a case-by-case basis. States may believe that individual 

considerations are appropriate in some cases and, accordingly, 

we have purposely allowed states to make decisions about how to 

implement specific CO2 reductions. Our determinations of 4.3-, 

2.1- and 2.3-percent heat rate improvement for EGUs in the 

Eastern, Western and Texas Interconnection, respectively, are 

conservatively based on the lowest value identified by any of 

our reasonable statistical analyses. If states choose to set 

limits on individual sourcesaffected EGUs based in part on the 

availability of heat rate improvements, the states are free to 

assess heat rate improvements on a more targeted, case-by-case 

basis that takes into account an EGU’s previous heat rate 
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improvement efforts, or lack thereof. The fact that states (or 

EGUs complying with state requirements) can make case-by-case 

decisions about how to achieve goals does not contradict our 

conservative estimates -- which are based on millions of hours 

of operating data reported to the EPA by EGUs -- of how much 

EGUs are capable of improving their heat rate in each region 

overall. Opportunities to improve heat rate abound for affected 

EGUs as a whole, as evidenced by the fact that the approaches in 

our statistical methodology each included a comparison of an 

EGU’s historical heat rate to its 2012 heat rate. FurthermoreOur 

estimates of the potential heat rate improvement are 

additionally conservative because they are based purely on 

comparisons among historical gross heat rate data, and thus do 

not reflect available, cost-effective opportunities to improve 

heat rate that affected EGUs never implemented during the study 

period. Finally, to the extent that an affected EGU was in 2012 

fully implementing every possible best practice for improving 

heat rate, it may still be capable of improving heat rate 

through equipment upgrades. 

Other commenters said that a 6-percent heat rate 

improvement overall is too high; that the heat rate improvement 

from upgrades are double-counted within the data used to 

determine heat rate improvements from best practices; and that 
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the 2-percent heat rate improvement specifically for upgrades 

was inappropriately based on “conceptual” improvements from only 

one study. 

We have reduced the 6-percent heat rate improvement from 

the proposed rule to three regionalized figures of 4.3 percent 

(Eastern), 2.1 percent (Western) and 2.3 percent (Texas), as 

discussed above and described in detail in the revised TSD.GHG 

Mitigation Measures TSD supporting the final CPP. We expect 

that, on average, affected coal-fired EGUs can at a minimum 

improve heat rate in these amounts by implementing best 

practices and equipment upgrades identified in the GHG 

Mitigation Measures TSD. These overall heat rate improvement 

figures do not include an estimated percent heat rate 

improvement attributable specifically to upgrades. Although we 

are no longer including in our calculation of building block 1 a 

separate 2-percent heat rate improvement attributable solely to 

equipment upgrades, this decision is not because we believe that 

our initial 2-percent assessment of equipment upgrades was 

incorrect. To the contrary, the information presented in the S&L 

study was similar to that in other industry reports and studies 

-- many of which were referenced in the proposal TSD -- 

describing potential heat rate improvements at EGUs from all 

types of equipment upgrades. However, we recognized that the 
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possibility existed that some limited portion of that 2 percent 

was also reflected in our statistical analyses of historical 

gross heat rate data. In order to ensure that our methodology 

did not double-count an indeterminate amount of heat rate 

improvement available through equipment upgrades, we 

conservatively set aside the entire additional 2 percent 

attributable solely to equipment upgrades. Accordingly, we 

determined the amount of potential heat rate improvement in the 

BSER solely from the heat rate analyses described above, which 

account for improvements through best practices and a 

portionequipment upgrades that were at some point achieved by an 

EGU, but not for the full range of thebest practices and

equipment upgrades that are actually available. 

Commenters also said that the EPA did not look at important 

factors that affect heat rate such as coal type, boiler type, 

cooling water temperature, age, nameplate capacity or the use of 

post-combustion pollution controls. 

Our statistical methodology compared each unit to its own 

historical performance and, therefore, largely accounts for the 

effects that a unit’s design or fuel characteristics would have 

on heat rate. As discussed above, our methodology used hourly 

data from 884 units over an 11-year period (2002-2012) and 

compared the variability in the heat rate of each individual 
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unit to that unit’s own performance. By assessing potential heat 

rate improvement by first looking at unit-specific data, our 

methodology inherently factors in the possible effects of design 

and fuel characteristics (e.g., coal type, boiler type, 

nameplate capacity, age, cooling water system, air pollution 

controls) on heat rate and heat rate variability. 

Although cooling water temperature likely plays an 

important role in a coal-fired EGU’s heat rate, as stated by 

commenters, there are no consistent quality-assured hourly 

cooling water temperature data available to the EPA. However, in 

an effort to determine the potential effect of cooling water 

temperature on heat rate, we looked at a sample of 45 coal-fired 

EGUs at 19 facilities for which we had hourly surface water 

temperature data (used as a surrogate for cooling water) from 

monitors located nearby and upstream of cooling water intake 

points. Our analysis found that surface water temperature did 

explain some of the variation in heat rate, but that surface 

water temperature is strongly correlated with ambient air 

temperature -- a variable we did control for in our methodology. 

Because of the strong correlation between ambient air 

temperature and surface water temperature, the lack of hourly 

cooling water temperature data, the availability of a 

comprehensive dataset of nationwide hourly ambient air 
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temperature, and the similar explanatory power of surface water 

temperature and ambient air temperature, it is unlikely that 

separately addressing cooling water temperature would 

significantly change the results. Rather, we are confident that 

our use of hourly ambient air temperature in our analyses 

adequately addressed any significant impact of cooling water 

temperature. See the TSDGHG Mitigation Measures TSD supporting 

the final CPP for further details about this analysis. As 

described further in thethat TSD, the other potentially relevant 

variables for which we did not directly control are unlikely to 

significantly affect the average heat rate. 

Commenters said that the heat rate improvement attributable 

to upgrades will degrade over time or require repeated and 

costly further upgrades. 

We are aware that some heat rate improvement measures can 

degrade over time. Like most power plant components, some heat 

rate improvement technologies require maintenance in order to 

sustain their efficacy over time. Therefore, to avoid 

degradation, personnel at EGUs will need to diligently apply 

“best practices” on a regular basis, a practice that numerous 

commenters say is standard operating procedure. The S&L study 

includes estimates of associated O&M costs for each heat rate 

improvement method that is discussed. As we explained in the 
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proposal, the related O&M costs of diligently applying best 

practices are relatively small compared to the associated 

capital costs and would, therefore, have little effect on the 

economics of heat rate improvements. 

Commenters stated that heat rate improvement should be set 

on a basis that is narrower than nationwide -- for example, 

state-by-state or unit-by-unit. 

The EPA did not propose and is not finalizing a rule that 

sets heat rate improvement goals for individual states or for 

individual coal-fired EGUs. Instead, in the approved state plans 

developed under this rule, each state will set the emission 

standards for its various coal-fired EGUs. In doing so, the 

state may take into account its own view of the amount of heat 

rate improvement needed (if any) at specific EGUs, and may look 

to the percentEPA’s analysis of heat rate improvement for 

itspotential in the applicable region as a guide, while keeping 

in mind the uniformCO2 emission performance rate. TheThis broadbased approach is consistent with the traditional rules 

evaluating the potential for emission reductions on a sourcecategory basis, and is consistent with the broader goal-setting 

purpose of this rule. Furthermore, the final rule establishes a 

uniform national performance rate based on the least stringent 

regional performance rate calculated with the building blocks. 
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Accordingly, affected sourcesEGUs in regions not setting the 

national level have emission reduction opportunities beyond 

those reflected in the applicable performance rate. For 

The heat rate improvement measures comprising building 

block 1 would ordinarily be evaluated on a nationwide basis. 

However, in this instance there are two good reasons to 

calculate building block 1 on a regionalized basis. First, a 

regionalized approach is consistent with the EPA’s approach to 

determining the other building blocks. For building block 1, 

this means that the heat rate improvement should reflect only as 

much potential for emission reduction from building block 1 as 

our analyses indicate can be achieved on average by the affected 

coal-fired EGUs in the contiguous United States, a methodology 

that assesses potential heat rate improvement within that 

region. This ensures that the BSER for each interconnection 

reflects the regional natureregion is representative of the 

interconnected electricity system and the region-wide 

scopecharacteristics and opportunities available within that 

region, rather than a less logical combination of opportunities 

available for in the region and opportunities nationwide. 

Second, a regionalized approach provides a more representative 

average of the potential heat rate improvement that EGUs in a 

given region are capable of achieving. The populations of 
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affected coal-fired EGUs in each region differ in some respects, 

as discussed in the GHG Mitigation Measures TSD, and the more 

nuanced regionalized approach thus indirectly accounts for some 

of those EGUs to access emission reduction measures through 

emissions trading.821systemic differences. For these and other 

reasons described in Section V.A. of the preamble with respect 

to the BSER as a whole, we have reasonably based building block 

1 on a regionalized approach. Applying this regionalized 

approach to building block 1 strikes an appropriate balance 

between the proposed nationwide analysis and commenters’ 

suggested state-specific analysis, which does not fully reflect 

the interconnected nature of the system within which affected 

coal-fired EGUs operate. 

The practical consequence of calculating building block 1 

on a regionalized versus nationwide basis is minimal. This is 

because the CO2 emission performance rates are based on the 

overall performance rate determined to be reasonable for EGUs in 

the Eastern Interconnection. Our methodology identifies a 4.3 

percent potential improvement in the Eastern Interconnection, 

 

821 As described in section [xxx], affected EGUs in states and 

territories that are isolated from the three major 

interconnections lack access to the same opportunities to access 

the building blocks across wide regions and, accordingly, have 

performance rates based on data specific to that state or 

territory. 
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compared to a 4.0 percent figure across all three 

interconnections. 

We further note, along with some commenters, that sitespecific engineering studies or unit-by-unit analyses of heat 

rate improvement potential for coal-fired EGUs are not available 

to the EPA; only a small number of site-specific case studies 

are available in the public literature. We considered that for 

the development of EPA to develop a comprehensive , unit-by-unit 

heat rate improvement study for each of the nearly 900 coalfired EGUs covered by this rule on a unit-by-unit basis is from 

scratch, it would likely to cost on the order ofAgency $50,000 

to $100,000 to study each EGU (almost $50 to $100 million total) 

and require three to four years to complete in total. 

Commenters. Such a granular analysis would not serve the broader 

goal-setting purpose of this rulemaking. We agree with 

commenters who have pointed out, and we agree, that a heat rate 

improvement-estimating effort of that magnitude and duration 

iswould be unnecessarily lengthy and expensive, and we believe 

would not serve the broader goal-setting purpose of this 

rulemaking.. Nor would such a granular analysis be a necessary 

predicate for states to develop emission standards, or for EGUs 

to comply with those emission standards. Rather, our 

methodology’s reliance on individualized, unit-by-unit hourly 
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Page 884 of 2153

performance data from 884 EGUs provides conservative and 

reasonable regional estimates of heat rate improvement 

potential. Indeed, given the conservative nature of our 

methodology, a unit-specific approach that evaluates the full 

range of best practices and equipment upgrades available at 

individual EGUs -- including upgrades not accounted for here -- 

would be more likely to result in higher overall heat rate 

improvement figures than we are finalizing for building block 1. 

Furthermore, site-specific information forms the foundation of 

the EPA’s estimated heat rate improvement potential, and similar 

data likely would be used in any site-specific heat rate 

improvement engineering study. Finally, EGU-specific detailed 

design and operation information is not consistently available 

for all the factors that influence heat rate. The EPA has used 

the comprehensive data that are available to reasonably and 

conservatively estimate potential heat rate improvement in each 

region.

Commenters also said that shifting electricity generation 

from coal-fired EGUs to other EGUs because of measures 

implemented under other building blocks will lower the capacity 

factors of coal-fired EGUs, and thus increase, not decrease, 

their heat rates. 
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We expect that most states will develop plans that optimize 

the operation of existing coal-fired EGUs while utilizing the 

other building blocks and other measures to reduce emissions 

from carbon-intensive generation. From our IPM projections, the 

average annual capacity factor of existing coal-fired EGUs that 

are expected to remain in operation in 2030 will actually 

increase compared to 2012. This projection -- which is further 

described in the GHG Mitigation Measures TSD -- incorporates 

expected retirements of inefficient units and generation shifts 

away from using coal-fired EGUs as peaking units. 

Commenters also noted that the EPA used net heat rate in 

state goals, but used gross heat rate in its heat rate 

improvement analysis -- potentially ignoring the detrimental 

effect that parasitic load from air pollution control devices 

(APCD) and other equipment can have on net heat rate. 

The EPA’s variability analysis necessarily and reasonably 

used gross output data for each of the 884 EGUs in the EPA’s 

database because they are the only publicly available, unitspecific, hourly performance data. By definition, improvement in 

gross heat rate would be reflected in the net heat rate. Gross 

heat rate is the total heat output from the EGU, in units of 

Btu/gross kWh, and includes the power used by auxiliary 

equipment required to operate the EGU itself. By contrast, net 
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Page 886 of 2153

heat rate is the remaining Btu/kWh after subtracting the power 

used by the EGU’s own auxiliary equipment from the gross heat 

rate value, i.e., what the EGU is able to provide to the grid. 

Improvements in net heat rate alone (e.g., reducing parasitic 

load of on-site equipment) may be possible on many units. 

Therefore, our use of gross heat rate to estimate potential heat 

rate improvement was conservative because of the additional 

opportunities to achieve the uniform performance rate through 

improvements in net heat rate alone. 

Commenters also raised concerns that the EPA was not taking 

into account net heat rate increases due to additional add-on 

pollution controls that may, for some units, be required by 

other rules.822

The results of our statistical analysis are based on gross 

heat rates and would not change with installation of emission 

controls for CSAPR, MATS, or other rules because these controls 

will add parasitic load requirements and thereby have an impact 

on the net heat rates only. Furthermore, we conservatively 

consider region-wide net heat rate improvement potential to be 

the same as that indicated for the region-wide gross heat rate, 

when in fact it is not. In order to check our assumptions 

 

822 See above for an explanation of gross versus net heat rate. 
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concerning gross versus net heat rate, we used the IPM Power 

Sector Modeling Platform (version 5.14) and National Electric 

Energy Data System (NEEDS) (version 5.14) to analyze the 

anticipated incremental heat input required to operate 

additional add-on controls to comply with various EPA rules, 

including CSAPR, MATS, effluent guidelines for EGUs, and coal 

combustion residuals. From this analysis, we project that 

between 2012 and 2025, existing coal-fired EGUs are expected to 

install approximately 18.6 GW of wet flue gas desulphurization 

(FGD), 16.6 GW of dry FGD, 24.9 GW of selective catalytic 

reduction (SCR), and 3.9 GW of selective noncatalytic reduction 

(SNCR). The resulting impact from new pollution controls on 

existing coal-fired EGUs’ heat rate is expected to be very 

small, at conservatively less than 31 Btu/kWh, or less than 0.3 

percent in 2025.823 After 2025, this estimate is particularly 

conservative because the EPA’s cost performance models 

overestimate the parasitic load from individual add-on controls 

for future years. Furthermore, at some EGUs these newer 

pollution control devices will replace existing pollution 

control devices. Accordingly, for these EGUs, the minimal 

 

823 When considered on a regional basis, we expect these controls 

to impact heat rate by approximately 0.3 Btu/kWhpercent in both 

the Eastern and Western Interconnections, and by less than 0.1 

percent in the Texas Interconnection. 
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increase in net heat rate due to power required to operate new 

controls will be at least partially offset by the decrease in 

net heat rate caused by removal of the control devices currently 

in place. For more information about this analysis, see the 

TSDGHG Mitigation Measures TSD supporting the final CPP. 

Commenters contended that the 11 years of data used to 

evaluate potential heat rate improvement is too broad, and that 

the population of domestic coal-fired EGUs has changed 

significantly over this time period. 

The 11-year span for the hourly gross heat rate data is 

appropriate because it represents a wide variety of economic 

conditions, market conditions and fleet composition, while also 

capturing the relatively recent historical performance of 

affected coal-fired EGUs. We also noted in the proposal TSD that 

the population of coal-fired EGUs used in the analytical 

approaches to determine potential heat rate improvement is made 

up of coal-fired EGUs that operated in 2012. The gross heat rate 

data of any coal-fired EGUs that retired prior to 2012 were not 

included in the dataset. 

Commenters stated that many of the changes in heat rate 

reflected in the 11-year hourly gross heat rate dataset are 

attributable to changes in monitoring methodology, and thus do 

not represent heat rate improvements attributable to best 
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Page 889 of 2153

practices or equipment upgrades. In addition, commenters are 

concerned that changes to the monitoring methodology in the 

future could artificially alter the measured heat rate. 

Different stack gas flow monitoring methods can yield more 

or less accurate measurements of heat input and CO2 emissions. 

These differences depend on the characteristics of the stack gas 

flow where the monitoring and reference method measurements are 

taken, and which options under the Part 75 emission measurement 

rules are chosen in the application of the various flow rate 

reference methods. In general, more accurate stack gas flow 

monitoring methodologies yield lower values that, when used to 

calculate emissions or heat input, may lower the heat rate 

values reported to the EPA. 

Some EGUs adopted monitoring methodologies that have the 

potential to affect the exactness of the data we used for 

assessing heat rate improvements. However, as discussed in 

detail in the GHG Mitigation Measures TSD supporting the final 

CPP, our review of the data shows that a relatively small amount 

of the data are affected by these changes; we remainare

confident that the values adopted for building block 1 are 

conservative and reasonable estimates of the potential for heat 

rate improvement in each region. In many instances,Some changes 

in monitoring methodology would have the result of actually 
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underestimatingtending to cause us to underestimate the 

potential for heat rate improvement at some EGUs.. Furthermore, 

because our methodology analyzes percentage heat rate 

improvement based on 2012 gross heat rate data, our results are 

unaffected by EGUs that consistently used lessmore accurate 

monitoring methodologies that tend to overestimate heat rate.in 

2012 or used the same monitoring methodologies consistently 

throughout the 11-year study period. For these and other reasons 

discussed in detail in the GHG Mitigation Measures TSD, we 

remain confident in our results despite the marginal differences 

attributable to monitoring methodologies in some of the heat 

rate data for a subset of EGUs.824 

In terms of concerns with future methodological changes, 

the overwhelming majority of the 884 EGUs in the dataset we used 

to assess heat rate improvement have already changed their stack 

gas flow monitoring methodology in 2012 or earlier. Furthermore, 

extension of the compliance date to 2022 for this rule, as 

discussed above, more than adequately allows enough time for 

EGUs to determine how to actually improve their heat rates and 

 

824 Furthermore, on a fundamental level, our methodology accounts 

for a certain amount of any residual inexactness because we have 

conservatively adopted the lowest value identified by any of our 

reasonable approaches -- all three of which are themselves 

conservative because they do not account for the full extent of 

heat rate improvements achievable through equipment upgrades. 
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lower CO2 emissions while accommodating future changes to 

monitoring methodologies. Consult the TSD forFor a more detailed 

explanation, see the GHG Mitigation Measures TSD supporting the 

final CPP. 

Commenters said that there is no proof that lowering the 

heat rate will reduce variability or that reduced variability 

will reduce heat rate, i.e., correlation does not prove 

causation. 

As an initial matter, it is important to note that for the 

final rule the EPA used three types of statistical analyses to 

evaluate and estimate potential heat rate improvements of coalfired EGUs, and only one of these analyses involved any 

consideration of heat rate variability. All three types of 

statistical analyses are described in the TSDGHG Mitigation 

Measures TSD supporting the final CPP. 

These commenters are correct that, in the abstract, 

reducing heat rate variability only means that heat rate will be 

more consistent -- not necessarily lower or higher. However, our 

analysis is not an abstract evaluation of the potential to 

reduce variability, as commenters suggest, but rather is an 

evaluation of the potential heat rate improvement achievable 

through reducing variability -- i.e., reducing variability to 

achieve a more consistently low heat rate. See the more detailed 
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discussion of the statistical procedures used for the final 

rule, above. In particular, the application of a “consistency 

factor” in the analyses performed for both the proposed and 

final rule demonstrates the potential results if each individual 

EGU operated slightly more consistently with the lower heat 

rates that the EGU had itself previously achieved under similar 

conditions. 

The consequence of a reduced heat rate is, of course, a 

lower rate of CO2 emissions, which is the purpose of the BSER for 

building block 1. This way of thinking about reduced variability 

is consistent with industry’sthe utility power sector’s own 

efforts to reduce variability, which are aimed at securing the 

economic benefits of a more consistently lower overall heat 

rate. 

Some commenters expressed concern that heat rate 

improvements could trigger applicability of new source review 

(NSR) provisions. The relationship of this final rule to other 

regulatory provisions, including NSR, is discussed in 

Sectionsection X of the preamble. 

D. Building Block 2—Generation Shifts Among Affected EGUs 

The second element of the foundation for the EPA’s BSER 

determination for reducing CO2 emissions at affected fossil fuelfired EGUs entails an analysis of the extent to which fossil 
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steam EGUs can shift generation to existing NGCC EGUs. In this 

section, we define building block 2 as the gradual shifting of 

generation from existing fossil steam to existing NGCC within 

each region up to a maximum NGCC utilization of 75 percent on a 

net summer basis. In each year of the interim period, this 75 

percent net summer maximum potential is subject to a regional 

limit informed by historical growth rates. 

This section summarizes the EPA’s analysis supporting that 

definition. We begin by discussing the sector’s ability to 

reduce CO2 emissions by shifting generation, including selected 

background information, data on trends toward greater NGCC 

generation, and various mechanisms for executing or facilitating 

generation shifts. Next, we describe the amount and timing of 

generation shift we have determined to be achievable through the 

building block. We then discuss various elements supporting our 

quantification of achievable generation shift, including the 

technical feasibility of NGCC units to increase generation; 

historical shifts to NGCC generation; considerations related to 

reliability, natural gas transmission infrastructure, natural 

gas production, and electricity transmission infrastructure; and 

regulatory flexibility. A discussion of costs follows. Finally, 

we respond to certain comments not addressed in the preceding 

discussions. 
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1. Demonstration of Abilityability to Reducereduce CO2

Emissionsemissions through Shifting Generationshifting 

generation 

a. Background of utility power sector. The ability to 

switchshift generation from higher- to lower- emitting 

generation reflectssources is compatible with the way EGUs are 

generally dispatched.825 The standard approach to dispatching 

generation is through Security Constrained Economic Dispatch 

(SCED), a well-established practice in the electric power 

industry.826 As the name indicates, SCED has two defining 

components: economic operation of generating facilities and 

ensuringassurance that the electric system remains reliable and 

secure.827 Economic dispatch generally refers to shorter-term 

planning and operations from a day ahead through real time. 

During this period, generating units are committed – a process 

known as “unit commitment” where,” in which units are committed 

to be ready to provide generation to the system when they will 

 

825 See Preamble,preamble section II.C.1, History of the Power 

sectorSector, for background to this discussion. 826 “Economic Dispatch: Concepts, Practices and Issues”, FERC 

Staff Presentation to the Joint Board for the Study of Economic 

Dispatch”, Palm Springs, California, November 13, 2005. A copy 

of this presentation is available in the docket for this rule.

827 “Security Constrained Economic Dispatch: Definitions, 

Practices, Issues and Recommendations: A Report to Congress”, 

Federal Energy Regulatory Commission, July 31, 2006. 
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be needed – and then dispatched in real time to meet the 

electricity demand onof the system. Overall changes in the level 

of generation from different facilities are also planned over 

time periods longer than this two-day dispatch period. Over a 

calendar year, for example, units are planned and scheduled 

seasonally or monthly to ensure that sufficient capacity and 

energy will be available to meet expected loads in an area. Over 

a period of a week, units are committed to be prepared to start 

up or shut down to meet forecast loads, and dispatch is 

coordinated within this planning and unit commitment framework. 

This process enables system operators to respond quickly to 

short-term changes in demand, and also to shift generation among 

different generation types to match longer-term requirements and 

goals. 

 EGUs using technologies with relatively low variable 

costs, such as nuclear units, are for economic reasons generally 

operated at their maximum output whenever they are available. 

Renewable EGUs such as wind and solar units also have low 

variable costs, but in any event arethe magnitude and timing of 

their output generally operated whendepend on wind and sun 

conditions permit rather than atthe operators' discretion. In 

contrast, fossil fuel-fired EGUs have higher variable costs and 

are also relatively flexible to operate. Fossil fuel-fired EGUs 
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are therefore generally the units that operators use to respond 

to intra-day and intra-week changes in demand. Because of these 

typical characteristics of the various EGU types, the primary 

opportunities for switching generation among existing units 

available to EGU owners and grid operators generally consist of 

opportunities to shift generation among various fossil fuelfired units, in particular between coal-fired EGUs (as well as 

oil- and gas-fired steam EGUs) and NGCC units. In the short term 

— that is, over time intervals shorter than the time required to 

build a new electric generation unit — fossil fuel-fired units 

consequently tend to compete more with one another than with 

nuclear and renewable EGUs. The amount of generation shifting 

from coal-fired EGUs to NGCC units that takes place as a result 

of this competition is highly relevant to overall power sector 

GHG emissions, because a typical NGCC unit produces less than 

half as much CO2 per MWh of electricity generated as a typical 

coal-fired EGU. Over the past decade or more, since 

b. Trends in generation shifts from coal-fired to natural gasfired sources. Since at least 2000, fossil fuel-fired generation 

has been shifting from coal- and oil-fired EGUs to natural gas 

NGCC units, both as a result of construction of newadditional

NGCC units, and also as a result of dispatch of pre-existing 

NGCC units at higher capacity factors. As a result, generation 
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Page 897 of 2153

from NGCC EGUs in 2012 reached over four times the level of NGCC 

generation in 2000, while generation from coal and oil/gas steam 

EGUs decreased by around one third.828 As we demonstrate 

elsewherein the GHG Mitigation Measures TSD, NGCC units are 

capable of operating at higher annual capacity factors than they 

have historically, so there remains considerable opportunity for 

increased use of existing NGCC units to replace generation 

currently supplied by higher -emitting coal and oil/gas steam 

units. The electric utility industry is thus well-positioned to 

address the requirements of this building block by increasing 

use of existing NGCC units and correspondingly decreasing use of 

steam units. The electric industry has been shifting generation 

to NGCCsNGCC units in recent years and is expected to continue 

this shift in the future.to retire coal capacity and add new 

NGCC capacity. In the reference case without 111dimplementation 

of CO2 emission limitations, EIA forecasts 40 GW of coal 

retirements and 53 GW of NGCC capacity additions from 20122014

to 2030.829 An EPA review of state Integrated Resource Plans 

(IRPs) shows a pattern of shifting away from coal steam 

generation to NGCC.capacity to NGCC capacity and, in some cases, 

 

828 Ventyx Electric Power Database. 829 Energy Information Administration, Annual Energy Outlook 2015 

reference case, ref2015.d021915a. 
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conversion of coal steam capacity to natural gas steam capacity. 

For example, Ameren plans to add 600 MW of NGCC capacity and 

convert two coal units to natural gas steam units, and Duke 

plans to add 680 MW of NGCC capacity and convert one coal unit 

to a natural gas steam unit.830

A review of the electric utility industry structure also shows 

that that utilities are able to shift generation among existing 

affected sources to meet the requirements of this building 

block. In the first instance, many of the NGCC units are owned 

by the same companies or affiliates as steam units.c. Mechanisms 

for dispatch shifts from coal-fired to natural gas-fired 

generation. There are a variety of patterns of ownership and 

operational control of EGUs; these ownership and operational 

structures influence how EGUs will respond to this building 

block. However, all owners and operators have the ability to 

comply by using this building block. In terms of ownership, 

investor-owned utilities (IOUs) serve about 75 percent of the US 

population, while consumer-owned utilities serve the remaining 

25 percent.831 In states that have maintained traditional 

 

830 For further examples, see the memo entitled “Review of 

Electric Utility Integrated Resource Plans” (May 7, 2015) 

available in the docket. 

831 Regulatory Assistance Project, Electricity Regulation in the 

US: A Guide, Page 9, March 2011. 
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regulation, IOUs are generally vertically integrated (owning 

generating capacity as well as transmission and distribution 

infrastructure), and the wholesale sales of these EGUs are 

regulated by the state; in states that have deregulated their 

retail service, ownership of the EGU is separated from ownership 

of transmission, and wholesale sales of generation are regulated 

by FERC. Consumer-owned utilities comprise municipal utilities, 

public utility districts of various types owned by government 

agencies, nonprofit cooperative entities (co-ops), and a number 

of other entities such as Native American Tribes. 

Operational control of the dispatch of power over the 

electricity grid is superimposed on this pattern of ownership. 

Prior to electricity restructuring, this dispatch was typically 

operated by major vertically-integrated utilities or by public 

power entities. Over the last 15 years, large portions of the 

power grid are now independently operated by Independent System 

Operators (ISOs) or Regional Transmission Operators (RTOs). 

These entities are regulated by FERC and dispatch power from 

multiple owners to meet the loads on the bulk power grid. 

The combination of multiple ownership and types of 

operational control adds to the complexity of electricity 

dispatch, but all affected EGUs, regardless of ownership and 

type of control, can use this building block to comply with the 
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final rule. The principal difference among the differing 

entities lies in the types of methods that are available for the 

affected EGU owner to bring about the shift in generation that 

will make use of this building block for compliance. There are 

several alternatives to accomplish this result: the owner of the 

higher-emitting affected EGU may also own, or have affiliates 

that own, lower emitting generation and thus reduce its own 

generation and use its control over these other EGUs to increase 

their generation; an EGU may be able to reduce its generation 

and buy replacement power from the market that is lower 

emitting; or the EGU may be able to reduce its generation and 

procure generation from a separately-owned lower-emitting EGU. 

These alternatives will be available in states with either rate 

or mass-based state plans without any change in their general 

form. Under a rate-based state plan, an EGU owner may also be 

able to purchase ERCs and average the ERCs into its emission 

rate for purposes of demonstrating compliance with its standard 

of performance. Under standards of performance that incorporate 

emissions trading, an EGU owner may be able to purchase ratebased emission credits or mass-based emission allowances not 

needed by other EGUs and use those credits or allowances to help 

achieve its standard of performance. 
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The potential to shift generation identified for this 

building block is entirely consistent with the existing economic 

dispatch protocols described above. State environmental policies 

can shift generation in two ways. The first is operational 

restrictions, such as permit limits on the number of hours that 

an EGU can operate in order to limit emissions. The second is 

changes in the relative costs of generation among different 

types of EGUs related to pollution reduction measures. For 

example, a regulation that necessitates the use of a control 

technology that requires the application of a reagent in a 

certain kind of EGU will increase the variable cost of operating 

that plant, which in turn may reduce the amount of generation it 

is called upon to deliver to the grid through securityconstrained economic dispatch procedures. 

In an organized market, where the system operator 

dispatches units partly based upon costs, an electric power 

plant that experiences an increase in its variable costs will 

tend to operate less than it otherwise would have. For example, 

market-based pollution control programs require units to hold 

tradable allowances to authorize their emissions of a regulated 

pollutant. Such an allowance-holding requirement puts a price on 

the act of emitting the regulated pollutant, which increases the 

operating costs of units that emit that pollutant, and thus such 
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units will be dispatched less than they otherwise would without 

such an allowance-holding requirement. The Regional Greenhouse 

Gas Initiative (RGGI) is an example of a state program that has 

this effect. In the present rule, although shifts in the mix of 

generation to address the costs of pollution control can lead to 

higher electricity generating costs overall, the EPA analysis 

shows these costs to be modest and well below their associated 

benefits.832

Many of the NGCC units are owned by the same companies or 

affiliates that also own steam units. In these cases, changes in 

EGU generation can be planned by the company or affiliate 

without the need to engage in separate market transactions with 

outside parties. Where the affected EGU owner is also the 

dispatch entity, as in most traditional market structures, the 

EGU owner will generally have operational control over the unit. 

In organized markets such as RTOs, the owner can exercise a 

similar control over the levels of generation across units by 

how it offers generation from its units to the market operator. 

In both types of market structures, environmentalEnvironmental

conditions, such as compliance costs or limits on generation, 

can be factored in with fuel costs to influence the timing of 

 

832 See the Regulatory Impact Analysis. 
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when the unit is offered in the dispatch, as well as the price 

and generation level at which the unit is dispatched. An 

analysis of generation data from steam and NGCC units in 2012 

shows that only 23 percent of the steam generation occurred 

where the entity (a company or affiliate) had no NGCC 

generation. Among entities with both steam and NGCC generation, 

an increase in NGCC generation from 2012 capacity factors to a 

capacity factor of 75 percent on a net basis would represent 33 

percent of the 2012 steam generation.833 for purposes of 

determining when the unit is committed to be available, how the 

unit can be most efficiently cycled, and at what level the unit 

is dispatched.

An analysis of generation data from steam and NGCC units in 

2012 shows that 77 percent of the steam generation occurred from 

an EGU that owned, or that had an affiliate that owned, NGCC 

generation. Eighty percent of the generation shift potential 

identified in this building block (increasing NGCC generation up 

to a 75 percent capacity factor on a net basis to replace steam 

generation) could occur among these entities that own (either 

directly or through affiliates) both steam and NGCC 

generation.834 These data show that most EGU generation relevant 

 

833 Egrid database. 834 SNL Energy. Data used with permission. Accessed May 2015. 
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for this building block is produced by entities that own both 

steam and NGCC generation. 

Another alternative available to an affected EGU owner that 

does not also own NGCC generation is for the higher-emitting 

affected EGU to reduce its generation and purchase replacement 

power from the market. In organized markets such as RTOs, it is 

available through standard practice, because the owner impacts 

how its EGUs are dispatched based upon how it bids into the RTO 

market. In this case, the owner can exercise control over the 

levels of generation across units by when it offers generation 

to the market operator (the RTO or ISO), and the prices it bids 

for this generation. As in traditional economic dispatch by a 

utility, environmental conditions, compliance costs, or limits 

on generation can be incorporated by the owner into the 

determination of the cost-effective generation pattern of its 

EGUs. 

In regions with organized electricity markets (including, 

but not limited to, RTOs or ISOs), the various types of EGU 

owners of higher-emitting sources can reduce their generation, 

and any resulting deficit in generation on the system can be 

supplied from other EGUs in the region; for example, a coalfired unit can reduce generation that is then replaced through 

the operation of the market by generation from an NGCC unit, 
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Page 905 of 2153

subject to dispatch by a regional operator to ensure the 

reliable delivery of the generation to loads within the region. 

To comply with this rule, higher-emitting steam units will need 

greater reductions relative to lower-emitting NGCC units which 

will, in turn, tend to raise steam unit costs compared to NGCC 

units. As a result, the bids that a steam unit provides a market 

operator will rise relative to NGCC units. This process of 

reducing generation from a higher-emitting unit will lead to 

substitution of lower-emitting generation. 

EGU owners that do not participate in an organized 

electricity market may nevertheless purchase power from the 

wholesale power market. Purchases in the wholesale power market 

can be spot purchases, which are typically general purchases of 

system power supplied by the EGUs across a region, or contract 

purchases, which may have more provider-specific characteristics 

(such as specifying the type of unit that is providing the 

power). Purchases between EGUs through the wholesale power 

market will have similar emission-lowering properties as 

operation of the organized market discussed above, because 

dispatch in balancing areas outside RTOs and ISOs also follows a 

similar economic dispatch protocol that is informed by each 

unit’s production costs and environmental limitations. 
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Under this alternative, the steam generators may, in 

effect, realize emission reductions from building block 2 simply 

by reducing their generation. Steam generators do not need to 

purchase replacement electricity as a prerequisite for realizing 

emission reductions from reducing their own generation because 

other generators already have an incentive to provide as much 

electricity as load-serving entities are willing to buy in order 

to satisfy electricity demand.835 As noted above, higher-emitting 

generation sources will have to incorporate correspondingly 

higher costs of pollution reduction into their supply bids 

compared to lower-emitting generation sources, and as a result, 

load-serving entities will seek to buy a greater share of 

electricity from the lower-emitting sources because their supply 

bids will be more economically attractive. Once the steam 

generators reduce their generation (and associated emissions), 

the other entities in the electricity system arrange for the 

 

835 Some owners or operators of steam generators may have 

electricity supply obligations to which they may be applying 

power from those steam generators. However, such parties may 

fulfil those supply obligations using the wholesale power market 

in the exact same way described here that enables any other 

generator with economically attractive electricity to offer such 

supply. In other words, the ability of a steam generator to 

reduce its generation is not contingent on an associated 

purchase to replace that power, notwithstanding the possibility 

that the owner or operator of that steam unit may choose to make 

such a purchase to meet an electricity supply obligation. 
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Page 907 of 2153

replacement electricity. The outcome of this power market 

process will reduce both the mass and the rate of emissions 

across sources. 

An owner of a source can also reduce the generation of an 

EGU by substituting generation from a lower-emitting NGCC 

directly. ThisFor an EGU owner without existing NGCC generation, 

this substitution can take the form of a bilateral contract 

purchase. In RTOs and ISOs, this alternative often takes the 

form of a contract for differences, where the replacement source 

could be an NGCC and the contract specifies a delivery location 

and the price of the power. In bilateral markets, the contract 

vehicle could be a Power Purchase Agreement from a replacement 

source, an alternative available both in regions with organized 

wholesale electricity markets or in regions without such 

markets. Unused capacity from existing NGCCs can be a source of 

supply for reducing the level of higher-emitting EGUs.. It is 

also possible that the owner of a steam unit could directly 

invest in an existing EGU, by purchasing the asset or taking a 

partial ownership position, thus acquiring the generation from 

the unit through that means. The acquired generation and its 

associated emissions could be used for compliance by the higheremitting EGU. Under a rate-based standard, the emissions and 

generation associated, in accordance with a purchase or 
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Page 908 of 2153

acquisition could be averaged with the higher-emitting EGU 

emissions and generation to reduce the combined emissions rate 

through the use of emission rate creditsthe plan under which it 

is operating. The amount of generation that could be shifted 

using the approaches described in this paragraph will depend on 

the type and terms of the commercial arrangements, butas well as

the potential need for regulated entities to obtain approvals 

for contracts or for changes in asset positions. The wide range 

of approaches permitted by this rule – reflecting both the 

characteristics of the interconnected operations of EGUs and 

those of CO2 itself as a global-impact pollutant –provides the 

needed flexibility, both within a year and across multiple 

years, to permitfor EGUs to fashion these arrangements to fit 

their circumstances.

Under a mass-based program, the steam generators simply 

need to reduce their generation (or buy allowances, or co-fire 

or repower, or install CCS). They do not need to purchase 

replacement, lower-emitting electricity or the environmental 

attributes of that electricity. They may need to do so to 

fulfill any electricity supply obligations they might be under, 

but they do not have to do so to meet the requirements of this 

rule. Once the steam generators reduce their generation, the 

other entities in the electricity system arrange for the 
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Page 909 of 2153

replacement electricity. But that replacement electricity does 

not lower the emissions from the steam generation. The reduced 

generation by the steam generators lowers the emissions. An EGU 

should also be able to meet its reduction obligations by 

purchasing tradable emission rate credits or mass allowances. 

Purchased emission rate credits would be averaged into the 

existing generation and emissions from the EGU to calculate a 

reduced emissions rate in a rate-based program. Purchased mass 

allowances would be added to any allowances already held to 

enable the EGU to hold a sufficient number of allowances to 

cover emissions in a mass-based program. In each case the 

calculation would need to reflect the type of program and the 

type of credit or allowance being applied (see section VIII for 

more detail on how these programs operate). 

Where permitted under its state plan, an EGU would also be 

able to meet its reduction obligations using emission rate 

credits or allowances. The particular nature of this alternative 

will depend on how a state elects to develop its plan. If a 

state chooses a mass-based approach, the EGU would simply need 

to hold allowances to cover its emissions. To realize an 

emission reduction from building block 2 under this approach, a 

steam generator would only need either to reduce its emissions 

by reducing its generation, which would lead to that generator 
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needing fewer allowances to cover its emissions under the 

program, or to purchase surplus allowances not needed by another 

EGU that had reduced its emissions. In a rate-based state, the 

state may choose to provide for compliance through the 

acquisition of tradable emission rate credits. To realize an 

emission reduction from building block 2 under this approach, a 

steam generator would be able to adjust its effective emission 

rate by purchasing emission rate credits that are produced by 

other sources whose emission rates are lower than the applicable 

rate standard. In this fashion, a steam generator does not need 

to purchase lower-emitting replacement power per se in order to 

demonstrate an emission reduction from this building block; 

instead, the steam generator may purchase any emission rate 

credits that were produced from lower-emitting sources (see 

section VIII for more detail on how state plans can use an 

emission rate credit approach to facilitate a rate-based 

compliance demonstration of this type of emission reduction).836

 

836 Stakeholders have recognized that emission rate credits and 

allowances are an effective tool for EGUs to implement the 

building blocks and achieve their standards of performance 

required under this rule. See “Clean Power Plan Implementation: 

Single-State Compliance Approaches with Interstate Elements,” 

Georgetown Climate Center (May 2015), 

http://www.georgetownclimate.org/sites/www.georgetownclimate.org

/files/GCC_ComplianceApproacheswithInterstateElements_May2015.pd

f. 
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The approaches shown here collectively demonstrate that all 

steam generators, -- regardless of size of, location, form of 

ownership, or type of market in which they operate -- can 

implement building block 2 through some or all of the mechanisms 

described. 

2. MagnitudeAmount and timing of generation shift 

The EPA has determined that for purposes of quantifying the 

CO2 emission reductions achievable through building block 2, a 

reasonable amount of generation shift is the amount of 

generation shift that would result from existing NGCC units, on 

average, increasing their annual utilization rates to 75 percent 

of net summer capacity. However, the building block does not 

reflect achievement of this average capacity factor at the start 

of the interim period, but instead reflects a glide path of 

increases in NGCC utilization over the interim period. Below, we 

discuss the glide path, and in the following section we discuss 

the basis for finding the 75 percent utilization rate, achieved 

over the period of time consistent with the glide path, to be 

reasonable. 

The EPA received significant public comments expressing 

concern regarding the proposal’s incorporation of the full 

building block 2 shift in generation by the first year of the 

interim period. These commenters perceived this approach as 
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requiring states to achieve such a significant portion of the 

required CO2 emission reductions early in the interim period that 

states would lack flexibility in when and how they may achieve 

the required emission reductions. Other commenters expressed 

concern that the full extent of building block 2 would be 

difficult for some states to achieve by the first year of the 

interim period as a result of technical, engineering, and 

infrastructure limitations or other considerations; that such 

timing may crowd out other cost-effective options for emission 

reductions; and that such timing might have negative 

implications for reliability. 

In the proposal, the EPA determined that emission 

reductions are feasible and achievable at fossil fuel-fired 

steam EGUs by shifting from more carbon-intensive EGUs to less 

carbon-intensive EGUs, as part of the BSER. More specifically, 

the EPA proposed that generation shifts from fossil fuel-fired 

steam units (which are primarily coal-fired) to NGCC units, up 

to a utilization of 70 percent on a nameplate capacity basis, 

could be achieved by 2020. In contrast, the EPA proposed that 

reductions in CO2 emissions from fossil fuel-fired units 

associated with other measures, such as increased utilization of 

RE generating capacity and increased demand-side energy 

efficiency, would be achievable on a phased-in basis between 
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2020 and 2029, reflecting the time needed for deployment.837 In 

light of the concerns noted above, in the October 2014 Notice of 

Data Availability the EPA solicited comment on potential 

rationales for phasing in the potential to shift generation 

under building block 2.838

As already noted, in the final rule the EPA has revised the 

interim period to start in 2022, which itself is a meaningful 

response regarding the concerns expressed by commenters about 

the timing of building block 2’s generation shift potential. In 

addition, the EPA has evaluated the feasibility over time of 

building block 2 within the framework of BSER, and is finalizing 

a change to building block 2 that gradually phases in the shift 

from existing fossil steam to existing NGCC over the interim 

period. This phase-in allows for additional time to complete 

potential infrastructure improvements (e.g., natural gas 

pipeline expansion or transmission improvements) that might be 

needed to support more use of existing natural gas-fired 

generation, and provides states with the increased ability to 

coordinate actions taken under building block 2 with actions 

taken under building block 3 (deployment of new renewable 

capacity). 

 

837 79 FR 34866. 838 79 FR 64543. 
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The phase-in schedule applies a limit to the maximum 

building block 2 potential in each year of the interim period 

based on two parameters. The first parameter defines an amount 

of generation shift to existing NGCC capacity that is feasible 

by 2022, and the second parameter defines how quickly that 

amount could grow until the full amount of NGCC generation could 

be achieved as part of the BSER. Both of these parameters are 

determined by examining the extent to which gas-fired generation 

has increased over historical time periods. The first parameter 

is based on the single largest annual increase in power sector 

gas-fired generation since 1990, which occurred between 2011 and 

2012 and is equal to 22 percent.839 We believe that this amount 

is a conservative estimate of the ability of the sector to 

increase utilization of NGCC capacity by 2022, given that this 

increase has already occurred in a single year. The second 

parameter is based on the average annual growth in gas-fired 

generation in the power sector between 1990 and 2012, which is 

approximately 5 percent per year. 

In the performance rate calculation methodology, these two 

parameters constrain the annual rate at which building block 2 

 

839 US EIA Monthly Energy Review, Table 7.2b Electricity Net 

Generation: Electric Power Sector (2015), available at 

http://www.eia.gov/totalenergy/data/browser/xls.cfm?tbl=T07.02B&

freq=m. 
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shifts generation from fossil steam units to NGCC units. The

interim performance rate is an average of annual rates 

calculated over the 2022-2029 period. The two parameters above 

limit the extent to which NGCC generation is able to increase 

and replace fossil steam generation in each year of the interim 

period. In the first year, NGCC generation is limited to a 

maximum of a 22 percent increase from 2012 levels in each 

region. In each subsequent year, regional NGCC generation is 

limited to a maximum of a 5 percent increase from the previous 

year. This phase-in continues in the performance rate-setting 

methodology until the full building block 2 level of shifting 

from fossil steam generation to NGCC generation is reached. 

Under this approach, building block 2 is completely phased into 

the source category calculation of all regions by the end of the 

interim period. 

Table 7. BSER Maximum NGCC Generation Shiftby Region and Year 

(TWh).

NGCC Generation (TWh) 

Regio

n 

Maximu

m 

Potent

ial at 

75% 

2012 

(adjus

ted) 

BSER Maximum 

202

2 

202

3 

202

4 

202

5 

202

6 

202

7 

202

8 

202

9 

203

0 

Limit -- -- 22% 5% 5% 5% 5% 5% 5% 5% 5% 

Easte

rn 

Inter 988 735 896 941 988 988 988 988 988 988 988
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conne

ction 

Weste

rn 

Inter

conne

ction 306 198 242 254 267 280 294 306 306 306 306

Texas 

Inter

conne

ction 204 137 167 176 185 194 203 204 204 204 204

This phase-in, in addition to the flexible nature of the goals, 

ensures that the overall framework of this final rule includes 

sufficient flexibility, particularly with respect to timing of 

and strategies for reducing emissions from the affected units, 

so that states can develop cost-effective strategies and allow 

for infrastructure improvements to occur should they prove 

necessary in some locations. 

3. Basis for magnitude of generation shift 

a. Technical feasibility of NGCC units to generate at 75% of 

their capacity. In order to estimate the potential magnitude of 

the opportunity to reduce power sector CO2 emissions through 

shifting generation among existing EGUs, the EPA first examined 

information on the design capabilities and availability of NGCC 

units. Availability is defined as the number of hours that 

generators are available to generate electricity, and it is 

typically expressed as a percentage of the total number of hours 
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in a year. Since the value of NGCC capacity is related to how 

much electricity the owner of that capacity can generate and 

sell, units are typically designed with very high availability 

ratings. Baseload units have annual average availabilities of 

approximately 91%-92%, and peaking units are generally available 

96% to 98% of peak hours.840 The EPA also examined information on 

the historical availability of NGCC units in practice. This 

examination showed that, although most NGCC units have 

historically been operated in intermediate-duty roles for 

economic reasons, they are technically capable of operating in 

base-loadbaseload roles at much higher annual utilization rates. 

Average annual availability (that is, the percentage of annual 

hours when an EGU is not in a forced or maintenance outage) for 

NGCC units in the U.S. generally exceeds 85 percent, and can 

exceed 90 percent for some groups.841

 

840 Negotiating Availability Guarantees for Gas Turbine Plants, 

available at: http://www.power-eng.com/articles/print/volume105/issue-3/features/negotiating-availability-guarantees-forgas-turbine-plants.html. 

841 See, e.g., North American Electric Reliability Corp., 2008-

2012 Generating Unit Statistical Brochure—All Units Reporting, 

http://www.nerc.com/pa/RAPA/gads/Pages/Reports.aspx; Higher 

Availability of Gas Turbine Combined Cycle, Power Engineering 

(Feb. 1, 2011), http://www.power-eng.com/articles/print/volume115/issue-2/features/higher-availability-of-gas-turbinecombined-cycle.html. 
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We also researched historical data to determine the 

utilization rates that NGCC units have already demonstrated 

their capability to sustain. Over the last several years, the 

utilization patterns of fossil fuel-fired units have shifted 

relative to historical dispatch patterns, with NGCC units 

increasing generation and many coal-fired EGUs reducing 

generation. In fact, in April 2012, for the first time ever the 

total quantity of electricity generated nationwide from natural 

gas was approximately equal to the total quantity of electricity 

generated nationwide from coal.842 These changes in generation 

patterns have been driven largely by changes over time in the 

relative prices of natural gas and coal. Although the relative 

fuel prices vary by location, as do the recent generation 

patterns, this trend holds across broad regions of the U.S. In 

the aggregate, the historical data provide ample evidence 

indicating that, on average, existing NGCC units can achieve and 

sustain utilization rates higher than their historical average 

utilization rates. 

Utilization of EGUs is often considered using the metric of 

a capacity factor, which is the percentage of total production 

potential that an electric generating unit achieves in a given 

 

842 http://www.eia.gov/todayinenergy/detail.cfm?id=6990. 
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time period. A capacity factor of 75 percent thus represents a 

unit producing three-quarters of the electricity it could have 

produced in that time had it utilized its entire capacity. The 

EPA received multiple comments regarding the proposed use of 

nameplate capacity in calculating the potential utilization 

level of existing NGCCs under building block 2. These comments 

stated that net summer capacity is a more meaningful and 

reliable metric than nameplate capacity, because net capacity 

best reflects the electric output available to serve load. The 

EPA agrees with these comments. The quantification of building 

block 2 as well as performance rate and state goal calculations 

in the final rule are all based on net summer generating 

capacity. An annual utilization rate of 75 percent on a net 

summer basis is similar to the proposed rule’s consideration of 

70 percent utilization on a nameplate basis.843 

The experience of relatively heavily-used NGCC units 

provides an additional indication of the degree of increase in 

average NGCC unit utilization that is technically feasible. In 

 

843 For a given amount of net generation, a net summer capacity 

factor appears higher compared to a corresponding nameplate 

capacity factor because net summer capacity reflects a lower 

amount of total generation potential achievable by the unit in 

practice. 
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response to comments regarding the use of nameplate capacity in 

determining NGCC utilization rate, the 

The EPA reexamined the historical NGCC plant utilization 

rate data reported to the EIA, and found that in 2012 roughly 15 

percent of existing NGCC plants operated at annual utilization 

rates of 75 percent or higher on a net summer basis.844,845 In 

effect, these plants were being dispatched to provide baseloadproviding baseload power. In addition to the 15 percent of 

NGCC plants that operated approximately at a 75 percent 

utilization rate on an annual basis, some NGCC plants operated 

at even higher utilization rates for shorter, but still 

sustained, periods of time in response to high cyclical demand. 

For example, on a seasonal basis, a significant number of NGCC 

plants have achieved utilization rates greater than 90 percent 

on a net summer basis; during the summer of 2012 (June through 

August), about 30 percent of NGCC plants operated at utilization 

rates of 75 percent or more across the entire season. During the 

 

844 Net summer capacity is defined as: “The maximum output, 

commonly expressed in megawatts (MW), that generating equipment 

can supply to system load, as demonstrated by a multi-hour test, 

at the time of summer peak demand (period of June 1 through 

September 30.) This output reflects a reduction in capacity due 

to electricity use for station service or auxiliaries.” (EIA, 

http://www.eia.gov/tools/glossary). 

845 An annual utilization rate of 75 percent on a net summer 

basis is similar to the proposed rule’s finding of 70 percent 

utilization on a nameplate basis. 
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spring and fall periods when electricity demand levels are 

typically lower, these plants were sometimes idled or operated 

at much lower capacity factors. Nonetheless, the data clearly 

demonstrate that a substantial number of existing NGCC plants 

have proven the ability to sustain 75 percent utilization rates 

for extended periods of time. We view this as strong evidence 

that increasing the annual average utilization rates of existing 

NGCC units to 75 percent on a net summer basis would be 

technically feasible. 

The EPA believes that an annual average utilization rate of 

75 percent on a net summer basis is a conservative assessment of 

what existing NGCC plants are capable of sustaining for extended 

periods of time. This level is based on the 85th percentile 

plant in 2012. In 2012, the 90th percentile plantroughly 10 

percent of existing NGCC plants operated at approximatelyannual 

utilization rates of 80%, percent or higher on a level which 

net summer basis. While the EPA believes this level is also 

technically feasible on average for the existing NGCC fleet. , 

the EPA is quantifying building block 2 assuming an NGCC 

utilization level of 75% on a net summer basis in order to offer 

sources additional compliance flexibility, given that the extent 

to which they realize a utilization level beyond 75 percent will 
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Page 922 of 2153

reduce their need to rely on other emission reduction measures 

or building blocks. 

For purposes of establishing state goals, historical (2012) 

electricb. Historical generation data are usedshifts to apply 

each building block and develop each state's goal (expressed as 

an adjusted CO2 emission rate in lbs per MWh).NGCC generation. In 

2012, total electric generation from existing NGCC units was 

X966 TWh. 846 After the application of the building block 2 

potential (increasing NGCC up to 75 percent target utilization 

rate in each regionup to a 75 percent capacity factor on a net 

summer basis, and including generation from NGCC units that were 

under construction in 2012,), the total generation from these 

existing sources is assumed to be X1,498 TWh.847 

Although producing X TWh of generation from existing NGCC 

units is not actually required, because states may choose other 

abatement measures to reach the state goals, the EPA 

neverthelessThe EPA believes that producing this quantity of 

generation from this set of NGCC units is feasible. As a 

reference pointTo put this level of generation into context, 

NGCC generation increased by approximately 430439 TWh (an 8083

 

846 Appendix 1, CO2 Emission Performance Rate and Goal Computation 

Technical Support Document for CPP Final Rule. 

847 Appendix 1, CO2 Emission Performance Rate and Goal Computation 

Technical Support Document for CPP Final Rule. 
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percent increase) between 2005 and 2012. The EPA calculates that 

assumed NGCC generation in 2022 through the quantification of 

building block 2 potential is approximately X44 percent higher 

than 2014 levels. This reflects a smaller ramp-upgrowth rate in 

potential NGCC generation between 2015 and 2022 than has been 

observed in practice from 2005 to 2012., a time period of the 

same duration. 

c. Reliability. We also expect that an increase in NGCC 

generation of this amount would not impair power system 

reliability. IncreasesSources can achieve increases in NGCC 

usage atutilization of existing EGUsNGCCs that displacesdisplace

generation from steam sources will not impactwithout impacting

reliability, since the available fossil generation will not 

change, leaving the system with because this shift in average 

annual utilization across existing EGUs does not inhibit the 

power sector’s ability to maintain adequate dispatchable 

resources to continue to meet reserve marginmargins and maintain 

reliability. In addition,Furthermore, sources are not required 

to achieve the exact or even the full extent of the final rule 

makes specific provision to ensure that building block 2 

generation shift itself, which means that sources will have 

ample flexibility to maintain reliability can be planned and 
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maintained under this final rule-relevant operations while 

achieving emission reductions through a variety of measures.848

d. Natural gas infrastructure. The EPA also examined the 

technical capability of the natural gas supply and delivery 

system to provide increased quantities of natural gas and the 

capability of the electricity transmission system to accommodate 

shifting generation patterns. For several reasons, we conclude 

that these systems would be capable of supporting the degree of 

increased NGCC utilization needed for states to achieve the 

goals established by this rulepotential in building block 2. 

First, the natural gas pipeline system is already supporting 

national average NGCC utilization rates of 60 percent or higher 

during peak hours, which are the hours when constraints on 

pipelines or electricity transmission networks are most likely 

to arise. NGCC unit utilization rates during the range of peak 

daytime hours from 10 a.m. to 9 p.m. are typically 15 to 20 

percentage points above their average utilization rates (which 

have recently been in the range of 40 to 50 percent).849 Fleet-

 

848 See also Reliabilitysection VIII for further discussion in 

the state plans sectionof electric reliability planning. 849 EIA, Average utilization of the nation's natural gas 

combined-cycle power plant fleet is rising, Today in Energy, 

July 9,2011, 

http://www.eia.gov/todayinenergy/detail.cfm?id=1730#; EIA, Today 

in Energy, Jan. 15, 2014, 
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wide combined-cycle average monthly utilization rates have 

reached 65 percent,850 showing that the pipeline system can 

currently support these rates for an extended period. If the 

current pipeline and transmission systems allow these 

utilization rates to be achieved in peak hours and for extended 

periods, it is reasonable to expect that similar utilization 

rates should also be possible in other hours when constraints 

are typically less severe, and be reliably sustained for other 

months of the year. Furthermore, this final rule will not 

havethe NGCC utilization increase assumed in building block 2 

could occur without a significant impact on peak demand for 

natural gas, including winter demand (when the power sector’s 

demand for natural gas for electricity will competecompetes with 

other sectorsectors’ demands, for natural gas), since the state 

goals areincreasing annual requirements and increases in demand 

for natural gas will be duringutilization of NGCCs could focus 

on non-peak periods when NGCC capacity factors are currently 

low. 

The second consideration supporting our view that natural 

gas and electricity system infrastructure would be capable of 

 

http://www.eia.gov/todayinenergy/detail.cfm?id=14611 (for recent 

data). 

850 EIA, Electric Power Monthly, February, 2014. Table 6.7.A. 
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supporting increased NGCC unit utilization rates is the 

flexibility of the emission guidelines. The state goals do not 

require any particular NGCC unit to achieve any particular 

utilization rate in any specific hour or year. Thus, even if 

isolated natural gas or electricity system constraints were to 

limit NGCC unit utilization rates in certain locations in 

certain hours, this would not prevent an increase in NGCC 

generation overall across a state or broader region and across 

all hours. The third consideration supporting a conclusion 

regarding the adequacy of theThe second consideration supporting 

a conclusion regarding the adequacy of the gas supply

infrastructure is that pipeline and transmission planners have 

repeatedly demonstrated the ability to methodically relieve 

bottlenecks and expand capacity.851 Natural gas pipeline capacity 

has regularly been added in response to increased gas demand and 

supply, such as the addition of large amounts of new NGCC 

capacity from 2001 to 2003, or the delivery to market of 

unconventional gas supplies since 2008. These pipeline capacity 

increases have added significant deliverability to the natural 

 

851 See, e.g., EIA, Natural Gas Pipeline Additions in 2011, Today 

in Energy; INGAA Foundation, Pipeline and Storage Infrastructure 

Requirements for a 30 Tcf Market (2004 update); INGAA 

Foundation, North American Midstream Infrastructure Through 

2035—A Secure Energy Future Report (2011). 
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gas pipeline network to meet the potential demands from 

increased use of existing NGCC units. Over a longer time period, 

much more significant pipeline expansion is possible. In 

previous studies, when the pipeline system was expected to face 

very large demands for natural gas use by electric utilities

about 10 years ago,, the pipeline industry projected that

increases of up to 30 percent in total deliverability out of the 

pipeline system were judged towould be possible by the pipeline 

industry.852 There have been notable pipeline capacity expansions 

over the past five years, and substantial additional pipeline 

expansions are currently under construction.853 Similarly, the 

electric transmission system is undergoing substantial 

expansion.854 Further, as discussed below in Sections X and X of 

 

852 Pipeline and Storage Infrastructure Requirements for a 30 Tcf 

Market, INGAA Foundation, 1999 (Updated July, 2004); U.S. gas 

groups confident of 30-tcf market, Oil and Gas Journal, 1999. 

853 For example, between 2010 and April 2014, 118 pipeline 

projects with 44,107 MMcf/day of capacity (4,699 miles of pipe) 

were placed in service, and between April 2014 and 2016 an 

additional 47 pipeline projects with 20,505 MMcf/day of capacity 

(1,567 miles of pipe) are scheduled for completion. Energy 

Information Administration, 

http://www.eia.gov/naturalgas/data.cfm. 

854 According to the Edison Electric Institute, member companies 

are planning over 170 projects through 2024, with costs totaling 

approximately $60.6 billion (this is only a portion of the total 

transmission investment anticipated). Approximately 75 percent 

of the reported projects (over 13,000 line miles) are high 

voltage (345 kV and higher). 

http://www.eei.org/issuesandpolicy/transmission/Documents/Trans_

Project_lowres_bookmarked.pdf. 
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this preamble (on state flexibilities and state plans, 

respectively), we believethe phasing in of building block 2’s 

potential in the determination of the BSER; the flexible nature 

of the goals providesmulti-year compliance with the ultimate 

emission reduction requirements of the rule; and the seven years 

between finalization of this rule and the first year of 

compliance provide time for infrastructure improvements to occur 

should they prove necessary in some locations. Finally, as 

discussed below in section X, the EPA is finalizing a start date 

two years later than at proposal, or almost seven years from the 

date of this final rule, and then phasing in building block 2 

through the interim period. Combining these factors of currently 

observed average monthly NGCC utilization rates of up to 65 

percent, the flexibility of the emission guidelines, the rates 

of historical growth, and the availability of time to address 

any existing pipeline infrastructure limitations, it is 

reasonable to conclude that the natural gas pipeline system can 

reliably deliver sufficient natural gas supplies, and the 

electric transmission system can reliably accommodate changed 

generation patterns, to allow NGCC utilization to increase up to 

an average annual utilization ratecapacity factor of 75 percent 

on a net summer basis. 
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e. Natural gas production. We recognize that an increase in NGCC 

utilization rates at existing units corresponds with an 

associated increase in natural gas production, consistent with 

the current trends in the natural gas industry. The EPA expects 

the growth in NGCC generation assumed in goal-settingfor 

building block 2 to be feasible and consistent with the 

production potential of domestic natural gas supplies. Increases 

in the natural gas resource base have led to fundamental changes 

in the outlook for natural gas. There is general agreement that 

recoverable natural gas resources will be substantially higher 

for the foreseeable future than previously anticipated, exerting 

downward pressure on natural gas prices. According to EIA, 

proven natural gas reserves have doubled between 2000 and 2012. 

Domestic dry gas production has increased by 3225 percent over 

that same timeframe (from 19.2 TCF in 2000 to 25.324.0 TCF in 

2012). EIA'sEIA’s Annual Energy Outlook Reference Case for 2015 

projects that production will further increase to 29.5 TCF by 

2022 and 33 TCF by 2030, as a result of increased supplies and 

favorable market conditions. In the AEO 2015 high oil and gas 

resource case, production is projected to increase to 42.7 TCF 

in 2030. For comparison, building block 2 assumes NGCC 

generation growth of X235 TWh (calculated in goal setting)from 

2012 to reach the level assumed for 2022, and that NGCC 
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generation growth would result in increased gas consumption of 

roughly Xless than 2 TCF for the electricity sector, which is 

less than EIA’s projected increase in natural gas production of 

5.5 TCF from 2012 to 2022. 

The EPA has also assessed the ability of the electricity 

and natural gas industries to achieve the potential quantified 

for building block 2 using the Integrated Planning Model (IPM). 

IPM is a multi-regional, dynamic, deterministic linear 

programming model of the U.S. electric power sector that the EPA 

has used for over two decades to evaluate the economic and 

emission impacts of prospective environmental policies. To 

inform its projections of least-cost capacity expansion and 

electricity dispatch, IPM incorporates representations of 

constraints related to fuel supply, bulk power transmission 

capacity, and unit availability. The model includes a detailed 

representation of the natural gas pipeline network and the 

capability to project economic expansion of that network based 

on pipeline load factors. At the EGU level, IPM includes 

detailed representations of key operational limitations such as 

turn-down constraints, which are designed to account for the 

cycling capabilities of EGUs to ensure that the model properly 

reflects the distinct operating characteristics of peaking, 

cycling, and base load units. 
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As described in more detail below, the EPA used IPM to 

assess the costs of increasing generation from existing NGCC 

capacity. IPM was able to meet average NGCC utilization rates of 

75 percent on a net summer basis, while observing the market, 

technical, and regulatory constraints represented in the model. 

This modeling also demonstrates the ability of domestic natural 

gas supplies to increase their production levels, and deliver 

that supply through the pipeline network, to support the level 

of NGCC generation quantified in building block 2. Such a result 

is consistent with the EPA's determination that increasing the 

average utilization rate of existing NGCC units to 75 percent 

would be technically feasible. 

3. Timing of Generation Shift 

Some stakeholders have expressed concern that the 

performance rate- and goal-setting methodology — in particular, 

calculating the interim performance rates and goals on the basis 

of achieving the shift in generation assumed under building 

block 2 by the first year of the interim period — requires 

states to achieve such a significant portion of the required CO2

emission reductions early in the interim period that it defeats 

the intended purpose of providing states flexibility in how they 

may achieve the required emission reductions. In particular, 

these stakeholders have stated that significant shifts of 
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generation away from coal-fired generators to existing NGCC 

units (as calculated under building block 2) will be difficult 

for some states to achieve by the first year of the interim 

period as a result of technical, engineering, and infrastructure 

limitations or other considerations, may limit cost-effective 

options for emission reductions, and might have negative 

implications for reliability and/or recent investments in fossil 

steam technology. According to these stakeholders, these 

concerns existed even though the proposed rule did not require 

all emission reductions to be achieved in 2020, but rather 

provided that the interim goal could be met on an average basis 

for the 2020-2029 period. 

f. Transmission planning and construction. Achieving the 

generation shift quantified in building block 2 would not impose 

significant additional burden on the transmission planning 

process and does not necessitate major construction projects. 

Two considerations are important for this conclusion: 

First, building block 2 applies only to increases in 

generation at existing NGCC facilities and does not contemplate 

any connection of new capacity to the bulk power grid. Second, 

regional grids are already supporting operation of the NGCC 

units for sustained periods of time at the capacity factors 
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quantified in building block 2.855 Although some upgrades to the 

grid (including potential, but modest, expansions of 

transmission capacity) may be necessary to support the extension 

of the time that these capacity factors are sustained over the 

course of the annual time period on which building block 2 is 

based, such upgrades are part of the normal planning process 

around the increased use of existing facilities. In fact, the 

electric transmission system is currently undergoing substantial 

expansion.856 Consequently, EPA does not believe that achieving 

the generation shift potential in building block 2 would 

necessitate any significant additional requirements for 

transmission planning and construction beyond those already 

being addressed at routine intervals by the power sector. 

Furthermore, the phasing in of building block 2’s potential in 

the determination of the BSER; the flexible nature of multi-year 

compliance with the ultimate emission reduction requirements of 

 

855 See Greenhouse Gas Mitigation Measures TSD for a discussion 

of regional NGCC capacity factors. 

856 According to the Edison Electric Institute, member companies 

are planning over 170 projects through 2024, with costs totaling 

approximately $60.6 billion (this is only a portion of the total 

transmission investment anticipated). Approximately 75 percent 

of the reported projects (over 13,000 line miles) are high 

voltage (345 kV and higher). Construction of transmission lines 

of 345KV and above are generally major projects that are 

particularly effective at carrying power of large distances. 

http://www.eei.org/issuesandpolicy/transmission/Documents/Trans_

Project_lowres_bookmarked.pdf. 
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the rule; and the seven years between finalization of this rule 

and the first year of compliance all provide time for 

infrastructure improvements to occur should they prove necessary 

in some locations. 

g. Regulatory flexibility. The final consideration supporting 

our view that natural gas and electricity system infrastructure 

would be capable of supporting increased NGCC unit utilization 

rates at a maximum of 75% on a net summer basis is the 

substantial unit-level compliance flexibility of the emission 

guidelines. The final rule does not require any particular NGCC 

unit to achieve any particular utilization rate in any specific 

hour or year. Thus, even if isolated natural gas or electricity 

system constraints were to limit NGCC unit utilization rates in 

certain locations in certain hours, this would not prevent an 

increase in NGCC generation overall across a state or broader 

region and across all hours on the order assumed in the 

generation shift potential quantified for building block 2. 

In the proposal, the EPA determined that emission 

reductions are feasible and achievable at fossil fuel-fired 

steam EGUs by shifting from more carbon-intensive EGUs to less 

carbon-intensive EGUs, as part of the BSER. More specifically, 

the EPA proposed that, generation shifts from fossil fuel-fired 

steam units (which are primarily coal-fired) to NGCC units, up 
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to a utilization of 70 percent on a nameplate capacity basis, 

could be achieved by 2020, as part of building block 2 and for 

purposes of establishing state goals. In contrast, the EPA 

proposed that reductions in CO2 emissions from fossil fuel-fired 

units associated with other measures, such as increased 

utilization of RE generating capacity and increased demand-side 

energy efficiency, would be achievable on a phased-in basis 

between 2020 and 2029, reflecting the necessary time needed for 

deployment (79 FR 34866). 

We note that the design of the guidelines makes clear that 

states are not required to reach their targets using precisely 

the levels of each building block that the EPA used to determine 

each state's goal. Nevertheless, some stakeholders have 

expressed concern that it may not be feasible to ensure 

significantly higher levels of utilization for existing NGCC 

units that might be required in order to meet the interim state 

goals because of the time required to improve natural gas 

pipeline infrastructure in some states. Stakeholders have also 

stated that, while some coal-fired units have recently been 

constructed and many have received significant capital 

investment (e.g., in the form of pollution control retrofits), 

some states' interim goals could not be achieved unless these 

units stop operating by 2020. According to stakeholders, this 
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concern particularly applies for states that have both 

significant amounts of steam generation and significant amounts 

of existing NGCC capacity that is not currently being operated 

at high levels of utilization. In light of these concerns, the 

EPA solicited comment in the proposal on potential rationales 

for phasing in the potential to shift generation under building 

block 2 in the subsequent NODA (79 FR 64543). 

As described in section X of this preamble, the EPA has 

revised the interim compliance period to start in 2022, which in 

and of itself provides a meaningful response regarding the 

concerns expressed by commenters about the timing of building 

block 2’s generation shift potential. More specifically in 

response to the comments about building block 2 received from 

stakeholders, the EPA has evaluated the timing of implementation 

of building block 2 within the framework of BSER, and is 

finalizing a change to building block 2 that phases in the shift 

from existing fossil steam to existing NGCC over the interim 

period. This phase-in allows for additional time to complete 

potential infrastructure improvements (e.g., natural gas 

pipeline expansion or transmission improvements) that might be 

needed to support more use of existing natural gas-fired 

generation, and provides states with increased ability 

coordinate actions taken under building block 2 with actions 
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taken under building block 3 (operation of new renewable 

capacity). Additionally, this phase-in increases the flexibility 

provided to states to address capital investment concerns 

regarding individual sources when scheduling compliance actions 

over the course of the interim and final periods. 

The phase-in schedule is based on two parameters. The first 

parameter defines an amount of generation shift to existing NGCC 

capacity that is feasible by 2022, and the second parameter 

defines how quickly that amount could grow until the full amount 

of NGCC generation could be achieved as part of the BSER. Both 

of these parameters are determined by examining the extent to 

which gas-fired generation increased over historical time 

periods. The first parameter is based on the single largest 

annual increase in power sector gas-fired generation since 1990, 

which occurred between 2011 and 2012 and is equal to 22 

percent857. We believe this is a conservative estimate of the 

ability of the sector to increase utilization of NGCC capacity 

between now and 2022, given that this increase already occurred 

in a single year. The second parameter is based on the average 

 

857 US EIA Monthly Energy Review, Table 7.2b Electricity Net 

Generation: Electric Power Sector (2015). Available at: 

http://www.eia.gov/totalenergy/data/browser/xls.cfm?tbl=T07.02B&

freq=m. 
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annual growth in gas-fired generation in the power sector 

between 1990 and 2012, or approximately 5 percent per year. 

In the performance rate calculation methodology, these two 

parameters constrain the annual rate at which building block 2 

shifts generation from fossil steam units to NGCC units. As 

discussed in Section X, the interim performance rate is an 

average of annual rates calculated over the 2022-2029 period. 

The two parameters above limit the extent to which NGCC 

generation is able to increase and replace fossil steam 

generation in each year of the interim period. In the first 

year, NGCC generation is limited to a maximum of a 22 percent 

increase from 2012 levels in each region. In each subsequent 

year, regional NGCC generation is limited to a maximum of a 5 

percent increase from the previous year. This phase-in continues 

in the performance rate-setting methodology until the BSER level 

of shifting from fossil steam generation to NGCC generation is 

completed. Under this approach, building block 2 is completely 

phased into the performance rates of all regions by the end of 

the interim period. 

This phase-in, in addition to the flexible nature of the 

goals (discussed below in Sections X and X of this preamble), 

ensures that the overall framework of this final rule includes 

sufficient flexibility, particularly with respect to timing of 
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and strategies for reducing emissions from the affected units, 

so that states can develop cost-effective strategies, and 

states, utilities, grid operators and others can readily respond 

to unexpected changes or demands on the energy system, such as 

severe weather, and allow for infrastructure improvements to 

occur should they prove necessary in some locations. 

4. Cost 

Having established the technical feasibility and 

quantification of the potential to replace incremental 

generation at higher-emitting EGUs with generation at NGCC 

facilities as a CO2 emissions reduction strategy, we next turn to 

the question of cost. The cost of the power sector CO2 emission 

reductions that can be achieved through shifting generation 

among existing fossil fuel-fired EGUs depends on the relative 

variable costs of electricity production at EGUs with different 

degrees of carbon intensity. These variable costs are driven by 

the EGUs' respective fuel costs and by the efficiencies with 

which they can convert fuel to electricity (i.e., their heat 

rates). Historically, natural gas has had a higher cost per unit 

of energy content (e.g., MMBtu) than coal in most locations, but 

for NGCC units this disadvantage in fuel cost per MMBtu relative 

to coal-fired EGUs is typically offset in significant part, and 

sometimes completely, by a technological heat rate advantage. 
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To consider the cost implications of building block 2, the 

EPA expanded upon the proposal’s extensive analysis of the 

magnitude and cost of CO2 emission reductions through generation 

shifting within defined areas (consistent with the application 

of building blocks for performance rate- and state goalsetting), without consideration of the availability of other 

emission reduction measures reflected in the other building 

blocksultimately available to units for compliance. 

To evaluate how EGU owners and grid operators could respond 

to a state plan's possible requirements, signals, or incentives 

to shift generation from more carbon-intensive to less carbonintensive EGUs, the EPA analyzed a series of scenarios in which 

the fleet of NGCC units within each of the regions considered 

for quantifying BSER (i.e., the three interconnections) was 

directed to achieve a specified average annual utilization rate 

across that region on a net basis. while maintaining a fixed 

level of aggregate generation in that region across all existing 

fossil fuel-fired sources. The EPA conducted such scenarios to 

address average utilization targetsrates of 70 percent, 75 

percent and 80 percent on a net basis, allowing for shifting of 

fossil generation between existing units within the regions 

described above. This scenario identifies a generation pattern 

that would meet electricity demand at the lowest total cost, 
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subject to all other specified operating and bulk power transfer 

constraints for the scenario, including the specified average 

NGCC unit utilization rate. 

The costs of the various scenarios were evaluated by 

comparing the total costs and emissions from each scenario to 

the costs and emissions from a business-as-usualbase case

scenario. For the scenario reflecting a 75 percent NGCC 

utilization rate on a net basis with regional fossil generation 

shifting, comparison to the business-as-usualbase case indicates 

that the average cost of the CO2 reductions achieved over the 

2022-2030 period was $4024 per metricshort ton of CO2, comparable 

to the average cost estimated for this building block at 

proposal. We view these estimated costs as reasonable and 

therefore as supporting the use of a 75 percent net utilization 

rate target for purposes of quantifying the emission reductions 

achievable at a reasonable cost through the application of 

building block 2 in the BSER. 

We also conclude from these analyses that potential impacts 

to fuel prices and electricity prices from achieving the extent 

of fossil generation shifting estimatedquantified for this 

building block are reasonably within the bounds of power sector 

experience. For example, in the 75 percent NGCC unit utilization 

rate scenario where generation shifting is limited to regional 
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boundaries, the delivered natural gas price was projected to 

increase by an average of X7 percent over the 2022-2030 period, 

which is well within the range of historical natural gas price 

variability.858 Projected wholesale electricity price increases 

over the same period were Xless than 4 percent, which similarly 

is well within the range of historical electric price 

variability. These projected impacts on prices were captured in 

the emission reduction costs of these scenarios already 

described above, which are reasonable and support use of a 75 

percent NGCC utilization rate target for purposes of quantifying 

the emission reductions achievable through application of the 

BSER. 

However, we also note that the costs (and their 

incorporated price impacts) just described are higher than we 

would expect to actually occur in real-world compliance with 

state goals. One reasonthe final rule’s compliance requirements

for the following reasons. First, this is that analysis does not 

capture the building block 2 phase-in reduces the, which assumes 

an average utilization rate over the interim period toof less 

than 75 percent in all three interconnections. Additionally, the 

 

858 According to EIA data, year-to-year changes in natural gas 

prices at Henry Hub averaged 29.9 percent over the period from 

2000 to 2013. http://www.eia.gov/dnav/ng/hist/rngwhhdA.htm. 
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75 percent utilization rate inSecond, the scenario 

exaggeratesanalysis overstates the stringency with extent to 

which building block 2 is actuallyultimately reflected in each 

of the state goals:source category performance rates. While the 

goal performance rate computation procedure usesassumes a 

maximum NGCC utilization rate of 75 percent (before the phasein) as a target NGCC utilization rate on a national averagenet 

summer basis, this target is only achieved in the the Eastern 

Interconnection. Performance ratesInterconnection’s realization 

of this level of NGCC utilization yields higher source category 

performance rates for steam than what would have been calculated 

for units in the Western Interconnection and Texas 

Interconnections are not based on the full 75 

percentInterconnection if they realized that maximum NGCC 

utilization rate in those regions. Also, at least some states 

mayconjunction with the other building blocks. In other words, 

there is substantial building block 2 potential in the Western 

Interconnection and Texas Interconnection that is not actually 

captured in the source category performance rates that are 

ultimately assigned to steam through this rate- and goal-setting 

approach (where the performance rates are ultimately determined 

by the BSER region with the highest rate outcome in the 

calculation). Therefore, the building block 2 analysis 
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Page 944 of 2153

overstates the cost of this component of BSER to the extent that 

it assumes achievement of this generation shift potential that 

is not reflected in the source category performance rates 

ultimately determined. Third, as a practical matter, sources 

will be able to achieve additional emission reductions through 

other measures that, if may prove to be less costly than 

generation shifting, and could substitute for the reductions and 

costs considered here. These building block 2 analyses were 

focused on evaluating the potential impacts of fossil generation 

shifting in isolation, and as a result, they do not consider 

states’ and sources’ flexibility to choose among alternative CO2

reduction strategies that could offer lower-cost reductions, 

instead of relying on fossil generation shifting to the extent 

analyzed here. 

Based on the analyses summarized above, the EPA concludes 

that an average annual utilization rate for each region’s NGCC 

units of up to 75 percent is a technically feasible, costeffective, and adequately demonstrated building block for BSER. 

For further information on the analysis discussed in this 

section, see Chapter X3 of the GHG Mitigation Measures TSD for 

the CPP Final Rule. 

5. Major Commentscomments and Responsesresponses
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The EPA received numerous comments regarding building block 

2. Many of these comments provided helpful information and 

insights, and have resulted in improvements to the proposed 

rule. This section summarizes some of these comments, and the 

remainder of the comments are responded to in the Response to 

Comment document, available in the docket. 

The EPA received multiple comments regarding the proposed 

use of nameplate capacity in calculating the generation 

potential under building block 2. These comments stated that net 

summer capacity is a more meaningful and reliable metric than 

nameplate capacity, because net capacity best reflects the 

electric output available to serve load. The EPA agrees with 

these comments. In response, the EPA reexamined historical data 

on a net summer basis and found that increasing the annual 

average utilization rates of existing NGCC units to 75 percent 

on a net summer basis would be technically feasible. Consistent 

with this analysis, performance rate and state goal calculations 

in the final rule are also based on net summer generating 

capacity. 

The EPA alsoThe EPA received comment regarding the 

potential for an increase in upstream methane emissions from 

increased utilization of natural gas. Our analysis found that 

the net upstream methane emissions from natural gas systems and 
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coal mines and CO2 emissions from flaring of methane will likely 

decrease under the Clean Power Plan. Furthermore, the changes in 

upstream methane emissions are small relative to the changes in 

direct emissions from power plants. The technical details 

supporting this analysis can be found in the Regulatory Impact 

AssessmentAnalysis. 

Commenters also expressexpressed concern that neither a 

utility nor any state agency controls dispatch in most states. 

The EPA believes these comments fail to adequately appreciate 

that the utilities do control the dispatch of units that they 

own and/or operate, either by being the actual dispatch agent in 

many cases where there is no RTO or ISO that schedules the 

dispatch, or by the choice of units and bids they offer into an 

organized electricity market operated by an RTO or ISO. These 

entities currently control the dispatch of their units while 

respecting all existing all requirements from environmental 

rules. This final rule does not change these current 

circumstances, and makes clear that it is the EGU that is 

responsible for meeting the requirements in the state plan; the 

state is responsible for the development of that plan, but the 

state does not need to control the dispatch. 

Commenters have further argued that the proposed rule will 

have the unintended consequence of requiring environmental 
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Page 947 of 2153

dispatch. The EPA does not believe the proposed rule has any 

such consequence, because nothing in the rule requires dispatch 

entities to depart from current economic dispatch principles. 

This final rules makes that point even clearer by emphasizing 

the role of market based approaches and the use of tradable 

emission rate credits and mass allowances that enable the 

incorporation of costs as part of the standard economic 

dispatch. 

Other comments object to the use of a single capacity 

factor goalfor all existing NGCCs to quantify building block 2 

potential on the grounds that not all units canmay be able to

achieve this goal of the highest performing unitsutilization 

level, and that some units may be designed for cycling and so 

may need upgrades to sustain such utilization. The EPA disagrees 

with these comments. The 75 percent capacity factor establishes 

a regional potential for generation from existing NGCC capacity, 

and an individual unit requirement. The EPA has set this target 

to reflect the fact that a portion of NGCC units already run 

above that capacity factor and are generally designed to have 

availabilities above that level.859 Moreover, by encouraging 

higher capacity factors, the final rule should actually result 

 

859 See Chapter X of GHG Abatement TSD. 
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in less cycling rather than moreit does not establish any 

individual unit requirements. 

Another concern expressed by commenters on the proposed 

rule was the disparity in state goals among different states. 

The EPA recognizes these comments and has designed the final 

rule to greatly reduce such disparity, by setting a single 

performance rate for each technology and using those performance 

rates as the basis for calculating state goals. As a result, the 

EPA believes these adjustments to the rule address these 

comments. 

Some comments argue that generation limits in permits for 

some existing NGCC units will limit the amount by which these 

units can increase their generation and thereby limit the 

feasibility of building block 2. The EPA disagrees with these 

comments. Although permit limits can constrain the ability of 

individual units to operate above certain levels, building block 

2 was developed conservatively, with units operating on average 

at a level below the maximum levels at which some units have 

demonstrated the capability to operate. No individual unit is 

required to achieve the average generation levels used to 

quantify building block 2. Further, permit limits at individual 

units can be considered when state plans are developed. There 

are many flexibilities in the final rule, including the 
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opportunity to establish standards of performance that 

incorporate emissions trading, that allow the development of 

plans that will not be constrained by existing permit limits at 

individual units. 

The EPA also received comments asserting that increasing 

generation from new renewables would require increased use of 

natural gas capacity for back-up and ramping, and therefore it 

is not possible for NGCC units to run at BSER utilization rates 

and also be available to support the additional variable 

renewable generation resulting from building block 3. The EPA 

disagrees with this comment. The 75% net summer utilization 

rates defined by building block 2 is a conservative assessment 

and applied on an annual average basis. It is therefore possible 

for these existing units to both operate at higher annual 

utilization rates, and also to operate at higher rates during 

limited periods and still maintain a 75% net summer average 

annual utilization rate. While variable renewable generation 

does require additional load following and ramping resources and 

unit cycling, these requirements are generally a small part of 

the overall ramping costs of the system (see NREL, Relevant 

Studies for NERC’s Analysis of EPA’s Clean Power Plan 111(d) 

Compliance). Additionally, while existing NGCC units are an 

efficient source of ramping to support variable renewables, 
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other units running in an intermediate mode can also provide 

load following and ramping. 

E. Building Block 3 — New Low- and Zero-carbonemitting Renewable

Generating Capacity 

 The third element of the foundation for the EPA’s BSER 

determination for reducing CO2 emissions at affected fossil fuelfired EGUs entails an analysis of the extent to which generation 

at the affected EGUs can be replaced by using an expanded amount 

of low- and zero-carbon electricity generating capacity, such as 

emitting renewable electricity (RE),) generating capacity to 

produce replacement generation. 

In this section we address: first the history of and then

trends in RE development, as well as the importance of expanding 

the use of RE,. Next we discuss the adequate demonstration of 

thisability of affected EGUs to access generation from new RE 

generating capacity, followed by a discussion of renewable 

energy certificate (REC) markets. We then describe the 

quantification of the amount of generation from new RE 

generating capacity achievable through building block as a 

component of the BSER, 3, including key comments, changes made 

from the proposal, key comments, the method by which RE target 

generation levels are quantified, and the magnitude and timing 

of increases in RE generation associated with this building 
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block, and the reasonableness of . Next, we discuss the 

feasibility of implementing the identified incremental amounts 

of RE generation. Finally, we address the costs associated with 

those increases in RE generation. 

1. History of RE Development 

RE generating technologies are a well-established part of 

the U.S. power sector. These technologies generate electricity 

from renewable resources, such as wind, solarsun and water. 

While RE has been used to generate electricity for over a 

century, the push to commercialize RE more broadly began in the 

1970s.860 Following a series of energy crises, new federal 

organizations and initiatives were established to coordinate 

energy policy and promote energy self-sufficiency and security, 

including solar energy legislation, the Public Utility 

Regulatory Policies Act of 1978 (PURPA) and the 1980 Energy 

Security Act.861 

 PURPA was a key step in stimulating RE development. By 

requiring utilities to purchase generation from qualifying 

 

860 Nearly all U.S. hydroelectric capacity was built before the 

mid-1970s. U.S. DOE. History of Hydropower. Accessed March 2015. 

Available at: http://energy.gov/eere/water/history-hydropower. 

861 U.S. DOE Office of Management, Timeline of Events: 1971-1980. 

Accessed March 2015. Available at: 

http://energy.gov/management/office-management/operationalmanagement/history/doe-history-timeline/timeline-events-1. 
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facilities (i.e., certain CHP and RE generators) at avoided 

costs, PURPA opened electricity markets to more RE generation 

and gave rise to non-utility generators that were willing to try 

new RE technologies.862

 SinceIn addition, since 1992, federal tax policy has 

provided important financial support via tax credits for the 

production of RE and investments in RE. While the specific 

provisions for these tax credits have expired and been renewed 

(or extended) a number of times, the financial support has 

helped drive recent growth in RE. 

 States have also taken a significant lead in requiring the 

development of RE resources. In particular, a number of states 

have adopted renewable portfolio standards (RPS), which are 

regulatory mandates to increase production of RE. As of 2013, 29 

states and the District of Columbia havehad enforceable RPS or 

similar laws.863 These RPS requirements and federal tax credits 

continue to drive the relatively robust near-term growth of nonhydropower RE. 

2. Trends in RE Development 

 

862 “Restructuring or Deregulation?" Smithsonian Museum of 

American History. Accessed March 2015. Available at: 

http://americanhistory.si.edu/powering/dereg/dereg1.htm. 

863 Energy Information Administration, Annual Energy Outlook 2014 

with Projections to 2040, at LR-5 (2014). 
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Today, RE is tightly integrated with the utility power 

sector in multiple ways: states have set RE targets for 

electrical load serving entities; utilities themselves are 

diversifying their portfolios by contracting with RE generators; 

and new RE generators are being developed to provide more 

electrical power grid support services beyond just energy (e.g., 

modern wind turbines power electronics allow wind turbines to 

provide voltage and reactive power control at all times).864,865

 Use of RE continues to grow rapidly in the U.S. In 2013, 

electricity generated from RE technologies, including 

conventional hydropower, represented 13 percent of total U.S. 

electricity, up from 9 percent in 2005.866 TotalIn 2013, U.S.

non-hydro RE capacity was approximately 16,000 megawatts (MW) in 

1998. In 2013, for the total non-hydro RE capacity was five 

times higher withelectric power industry exceeded 80,000 

 

864 IPCC, Renewable Energy Sources and Climate Change Mitigation, 

2012. Accessed March 2015. Available at: 

http://www.ipcc.ch/pdf/specialreports/srren/SRREN_Full_Report.pdf. 

865 American Wind Energy Association. AWEA Comments on EPA’s 

Proposed Carbon Pollution Emission Guidelines for Existing 

Stationary Sources and Supplemental Proposed Rule. p. 107. 

866 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at LR-5 (2014), P. ES-6 and Energy 

Information Administration, Monthly Energy Review, May 2015, 

Table 7.2b, Available at: 

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf. 
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MWmegawatts, reflecting a fivefold increase in just 15 years.867

In particular, there has been substantial growth in the wind and 

solar photovoltaic (PV) markets in the past decade. Since 2009, 

U.S. wind energygeneration has tripled and solar 

capacitygeneration has grown twenty-foldtwentyfold.868 

 The global market for RE is projected to grow to $460 

billion per year by 2030.869 RE growth is further spurred by the 

significant amount of existing natural resources that can 

support RE production in the United States.870 In the Energy 

Information Administration’s Annual Energy Outlook 2015, RE 

generation grows substantially from 2013 to 2040 in the 

reference case and all alternative cases.871 In the reference 

case, RE generation increases by more than 70 percent from 2013 

 

867 Energy Non-hydro RE capacity for the total electric power 

industry was more than 16,000 megawatts in 1998. Energy

Information Administration, 1990-2013 Existing Nameplate and Net 

Summer Capacity by Energy Source Producer Type and State (EIA860), Available at: http://www.eia.gov/electricity/data/state/. 

868 Energy Information Administration, Monthly Energy Review, May 

2015, Table 7.2b. Available at: 

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf 

869 “Global Renewable Energy Market Outlook.” Bloomberg New 

Energy Finance, November 16, 2011, Available at: 

http://bnef.com/WhitePapers/download/53. 

870 Lopez et al., NREL, ‘‘U.S. Renewable Energy 

Technical Potentials: A GIS-Based Analysis,’’ (July 2012). 

871 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at LR-5 (2014), P. 25. 
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to 2040 and accounts for over one-third of new generation 

capacity.872

 The recent and projected growth of RE is in part a 

reflection of its increasing economic competitiveness. Numerous 

studies have tracked capital cost reductions and performance 

improvements for RE, particularly for solar and wind. For 

instance, Lazard’s analysis of wind and utility-scale solar PV 

levelized costs of energy (LCOE), on an unsubsidized basis, over 

the last five years found the average percentage decrease of 

high and low of LCOE ranges were 58 percent and 78 percent, 

respectively.873 Analyses of wind’s competitiveness found falling 

wind turbine LCOE while the wind industry developed projects at 

lower wind speed sites using new turbine designs (e.g., 

increased turbine hub heights and rotor diameters). Performance 

improvements have come from novel deployments of new turbines 

designed for lower quality wind sites that are deployed at 

higher quality wind sites, which have resulted in capacity 

 

872 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at LR-5 (2014), P. ES-6-7. 

873 Lazard, Levelized Cost of Energy Analysis-Version 8.0, 

September 2014, p. 9, Available at: 

http://www.lazard.com/media/1777/levelized_cost_of_energy_-_version_80.pdf. 
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factor increases for these locations.874,875 For utility-scale 

solar, cost and performance have also improved significantly. 

Analysis has shown that the installed price of solar 

photovoltaics (PV) systems, prior to any incentives, has 

declined substantially since 1998. Capacity-weighted average 

prices of solar PV in utility-scale deployments were 40 percent 

lower in 2013 than five years earlier.876877 Initially, price 

declines were partially driven by oversupply and manufacturers’ 

thin margins, but, in 2014, prices have remained low due to 

reductions in manufacturing costs.878 The capacity factors of new 

utility-scale installations have increased as systems are 

optimized to maximize energy production. For example, a growing 

number of utility-scale PV systems are increasing the direct 

current capacity of the solar array relative to the alternating 

 

874 “2013 Wind Technologies Market Report,” LBNL, August 2014. 

Available at: http://emp.lbl.gov/publications/2013-windtechnologies-market-report. 

875 “2013 Cost of Wind Energy Review,” NREL, Feb 2015. Available 

at: http://www.nrel.gov/docs/fy15osti/63267.pdf. 

876 “Tracking the Sun VII” LBNL, Sept 2014. Available at: 

http://emp.lbl.gov/publications/tracking-sun-vii-historical-summary-installed-price-photovoltaics-united-states1998-20. 877 “Photovoltaic System Pricing Trends,” NREL, 22 Sept 2014. 

Available at: http://www.nrel.gov/docs/fy14osti/62558.pdf. 878 “Revolution Now – The Future Arrives for Four Clean Energy 

Technologies – 2014 Update,” DOE, Oct 2014. Available at: 

http://energy.gov/sites/prod/files/2014/10/f18/revolution_now_ 

updated_charts_and_text_october_2014_1.pdf. 
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current rating of the array’s inverter to increase energy 

production and improve project economics.879 The cost and 

performance improvements for wind and solar are driven by 

increased scale of production, improved technologies, and 

advancements in system deployments. 

3. Importance of Increasing Use of RE 

Currently, the utility power sector accounts for 40 percent 

of total annual energy consumption in the U.S.880 Introducing 

more zero-emitting RE generation over the long- term could 

significantly reduce CO2 emissions, as production of RE 

predominantly replaces fossil fuel-fired generation and thereby 

avoids the emissions from that replaced generation. 

 A number of studies and recent policy developments have 

acknowledged RE as an important means of achieving CO2

reductions. California cited the reduction of CO2 emissions from 

electrical generations as one of the reasons for increasing its 

RE target from 20 percent to 33 percent by 2020 (and potentially 

 

879 “Utility-Scale Solar 2013,” LBNL, Sept 2014. Available at: 

http://emp.lbl.gov/publications/utility-scale-solar-2013-

empirical-analysis-project-cost-performance-and-pricing-trends 

880 U.S. Energy Information Administration Annual Energy Review, 

2011. Accessed March 2015. Available at: 

http://www.eia.gov/totalenergy/data/monthly/pdf/flow/primary_ene

rgy.pdf. 
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50 percent by 2030).881 A recent IPCC report also concluded that 

RE has large potential to mitigate CO2 emissions.882

 Increased use of RE provides numerous benefits in addition 

to lower CO2 emissions. RE typically consumes less water than 

fossil fuel-fired EGUs. Wind power and solar PV systems do not 

require the use of any water to generate electricity; water is 

only needed for cleaning to ensure efficient operation. In 

contrast, utility boilers, in particular, require large 

quantities of water for steam generation and cooling.883

Increasing RE use will also continue to lower other air 

pollutants (e.g., fine particles, ground-level ozone, etc.), 

diversify energy supply, hedge against fossil fuel price 

increases and create economic development and jobs in 

manufacturing, installation, and other sectors of the economy. 

4. Ownership ofAccess to RE by Fossil Fuel-FiredOwners of 

Affected EGUs 

 

881 California S.B. 2 (1X), 2011. Accessed March 2015. Available 

at: http://www.leginfo.ca.gov/pub/11-12/bill/sen/sb_0001-

0050/sbx1_2_bill_20110412_chaptered.pdf.

882 IPCC, Renewable Energy Sources and Climate Change Mitigation, 

2012. Accessed March 2015. Available at: 

http://www.ipcc.ch/pdf/specialreports/srren/SRREN_Full_Report.pdf. 

883 EPA, Water Resource Use. Accessed on March 2015. Available 

at: http://www.epa.gov/cleanenergy/energy-and-you/affect/waterresource.html. 
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The ability of affected EGUs to co-locate or obtain 

incremental RE to reduce CO2 emissions is well-demonstrated, 

whether it is through direct ownership, bilateral contracts, or 

procurement of the environmental attributes associated with RE 

generation.884 Consequently, the EPA believes that an increase in 

RE is a proven way to reduce CO2 emissions at affected EGUs of 

all types at a reasonable cost. 

Affected Owners and operators of affected EGUs across the 

U.S. already have substantial opportunities to procure RE 

regardless of their organizational structure and/or business 

model. In many parts of the country, EGUs are owned and operated 

by vertically integrated utilities. These utilities can be 

investor-owned utilities that operate under traditional 

electricity regulation, municipal utilities (munis), or electric 

cooperatives (co-ops). These utilities have significant control 

over the types of generating capacity they develop or acquire, 

and over the electricity mix used to meet demand within their 

service territories. 

Even when EGU owners participating in organized markets do 

not directly determine dispatch among energy sources, such EGU 

 

884 Refer to the GHG AbatementMitigation Measures TSD for 

additional information on RE ownership statistics.and colocation. 
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owners make decisions about what types of capacity they choose 

to develop and thus what generation mix they can ultimately 

supply into that market’s dispatch choices. Because zeroemitting RE technologies have relatively low variable costs, an 

EGU owner’s decision to install (or to finance the installation 

of) RE capacity will yield lower-cost electricity generation 

that, when available, a system dispatcher will prefer over 

higher-variable-cost generation from fossil fuel-fired capacity. 

Therefore, all owners of affected EGUs have a direct path for 

replacing higher-emitting generation with RE regardless of their 

organizational type and regardless of whether they operate in a 

cost-of-service framework or in a competitive, organized market. 

Many affected EGUs have already directly invested in RE. Of 

the 417404 entities that owned part of at least one affected EGU 

under this rule, 191178 also owned RE (biomass, geothermal, 

solar, water or wind). These 191178 owners owned 8482 percent of 

affected EGU capacity. As a whole, these entities’ share of RE 

capacity was equal to 2125 percent of the total of their 

affected EGU capacity.885

Some of the largest owners of affected EGUs also owned RE 

(see Table 7). Of the 8). For example, NRG Energy, Inc. owns 

 

885 SNL Energy. Data used with permission. Accessed Januaryon 

June 9, 2015. 
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more than 3,000 MWmegawatts of RE capacity owned by NRG Energy, 

Inc., solar represents, over 20 percent of which (nearly 800 

MW)megawatts) is solar, and wind was almost 80 percent of the 

totalwhich (over 2,500 MW).megawatts) is wind. Duke Energy 

Corporation owns 175 MWmegawatts of solar and over 1,500 

MWmegawatts of wind. NextEra Energy, Inc.’s share of RE capacity 

approaches 40 percent of their total affected EGU capacity.886

Table 8 lists a sampling of affected EGUs that have large 

amounts of fossil fuel-fired capacity and RE capacity:

 

TABLE 7. Ownership8. Sample of Owners of Affected EGUs and RE 

Capacity.887,888 

Ultimate Parent Cover

ed 

Units 

Gener

ation 

(MWh)

Covered 

UnitsAffected 

EGU Capacity 

(MW) 

Renewable 

Capacity (MW) 

NRG Energy, Inc. 112,0

18,18

9

48,964787 3,303149

Duke Energy Corporation 155,255,05639,0

28

38,4465,

526

4,917

Southern Company 138,080,

95837,16

8

36,32

8

3,317245

American Electric Power 

Company, Inc. 

143,547,

59434,94

0

35,52

6

1,158142

 

886 Ibid. 887 SNL Energy. Data used with permission. Accessed on June 9, 

2015. 

888 eGRID, EPA. 2012 Unit-Level Data Using the eGRID Methodology. 

June 7, 2015 version. 

Deleted Cells

Deleted Cells

Deleted Cells
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NextEra Energy, Inc. 104,325,

61029,47

1

28,34

4

11,164626

Calpine Corporation 99,589,1

7223,878

24,14

8

1,637509

Entergy 

Corporation 

48,954,652 23,411 145 

Tennessee Valley 

Authority 

83,77

4,468

21,717 5,429427

Berkshire Hathaway 

Inc. 

83,55

8,238

18,899 6,342650

FirstEnergy Corp. 72,02

1,222

16,175 1,372371

Exelon Corporation 10,283 3,361

Nebraska Public Power 

District 

2,003 90

Basin Electric Power 

Cooperative 

1,526 275

American Municipal Power, 

Inc. 

1,112 53

Sacramento Municipal 

Utility District 

925 834

Golden Spread Electric 

Cooperative, Inc. 

521 78

 Large vertically integrated utilities generally have 

multiple options for investing in RE, including building their 

own RE capacity or procuring RE under a long-term power purchase 

agreement. Municipal utilities and rural cooperatives that own 

generating asset portfolios, particularly generation and 

transmission cooperatives and larger municipal utilities, have 

also used RE to reduce carbon emissions. Large generation and 

transmission cooperatives also purchase significant quantities 

Deleted Cells
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of RE for their members. Federal power authorities own or 

contract for significant amounts of RE.889,890

The list of the ten largest electric utilities with the 

largest amounts of wind power capacity on the system (ownerowned

or under contract) includes a variety of affected EGU 

organizational structures, including vertically integrated 

investor-owned utilities, municipal utilities, and federal power 

authorities. Xcel Energy and Berkshire Hathaway Energy rank 

number onefirst and twosecond with 5,736 MWmegawatts and 4,992 

MWmegawatts of wind capacity, respectively. Basin Electric Power 

Cooperative had 716 MWTennessee Valley Authority, a federal 

power authority, had 1,572 megawatts and CPS Energy, a public 

utility, had 1,059 MWmegawatts of wind power capacity.891 Basin 

Electric Power Cooperative had 716 megawatts and was the top 

 

889 American Wind Energy Association. AWEA Comments on EPA’s 

Proposed Carbon Pollution Emission Guidelines for Existing 

Stationary Sources and Supplemental Proposed Rule. pp. 88-91. 

890 SEIA comment pp. 98-147. Solar Energy Industries Association. 

Comments to the EPA and States on the Proposed Clean Power Plan 

Regulating Existing Power Plants Under Section 111(d) of the 

Clean Air Act. pp. 98-147.

891 American Wind Energy Association. U.S. Wind Industry Annual 

Market Report (2014 data). Accessed AprilJuly 2015. Available at 

http://www.awea.org/AnnualMarketReport.aspx?ItemNumber=7422&RDtoken=64560&userID=. The ten 

largest electric utilities with wind power capacity on the 

system (owner or under contract) includes: Xcel Energy; 

Berkshire Hathaway Energy; Southern California Edison; American 

Electric Power; Pacific Gas & Electric; Tennessee Valley 

Authority; San Diego Gas & Electric; CPS Energy; Los Angeles 

Department of Water & Power; and Alliant Energy.
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ranked cooperative utility, but is not on the top ten utilities 

with wind power capacity list. 

Many affected EGUs are already planning on deploying 

significant amounts of RE according to their integrated resource 

plans (IRPs). For instance, Dominion plans for over 800 MW of 

wind and solar in their 2015 to 2029 planning period. Electric 

utilities use IRPs to plan operations and investments over long 

time horizons. These plans typically cover 10 to 20 years and 

are mandated by public utility commissions (PUCs). A recent 

study of IRPs, included in the docket for this rulemaking, shows 

this trend.892 For instance, Dominion plans for over 800 

megawatts of wind and solar in their 2015 to 2029 planning 

period.893 Duke Energy Carolinas’ IRP has no plans for new coal, 

but describes plans for roughly 1,250 megawatts of additional RE 

by 2021, and approximately 2,150 megawatts by 2029. A 

significant portion (1,670 megawatts) of the planned RE is 

solar.894 Ameren is planning to retire one-third of the coal 

 

892 See memo entitled “Review of Electric Utility Integrated 

Resource Plans” (May 7, 2015). 

893 Dominion North Carolina Power's and Dominion Virginia Power's 

Report of Its Integrated Resource Plan, August 2014, Available 

at: 

https://www.dom.com/library/domcom/pdfs/corporate/integratedresource-planning/nc-irp-2014.pdf. 

894 Duke Energy Carolinas’ 2014 Integrated Resource Plan, 

September 2014, Available at: 
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generating capacity, as well as installing an additional 400 

megawatts of wind, 445 megawatts of solar, and 28 megawatts of 

hydroelectric generating capacity.895 

 EPA agrees with commenters that highlighted the opportunity 

owners and operators of affected EGUs across the U.S. already 

have to procure RE. Commenters found many fossil fuel-fired EGU 

owners own or contract for RE and can control the dispatch mix 

among these sources. 

One commenter highlighted that in many parts of the 

country, EGUs are owned and operated by vertically integrated 

utilities. These utilities can be investor owned utilities that 

operate under traditional electricity regulation, municipal 

utilities (munis), or electric cooperatives (co-ops). These 

utilities have significant control over the types of generating 

capacity they develop or acquire, and over the electricity mix 

used to meet demand within their service territories. 

The commenter similarly observed that EGU owners 

participating in organized markets retain sufficient control to 

substitute fossil fuel-fired generation with RE, even when those 

 

http://starw1.ncuc.net/NCUC/ViewFile.aspx?Id=c3c5cbb5-51f2-423a9dfc-a43ec559d307. 

895 Integrated Resource Plan Update, October 2014, Available at: 

https://www.ameren.com/missouri/environment/renewables/amerenmissouri-irp. 
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EGU owners do not directly determine dispatch among energy 

sources. They offered the example of Oklahoma Gas & Electric 

(OG&E), which owns generation assets utilizing coal, gas-fired 

combined cycle and wind technology and is able to make decisions 

regarding the utilization of fossil fuel-fired EGUs and energy 

assets within the rules of the regional transmission 

organization (RTO). OG&E and other EGU owners, including munis 

and co-ops operating in organized markets, can also make longerterm decisions about what types of capacity they choose to 

develop going forward. 

The commenter also emphasized that independentIndependent

power producers (IPPs) also can and do own both RE and fossil 

generation. They provided theFor example of, NRG, which is a 

diversified IPP that operates substantial coal, natural gas, 

wind, solar, and nuclear capacity. NRG demonstrates the ability 

of IPPs to reduce utilization of fossil fuel-fired EGUs and 

replace that generation with RE. NRG announced a goal to cut CO2

emissions from its fleet by 50 percent by 2030 (from a 2014 

baseline).896 NRG has already reduced CO2 emissions from its fleet 

 

896 NRG, “NRG Energy Sets Long-Term Sustainability Goals at 

Groundbreaking of “Ultra-Green” New Headquarters” (Nov. 20, 

2014), available at 

http://investors.nrg.com/phoenix.zhtml?c=121544&p=irolnewsArticl

e&ID=1991552. 
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by 40 percent since 2005. This achievement demonstrates that 

when an IPP commits to shifting its generation portfolio, it can 

do so at reasonable cost and without reliability impacts. The 

NRG example shows that reduced utilization of fossil fuel-fired 

EGUs that is replaced by RE also owned by the EGU owner is 

adequately demonstrated. 

Commenters said EGU owners can also replace fossil fuelfired generation with RE through bilateral contracts and 

renewable energy creditcertificate (REC) purchases. They stated 

that, as described below. Both the bilateral market for RE 

contracts and REC markets are well- developed. There are no 

legal or technical obstacles to a fossil fuel-fired EGU owner 

acting as the counterparty of a bilateral contract for purchase 

of energy from a RE facility. PurchaseAny type of RECs tracked 

in a registry is not limited to utilities. Third parties, 

including IPPs,EGU owner (utility or otherwise) can purchase and 

retire RECs. To date, there has not been significant need for 

merchant generators to purchase RECs. However, there are no 

legal or technical obstacles that would prevent this action. The 

fact that RECs are purchased by a diverse set of market 

participants— — including residential consumers, commercial 

businesses, and industrial facilities— — demonstrates that such 

a purchase for all EGU owners is adequately demonstrated. 
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5. Renewable Energy CreditCertificate Markets 

 RECs Affected EGU owners do not need to directly invest in, 

or own, renewable generating capacity in order to replace fossil 

fuel-fired generation with RE as an emission reduction measure. 

Renewable energy certificates (RECs) are used to demonstrate 

compliance with state RE targets, such as state RPS, and also to 

substantiate claims stemming from RE use. RECs are tradable 

instruments that represent are associated with the generation of 

one megawatt-hour (MWh) of RE and represent certain information 

or characteristics of the generation, called attributes.897 RECs 

aremay be traded and transferred regardless of the actual energy 

flow. REC ownership confers the right to claim the generation 

attributes. 

 The legal basis for RECs is established by state statutes 

and administrative rules. Nearly all states with a mandatory RPS 

have established RECs as a means of compliance. The Federal 

Energy Regulatory Commission (FERC) has ruledobserved that 

states have created RECs into facilitate programs designed to 

promote increased use of RE, and that “attributes associated 

 

897 EPA Green Power Partnership, Renewable Energy Certificates 

July 2008). Available at 

http://www.epa.gov/greenpower/documents/gpp_basics-recs.pdf. 
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with the [RE] facilities are separate from, and may be sold 

separately from, the capacity and energy.”898 

 In complying with states’ RPS requirements in 2012, 61 

percent of, utilities have contracted for RECs were sourced from 

in-state resources (65 percent on weighted average basis). When 

sourcing RECs fromand out-of-state, resources in accordance with

RPS requirements typically restrict eligible RECs to the state’s 

region (e.g., ISO or neighboring states).. Utilities may have 

sourced RECs from out-of-state to reduce the cost of compliance, 

to source RECs from specific generation types, or for other 

reasons.899

The development of REC markets to facilitate RPS compliance 

provides evidence that markets can develop to facilitate 

compliance with rate-based state plans. These markets will 

afford affected EGU owners an alternative to directly invest in, 

or own, renewable generating capacity in order to replace fossil 

 

898 FERC Docket No. EL03-133-000, Petition for Declaratory Order 

and Request for Expedited Consideration, American Ref-Fuel 

Company, Covanta Energy Group, Montenay Power Corporation, and 

Wheelabrator Technologies, Inc. June 16, 2003, Order Granting 

Petition for Declaratory Ruling, October 1, 2003. American RefFuel Co. et al., 105 FERC ¶ 61,004 (2003); and Order Denying 

Rehearing. April 15, 2004. 107 FERC ¶ 61,016 (2004). Available 

online at: http://www.ferc.gov/whats-new/comm-meet/041404/E28.pdf (accessed 11/7/2014). 

899 Heeter, J. Quantifying the Level of Cross-State Renewable 

Energy Transactions. NREL 2015. Available at 

http://www.nrel.gov/docs/fy15osti/63458.pdf. 
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fuel-fired generation with RE as an emission reduction measure. 

6. Quantification of Renewable Energy Generation Potential for 

BSER and Major Comments 

The methodology for quantifying RE target generation levels 

under building block 3 is a modified version of the alternative 

RE approach from proposal, with adjustments that reflect the 

data and information the EPA collected through stakeholder 

comments. and the EPA’s additional analysis and information 

collection. In evaluating the proposed and alternative RE 

approaches, commenters observed that RPS, as the basis for 

settingquantifying RE target generation levels under the 

proposed approach, are policy instruments that states may choose 

to implement for a variety of reasons not related to CO2 emission 

reductions. Additionally, differences across RPS policies in 

eligible resources, crediting mechanisms, deliverability 

requirements, alternative compliance payments, and other policy 

elements made the regional averaging of state-level RPS 

requirements challenging. Finally, commenters provided data 

demonstrating that RE resource potential can vary significantly 

within the regions identified under the proposed approach, 

producing state-level targetsRE generation levels that may not 

be aligned with the opportunity to deploy incremental RE 

resources at reasonable cost. In contrast, commenters argued 
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Page 971 of 2153

that a methodology similar to the alternative RE approach, which 

is based on economic potential, represents a more 

technicaltechnically sound basis for quantifying building block 

3 target generation levels that accounts for regional 

differences in RE resources and power market conditions, such as 

projected fuel prices, load growth and wholesale power prices. 

The EPA agrees with these comments. 

 Within the framework of the alternative RE approach, the 

EPA received significant comments on a number of issues, 

including the use of historical deployment rates, the interstate 

nature of RE and the power system, usemerits of total versus 

incremental RE generation to define targetas the metric by which 

building block 3 generation levels, are quantified, types of RE 

technologies that contribute to setting targetthose generation 

levels, cost and performance estimates associated with those RE

technologies, magnitude of the reduced cost applied to new RE 

capacity as an incentive to deploy, and application of a 

nationally uniform technical potential limiterbenchmark 

development rate to modeled projections of economic deployment. 

Based on commenter data and information, as well as further 

analysis and information collection, the primary adjustments the 

EPA made to the alternative RE approach are: 
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 The target generation level isThe basis for quantifying 

building block 3 generation has been modified to 

incorporate historical deployment patterns for RE 

technologies as well as the economic potential identified 

through modeling projections. The introduction of 

historical capacity additions to the final methodology 

further grounds building block 3 generation in demonstrated 

levels of RE deployment that have been successfully 

incorporated into the power system. This adjustment also 

serves to harmonize the approach across all three building 

blocks in which historical data is the primary basis for 

identifying emission reduction opportunities under the 

BSER. 

 The RE technologies used to quantify building block 3 

generation levels are onshore wind, utility-scale solar PV, 

concentrating solar power (CSP), geothermal and hydropower. 

Each of these technologies is a utility-scale, zeroemitting resource that was included under the alternative 

RE approach at proposal. Additionally, the EPA received 

significant comments on the opportunities and challenges 

associated with distributed RE technologies. Distributed 

technologies, as a demand-side resource, present unique 

data and technical challenges (such as the role of 
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Page 973 of 2153

evaluation, measurement and verification (EM&V) procedures 

in verifying their production, the diverse economic 

incentives of different parties involved in their 

deployment, and the variety of grid integration policies 

and conditions across potential deployment sites) that 

complicate identifying a technically feasible and costeffective level of generation. Consequently, the EPA is, at 

this time, choosing not to include distributed technologies 

as part of the BSER (although, as explained in section 

VIII.K of this preamble, distributed RE technologies that 

meets eligibility criteria may be used for compliance). 

Finally, any RE technology that has not been deployed in 

the United States, including demonstrated RE technologies 

for which there is clear evidence of technical feasibility 

and cost-effectiveness (e.g., offshore wind), contributes 

no generation to building block 3 under this historicallybased methodology. These RE technologies are consequently 

reserved for compliance, which offers affected EGUs 

additional flexibility and will reduce their need to rely 

on other emission reduction measures or building blocks. 

 Building block 3 generation levels are expressed in terms 

of incremental, rather than total, RE generation. As a 

metric, incremental generation is better aligned with 
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quantifying an amount of expanded RE to replace generation 

at affected EGUs.900 Specifically, the target generation 

levels under building block 3 include all generation from 

BSER RE technologiescapacity that commenced operation 

subsequent to 2012 (the BSER data year on which the BSER is 

evaluated). Commenters remarked that it is unnecessary to 

include generation from RE capacity that was already in 

operation by 2012 in building block 3 because the impact of 

2012.that generation on fossil fuel-fired EGUs is already 

reflected in the observed 2012 emissions and generation 

data of those EGUs. 

 Due to the interstate nature of RE and the power system, 

and consistent with the rationale provided in the October 

2014 Notice of Data Availability (NODA), targetbuilding 

block 3 generation levels are quantified for each of the 

three BSER regions – the Eastern Interconnection, Western 

Interconnection, and Texas Interconnection – rather than at 

the state-level. This regionalized approach, as described 

in the NODA, takes into account the opportunity to develop 

 

900 Consistent with the November 2014 Notice of Data 

Availability, the final goal setting methodology assumes 

replacement of affected EGU generation by incremental building 

block 3 generation in calculating source-specific CO2 emission 

performance rates. For additional information on the goal 

setting methodology refer to Section VI. 
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regional RE resources and thus better aligns building block 

3 generation levels with the rule’s approach to allowing 

the use of qualifying out-of-state renewable generation for 

compliance. 

 The BSER RE technologies used to quantify target generation 

levels no longer include landfill gas and concentrated solar 

power (CSP). Incremental landfill gas and CSP generation are no 

longer projected to deploy on an economic basis during the 

compliance period and consequently have been removed as BSER RE 

technologies. All other RE technologies from the proposed 

alternative approach – onshore wind, utility-scale solar PV, 

geothermal and hydropower – are maintained as part of the BSER 

and no new RE technologies have been added. 

 Commenters observed that the cost and performance estimates 

the EPA relied on at proposal from the Energy Information 

Administration’s Annual Energy Outlook 2013 are outdated 

and do not reflect the decline in cost and increase in 

performance that have been demonstrated by current 

projects, particularly in regards to wind and solar

technologies. Commenters provided data from a variety of 

sources to support these claims, including Lawrence 

BerkleyBerkeley National LabLaboratory, the Department of 

Energy (DOE) and Lazard. Consequently,Each of these sources 
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supported the contention that RE technologies, particularly 

wind and solar, have realized gains in cost and efficiency 

at a scale that has altered the competitive dynamic between 

RE and conventional resources. As a result, it has become 

increasingly necessary for any long-term outlook of the 

utility power sector to continually assess the development 

of RE technology cost and performance estimatestrends. In 

performing this task, the EPA revised its data for onshore 

wind and utility-scale solar technologies were revised to 

reflect the mid-case estimates from the National Renewable 

Energy Laboratory’s (NREL’s) 2015 Annual Technology 

Baseline. The EPA selected the NREL 2015 Annual Technology 

Baseline (ATB) estimates based on the quality of its data 

as well as NREL’s demonstrated success in both reflecting 

and anticipating RE cost and performance trends. In 

addition to wind and solar technologies, the EPA evaluated 

hydropower deployment potential based on the latest cost 

and performance data from NREL’s Renewable Energy Economic 

Potential study.901

 

901 For additional information on the updated RE cost and 

performance assumptions used to quantify building block 3 

generation, refer to the GHG Mitigation Measures TSD. 
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 The final methodology for quantifying building block 3 target 

generation applies a reduced cost of building new RE capacity of 

$40 per metric ton CO2. This cost represents the avoided cost of 

other actions that could be taken instead to reduce CO2 emissions 

from the utility power sector and, unlike at proposal, is not 

derived from RE technology cost assumptions but rather results 

from the costs associated with building block 2. A harmonized 

cost-effectiveness threshold across building blocks 2 and 3 

ensures that emission reduction opportunities are evaluated for 

inclusion in the BSER on equitable terms. 

 The technical potential limiterbenchmark development rate

that constrained cost-effective RE deployment under the 

alternative RE approach in the proposal has been removed 

from the final methodology.902 Commenters observeddetailed

several issues with applying the technical potential 

limiterbenchmark development rate, including that this 

feature limits future performance to historical levels of 

development,it does not factor in the total size of the RE 

resource in a given state, relies on non-exclusive resource 

estimates where a single area of land may contribute to the 

 

902 The technical potential limiter was a nationally uniform, 

technology-specific limit on cost-effective RE deployment based 

on the amount of 2012 generation in a state as a share of that 

state’s total technical potential. 
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technical potential of multiple RE technologies, and is 

inconsistent with a regional approach to quantifying target 

generation levels. EPA agrees with these comments and the 

technical potential limiterbenchmark development rate has 

been eliminated. 

In addition to the comments described above, the EPA 

received significant comments on a wide variety of topics 

related to building block 23. Many of these comments provided 

helpful information and insights, and have resulted in 

improvements to the final rule. These comments, as well as the 

EPA responses, are available in the Response to Comment 

document. 

The final methodology for quantifying incremental RE target 

generation levels relies on a combination of modeling and nonmodeling approaches that produce regional technology-specific 

estimates.contains seven steps. Each step is described below.903

Estimates for the economic potential of new hydropower are 

the result of a DOE avoided cost methodology that develops 

regional hydropower supply curves and compares that supply 

potential against the revenue available to those projects 

 

903 For supporting data, documentation, and examples for each 

step of the quantification methodology, refer to the GHG 

Mitigation Measures TSD. 
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through regional marginal generation prices and capacity values. 

The deployment levels of hydropower are increased until total 

generation costs, inclusive of the reduced cost of building new 

RE capacity, equal avoided costs for each region. 

In contrast, economic potential estimates for utility-scale 

solar photovoltaic (PV)), onshore wind and geothermal 

technologies areFirst, the EPA collected data for each RE 

technology (onshore wind, utility-scale solar PV, CSP, 

geothermal and hydropower) to determine the annual change in 

capacity over the most recent five-year period. From these data, 

the EPA calculated the five-year annual average change in 

capacity and the five-year maximum annual change in capacity for 

each technology. 

Second, the EPA determined an appropriate capacity factor 

to apply to each RE technology that would be representative of 

expected future performance from 2022 through 2030. For this 

purpose the result of IPM EPA relied on NREL’s ATB. 

Third, the EPA calculated two generation levels for each RE 

technology. The first generation level is the product of each 

technology’s five-year average capacity change and the assumed 

future capacity factor. The second generation level is the 

product of each technology’s five-year maximum annual capacity 
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deployment and the assumed future capacity factor. Table 9 below 

shows the data and assumptions used for these calculations. 

TABLE 9. Historical Capacity Changes and Associated Generation 

Levels. 

 Assumed 

Future 

Capacity 

Factor 

Five-Year 

Average 

Capacity 

Change 

(MW) 

Generation 

Associated 

with Five 

Year-Average 

Capacity 

Change (MWh)

Maximum 

Annual 

Capacity 

Change 

(MW) 

Generation 

Associated 

with Maximum 

Annual 

Capacity 

Change (MWh) 

UtilityScale Solar 

PV904

20.7% 1,927 

3,494,268 

3,934 

7,133,601 

CSP 34.3% 251 

754,175 767 2,304,590 

Onshore 

Wind 41.8% 6,200 

22,702,416 13,131 48,081,520 

Geothermal 85.0% 142 

1,057,332 407 3,030,522 

Hydropower 63.8% 141 

788,032 294 1,643,131 

Total 

Generation N/A N/A 

28,796,222 N/A 62,193,363 

Fourth, the EPA quantified the RE generation from capacity 

commencing operation after 2012 that can be expected in 2021 

(the year before this rule’s first compliance period) without 

the imposition of this rule. Because building block 3 is focused 

on the ability of fossil fuel-fired EGUs to reduce their 

 

904 Capacity values for utility-scale solar PV are expressed in 

terms of MWDC. The assumed future capacity factor for this 

utility-scale solar PV includes a DC-to-AC conversion, enabling 

the generation totals to be combined across all RE technologies. 
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emissions by deploying incremental RE, it is reasonable to take 

into account the considerable amount of RE deployment that is 

already taking place and is projected to continue doing so 

before considering the additional deployment that would be 

motivated by this rule’s mandate to reduce emissions from 

affected EGUs. The EPA considered its base case power sector 

modeling projections thatusing IPM to quantify this component of 

future-year RE generation, which the EPA assumes to be 

213,084,125 megawatt-hours in 2021. 

 Fifth, the EPA applied the generation associated with the 

five-year average capacity change to the first two years of the 

interim period. Combining the projected 2021 RE generation from 

capacity starting operation after 2012 with the generation 

increment associated with the five-year average change in 

capacity produces 241,880,347 megawatt-hours in 2022 and 

270,676,570 megawatt-hours in 2023. The EPA believes it is 

appropriate to apply the generation associated with the fiveyear average capacity change for the first two years of the 

interim period to ensure adequate opportunity to plan for and 

implement any necessary RE integration strategies and 

investments in advance of the higher RE deployment levels 

assumed for later years. 
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Sixth, for all years subsequent to 2023 the EPA applied the 

generation associated with the maximum annual capacity change 

from the historical data analysis. In 2024, this produces a 

building block 3 generation level of 332,869,933 megawatt-hours 

(aggregated across all three BSER regions); by 2030, that 

generation level is 706,030,112 megawatt-hours. 

Seventh, to further evaluate the technical feasibility and 

cost-effectiveness of the building block 3 generation levels 

(aggregated across all three BSER regions), as well as to 

produce interconnection-specific levels of building block 3 

generation from the national totals described in steps 5 and 6, 

the EPA conducted analysis using IPM of a scenario directing the 

power sector to achieve those RE generation levels. IPM modeling 

projections assess opportunities for RE deployment in an 

integrated framework across power, fuel, and emission markets. 

The modeling framework incorporates a host of constraints on the 

deployment of RE resources, including resource constraints (such 

as resource quality, land use exclusions, terrain variability, 

distance to existing transmission, and population density

etc.),; system constraints (such as interregional transmission 

limits, partial reserve margin credit for intermittent RE 

installations, minimum turndown constraints for fossil fuelfired EGUs, and short-term capital cost adders to reflect the 
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potential added cost due to competition for scarce labor and 

materials etc.); and technology constraints (such as 

construction lead times, and hourly generation profiles for nondispatchable resources by season etc.)..905 Additionally, the EPA 

assumes in this analysis that deployment of variable, nondispatchable RE resources in IPM is limited to 20 percent of net 

energy for load by technology type and 30 percent of net energy 

for load in total at each of IPM’s 64 U.S. sub-regions.906 These 

constraints do not represent a technical feasibility limit but 

rather a conservative view of penetration levels that would not 

requireThe 30 percent constraint applied to variable, nondispatchable RE resources reflects levels commonly modeled in 

grid integration studies at the level of the interconnection. 

These studies have demonstrated that impacts to the grid in 

reaching levels as high as 30 percent of net energy for load are 

relatively minor.907 For example, the Western Wind and Solar 

Study Phase 2 found cycling costs ranged from $0.14 to $0.67 per 

 

905 Refer to GHG AbatementMitigation Measures TSD for more detail 

on modeling methodology. 

906 Regions that have already exceeded these limits are held at 

historical percent of net energy for load. 

907 Wind Technologies Market Report 2013. LBNL. Cochran, et al. 

2014; Grid Integration and the Carrying Capacity of the U.S. 

Grid to Incorporate Variable Renewable Energy. NREL. Cochran, et 

al. 2015; The Western Wind and Solar Integration Study Phase 2. 

NREL. Lew, et al. 2013. Refer to GHG Mitigation Measures TSD for 

further analysis. 
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megawatt-hour of added wind and solar generation. These 

integration cost levels are not impactful in determining costeffectiveness. As such, applying the 30 percent constraints at 

the IPM sub-region level is very conservative and provides a 

high degree of assurance that the RE capacity deployment pattern 

projected by the model would not incur significant grid 

integration costs.908 

To reflect the interstate nature of the power system, the 

economic potential identified under the avoided cost and 

modeling approaches is presented on a regional basis. Three 

power sector regions are used for this purpose – the Eastern 

Interconnection, Western Interconnection and Texas 

Interconnection.909 

The regional economic potential in 2030 sets the final RE 

target generation level under building block 3. To ensure 

adequate opportunity to plan for and implement any necessary RE 

integration strategies and investments, 2030 economic potential 

levels are phased in over the interim compliance period in three 

stages – 2022 through 2024, 2025 through 2027, and 2028 through 

2030. The first stage of deployment limits growth in RE target 

 

908 Refer to the GHG AbatementMitigation Measures TSD for 

additional information on constraints related to deployment of 

non-dispatchable RE. 

909 Refer to Section V.A.3. 
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generation to annual increases consistent with the most recent 

five-year deployment averages for the BSER RE technologies. The 

second stage limits annual target generation growth to levels 

consistent with the historical maximum deployment for the BSER 

RE technologies. The third stage increases target generation 

levels at a constant level from 2028 through 2030 to achieve the 

2030 economic potential.910 Regional RE target generation values 

for all years, representing RE generation incremental to the 

BSER data year of 2012, are presented below. 

In addition to facilitating the EPA’s assessment of the 

feasibility and cost of reaching the aggregate building block 3 

generation levels across all three BSER regions, the IPM 

projections also provide the EPA with a basis for apportioning 

those generation levels to each interconnection. The EPA 

considered the projected regional location of the evaluated RE 

deployment in this analysis, which shows the majority of such 

deployment occurring in the Eastern Interconnection. The GHG 

Mitigation Measures TSD describes in greater detail the process 

by which the EPA calculated the apportionment of building block 

3 generation levels to each of the BSER regions, taking these 

modeling projections into account. Table 10 describes the annual 

 

910 Additional information on interim period RE target generation 

levels is available in the GHG Abatement Measures TSD. 
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building block 3 generation levels for each interconnection from 

2022 through 2030. 

TABLE 810. Building Block 3 Target Generation Levels (MWh). 

Year Eastern 

Interconnection 

Western 

Interconnection 

Electric 

Reliability Council 

of Texas

Interconnection

2022 145,326,468 

166,253,134 

 

56,931,543663,541 

31,058,067 

18,963,672 

2023 167,746,931 

181,542,775 

 

60,443,578956,363 

37,217,478 

28,177,431 

2024 189,692,816 

218,243,050 

64,798,622 

75,244,721 

43,008,457 

39,382,162 

2025 233,278,550 

254,943,325 

76,786,908 

89,533,078 

53,643,200 

50,586,893 

2026 271,801,204 

291,643,600 

95,456,423 

103,821,436 

62,659,794 

61,791,623 

2027 309,867,354 

328,343,875 

114,669,103 

118,109,793 

71,589,727 

72,996,354 

2028 366,885,008 

365,044,150 

141,757,894 

132,398,151 84,920,883201,085 

2029 423,280,371 

401,744,425 

169,587,110 

146,686,508 

98,133,904 

95,405,816 

2030 479,177,844 

438,444,700 

198,008,732 

160,974,866 

111,252,409 

106,610,547 

7Through the quantification methodology detailed above, the 

EPA has identified amounts of incremental RE generation that are 

reasonable, rather than the maximum amounts that could be 

achieved while preserving the cost-effectiveness of the building 

block. For example, assuming gradual improvement in RE 

technology capacity factors consistent with historical trends, 

expanding the portfolio of RE technologies that contribute to 

the building block 3 generation level, and applying the five-
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year maximum capacity change values to all years of the interim 

period are adjustments that would produce higher building block 

3 generation levels and maintain the primacy of historical data 

in quantifying RE generation potential. External analysis and 

studies of RE penetration levels strongly support the technical 

feasibility and cost-reasonableness of RE deployment well in 

excess of the levels established by building block 3, as 

detailed in section V.E.7. By identifying reasonable rather than 

maximum achievable amounts, we are increasing the assurance that 

that the identified amounts are achievable by the source 

category and providing greater flexibility to individual 

affected EGUs to choose among alternative measures for achieving 

compliance with the standards of performance established for 

them in their states’ section 111(d) plans. 

7. Feasibility of Renewable Energy Deployment 

 The 2030 level of RE deployment and the rate of progress 

during the interim period in getting to that level are well 

supported by comments received, DOE and NREL analysis, and 

external studies evaluating the costs of and potential for RE 

penetration. The EPA has assessed the feasibility of RE in terms 

of deployment potential, system integration, reliability, backup 

capacity, transmission investments, and RE supply chains. 
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Historical RE deployment rates are a strong indication of 

the feasibility of the 2030 level of deployment and interim 

period pathway. The use of RE continues to grow rapidly in the 

U.S. In 2013, electricity generated from RE, including 

conventional hydropower, represented 13 percent of total U.S. 

electricity, up from 9 percent in 2005. In particular, there has 

been substantial growth in the wind and solar markets in the 

past decade. Since 2009, wind energy has tripled and solar has 

grown tenfold. 

The expected future capacity installations in 2022-2030 

needed to reach the 2030 level of incremental RE generation are 

consistent with historical deployment patterns. Forecasts by 

Cambridge Energy Research Associates (CERA) of 17 gigawatts in 

2015 and historical deployment of 16 gigawatts in 2012 are 

significant. The average deployment of wind over the past five 

years was 6,200 megawatts per year; 2014 deployment of solar PV, 

both distributed and utility-scale, was 6,201 megawatts. This 

contribution from solar PV is consistent with the rapid 

reduction in costs that is currently being observed and is 

expected to continue. 

Grid operators are reliably integrating large amounts of 

RE, including variable, non-dispatchable RE today. For example, 

Iowa and South Dakota produced more than 25 percent of their 
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electricity from wind in 2013, with a total of nine states above 

12 percent and 17 states at more than 5 percent. California 

served nearly 19 percent of total load in 2013 with RE 

resources, not including behind-the-meter distributed solar 

resources, and approximately 25 percent of total load with RE in 

2014. On an instantaneous basis, California is regularly serving 

above 25 percent of load with RE resources, recently began 

seeing over 5,000 megawatt-hours of solar energy, and is on 

track for 33 percent of load with no serious reliability or grid 

integration issues. Germany exceeded 28 percent non-hydro RE as 

a percentage of total energy in first half of 2014. Other recent 

examples include: ERCOT met 40 percent of demand on March 31, 

2014 with wind power; SPP met 33 percent of demand on April 6, 

2013 with wind power; and, Xcel Energy Colorado met 60 percent 

of demand on May 2, 2013 with wind power. Operational and 

technical upgrades to the power system may be required to 

accommodate high levels of variable, non-dispatchable RE like 

wind and solar over longer time periods; however, the 

penetration levels cited above have been achieved without 

negative impacts to reliability due in large part to low-cost 

measures such as expanded operational flexibility and effective 

coordination with other regional markets. 
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RE can contribute to reliable system operation. The 

abundance and diversity of RE resources in the U.S. can support 

multiple combinations of RE in much higher penetrations. When 

California, the Midwest, PJM, New York, and New England 

experienced record winter demand and prices during the polar 

vortex, wind generation played a key role in maintaining system 

reliability. 

Wind and solar PV are increasingly productive and capable 

of being accurately forecast, which improves grid reliability. 

Increasing capacity factors mean less variability and more 

generation. While the wind industry develops more projects at 

lower wind speed sites, wind turbine design changes are driving 

capacity factors higher among projects located in a given wind 

resource regime.911 Average capacity factors have risen from the 

low 30 percent range to high 30 percent range and continue to 

improve. One key recent advancement is the increasing use of 

turbines designed for low to medium wind speed sites (with 

higher hub-heights and larger rotors, relative to nameplate 

capacity) at higher wind-speed sites with low turbulence. 

 

911 LBNL, Wind Technologies Market Report 2013, August 2014, p. 

43, Available at: 

http://emp.lbl.gov/sites/all/files/2013_Wind_Technologies_Market

_Report_Final3.pdf. 
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New variable RE generators can provide more electrical 

power grid support services beyond just energy. Modern wind 

turbine power electronics allow turbines to provide voltage and 

reactive power control at all times. Wind plants meet a higher 

standard and far exceed the ability of conventional power plants 

to “ride-through” power system disturbances, which is essential 

for maintaining reliability when large conventional power plants 

break down. Xcel Energy sometimes uses its wind plants’ 

exceedingly fast response to meet system need for frequency 

response and dispatchable resources. Utility-scale PV can 

incorporate control systems that enable solar PV to contribute 

to grid reliability and stability, such as voltage regulation, 

active power controls, ramp-rate controls, fault ride through, 

and frequency control. Solar generation is capable of providing 

many ancillary services that the grid needs but, like other 

generators, needs the proper market signals to trade energy 

generation for ancillary service provision. 

The transmission network can connect distant high-quality 

RE to load centers and improve reliability by increasing system 

flexibility. Investments in transmission and distribution 

upgrades also enable improvements in system-wide environmental 

performance at lower cost. 
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The potential range of new transmission construction is 

within historical investment magnitudes. Under nearly all 

scenarios analyzed for the DOE’s Quadrennial Energy Review, 

circuit-miles of transmission added through 2030 are roughly 

equal to those needed under the base case, and while those base 

case transmission needs are significant, they do not appear to 

exceed historical annual build rates. DOE’s Wind Vision findings 

project 11.5 gigawatts of wind per year from 2021-2030. This 

deployment level would require 890 circuit miles per year of new 

transmission; 870 miles per year have been added on average 

between 1991 and 2013. 11.5 gigawatts per year is consistent 

with building block 3 deployment levels for wind capacity over 

the compliance period. DOE’s SunShot scenario, which increases 

utility-scale PV to 180 gigawatts by 2030, required spending of 

$60 billion on transmission through 2050. On an average annual 

basis, this expenditure is within the historical range of annual 

transmission investments made by IOUs in recent decades. 

Incremental grid infrastructure needs can be minimized by 

repurposing existing transmission resources. Transmission 

formerly used to deliver fossil-fired power to distant loads can 

– and is – being used to deliver renewable energy without new 

infrastructure. First Solar’s Moapa project uses transmission 

built to deliver coal-fired power from Navajo to Los Angeles. NV 
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Energy’s retirement of Reid-Gardner will free up additional 

transmission capacity. The Milford wind projects in Utah already 

utilize transmission that was built to deliver coal power to Los 

Angeles. 

Storage can be helpful but is not essential for the 

feasibility of RE deployment because there are many sources of 

flexibility on the grid. DOE’s Wind Vision and many other 

studies have found an array of integration options (e.g., large 

balancing areas, geographically dispersed RE, weather 

forecasting used in system operations, sub-hourly energy 

markets, access to neighboring markets) for RE beyond storage. 

Storage is a system resource, as its value for renewables is a 

small share of its total value. 

Increasing regional coordination between balancing areas 

will increase operational flexibility. The Energy Imbalance 

Market (EIM) recently implemented by the California ISO and 

Pacificorp is a good example of the increased coordination that 

will be helpful in ensuring that resources across the West are 

being utilized in an efficient way. 

Significant wind and solar supply chains have developed in 

the past decade to serve the fast-growing US RE market. For 

wind, domestic production capability would likely have to 

increase to accommodate projected builds under the CPP in the 
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2022-2030 time period; however, the global supply chain has 

expanded significantly to serve multiple markets and can augment 

production from the domestic supply chain, if necessary. At the 

start of 2014, the U.S. domestic supply chain could produce 

10,000 blades (6.2 gigawatts) and 4300 towers (8 gigawatts) 

annually. It is not anticipated that expanded domestic 

manufacturing will be constrained by raw materials availability 

or manufacturing capability. For solar technologies, the global 

supply chain has a capacity that has significantly expanded over 

the past few years from 1.4 gigawatts per year in 2004 to 22.5 

gigawatts per year in 2011. Current capacity exceeds these 

levels and is expected to grow. For PV systems, raw materials 

like tellurium and indium are at highest risk of supply 

shortage, but these materials are not used in the PV 

technologies currently being deployed at large-scale. 

8. Cost of CO2 Emission Reductions from Renewable Energy 

Generation 

The EPA believes that RE generation at the levels 

represented in building block 3 can be achieved at reasonable 

costs. The DOE avoided cost methodology applies a reduced cost 

of building new hydropower generating capacity of approximately 

$35 per metric ton. Under the In the EPA’s modeling approach, 

the EPA applies a reduced cost of building new utility-scale 
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solar PV, onshore wind and geothermal generating capacity of $40 

per metric ton CO2. This reduced cost is translated to $28 per 

MWh for inclusion in the modeling framework, under the 

assumption that incremental RE is replacing affected EGU 

generation of an approximate emissions intensity of 0.7 metric 

tons of CO2 per MWh.912 The projected total power system cost of 

applying this reduced cost to the EPA Base Case is $2.2 billion 

annually from 2022 through 2030. Total power system costs are a 

function of annualized capital costs, variable operating 

expenses, fixed operating expenses, fuel purchases and the 

expense associated with the benefit of providing the reduced 

cost to each qualifying RE build. The of the building block 3 

generation level, the projected emissioncost of achieving CO2

reductions average 165 million metric tons from 2022 through 

2030. Consequently, the cost of achieving CO2 reductions through 

the through this expansion of RE generation is $1337 per metric

ton on average from 2022 through 2030.913 There are a number of 

reasons why the EPA believes that the cost of CO2 emission 

reductions from RE generation will be lower than what is 

 

912 In the EPA Base Case, fossil fuel-fired EGUs are projected to 

operate in the EPA Base Case at approximately 0.72 metric tons 

of CO2 per MWh in 2030. 913 Refer to the GHG AbatementMitigation Measures TSD for further 

analysis and IPM run results. 
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presented in this section. First, interim period target 

generation is, on average, more than 20 percent less than the 

economic potential identified by the modeling and avoided cost 

approaches. Second, this analysis suggests. First, modeling 

constraints that restrict variable, non-dispatchable RE 

technologies to a percentage30 percent of net energy for load at 

each of the 64 U.S. IPM regions represents uncertainty 

associated with is a conservative limit intended to eliminate 

significant grid integration costs rather than a determination 

of technical infeasibility.at increased levels of RE 

penetration. In fact, many regions have already demonstrated 

levels of RE penetration that exceed the constraints. Third,, 

and in practice intermittency can be managed across larger 

regions than the total system costs presented in this section 

assume all incremental generation in 64. Consequently, the 

compliance period receives the full benefitextent to which these 

regions could, in practice, achieve higher levels of the cost 

reduction; however, the majority of cost-effective RE generation 

projecteddeployment without facing substantial grid integration 

costs would lead to a lower-cost RE outcome than is estimated by 

IPM does not require the full $28 per MWh reduced cost to become 

economic. Fourththis analysis. Second, there are a number 

ofmultiple RE technologies not included in the BSER that may 
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contribute to compliance withquantified under building block 3 

target generation, including that affected EGUs may use to 

demonstrate compliance (distributed generation technologies, 

offshore wind, CSP, waste-to-energy and many other technologies 

that are already in widespread use.914etc.). Based on preliminary 

analysis from DOE and NREL, cost-effective opportunities for 

distributed generation alone could satisfy one-third to over 

one-half of the stringency associated with building block 3.915

Third, as discussed in section V and VI of the preamble, the 

BSER reflects the degree of emission limitation achieved through 

the application of the building blocks in the least stringent 

region. By definition, in the other two regions the BSER is less 

stringent than the simple combination of the three building 

blocks, rendering a portion of the emission reduction potential 

quantified by the building blocks unnecessary to achieving the 

interim and final CO2 emission performance rates. For example, 

the EPA has calculated that in excess of 160,000,000 megawatthours of building block 3 potential is not required to achieve 

the final CO2 emission performance rates in 2030 – and would be 

 

914 See Section VIII.G for a description of qualifying non-BSER 

RE technologies 

915 See Section VIII.K. for a description of qualifying RE 

technologies for compliance. 
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accessible to affected EGUs for compliance.916 Therefore, it is 

reasonable to expect that it would cost less to achieve the 

component of building block 3 potential that is reflected in the 

calculation of the final CO2 emission performance rates, as 

compared to the results of this analysis which assumed 

achievement of the entire quantified building block 3 potential.

The EPA believes that these factors provide significant 

opportunities for lower-cost achievement of the building block 3 

target generation levels at lower costs than estimated in this 

analysis. 

VI. Source CategorySubcategory-Specific CO2 Emission Performance 

Rates 

A. Overview 

In this section, the EPA sets out technologysubcategoryspecific CO2 emission performance rates to guide states in 

development of their state plans. The emission performance rates 

reflect the emission rates for two generating source 

categoriessubcategories affected by the rule (fossil steam 

 

916 For additional discussion on how this concept impacts 

building block 3 generation levels, refer to the GHG Mitigation 

Measures TSD and the CO2 Emission Performance Rate and Goal 

Computation TSD for Final CPP. 
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generation and gas-fired combustion turbines).917 These final 

emission performance rates reflect the EPA’s quantification of 

the BSER based on the three building blocks described in section 

V above. This procedure follows a similar logic to BSER 

quantification at proposal, but it keeps the emission 

performance rates separate for fossil steam and NGCC source 

categoriessubcategories instead of immediately blending them 

together into a single value for all affected categoriesEGUs. 

Commenters noted that the proposed rule established 

standardsguidelines that were based on the aggregation of units, 

and their reduction potential, in a state rather than providing 

technology-specific standardsguidelines. While many commenters 

appreciated the flexibility this state-focused structure 

provided, some noted two concerns with this approach: 1) it 

would potentially create different incentives for the same 

generating technology class depending on the state in which that 

generator was located, and 2) it deviated from the EPA’s 

 

917 The only natural gas unitsfired EGUs currently considered 

“likely affected” units under the 111(d) applicability criteria

are turbines at NGCC units (capable of supplying more than 25 MW 

of electrical output to the grid. The data and rates for these 

units represent all emissions and MWh output associated with 

both the gas and combustion turbines as well as all associated 

heat recovery steam turbine).generating units. The remainder of 

the section will use the term “NGCC” to collectively refer to 

the output from both the steam and gas turbines at a NGCC 

unitthese natural gas fired EGUs. 
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previous interpretation of the 111(d) regulatory 

standardsguidelines by not providing technology-specific 

standards of performance. In response to these comments and our 

further consideration, the final rule establishes 

technologysubcategory-specific emission performance rates that 

are identical across units within a source categorysubcategory

regardless of where a unit is located within the 

continentalcontiguous U.S.918 These subcategory-specific 

emission performance rates are then translated into statespecific goals which, as in the proposal, reflect the particular 

energy mix present in each state. That translation is presented 

in section VII.

These performance rates reflect the average emission rate 

requirement for each source categorysubcategory. Similar to the 

proposal, they are presented as adjusted average emission rates 

that reflect other generation components of BSER (e.g., 

renewable) in addition to the fossil component. These 

performance rates must be achieved by 2030 and sustained 

thereafter. The interim performance rates apply over a 2022-2029 

interim period and would be achieved on average through 

 

918 As noted later in this section, the approach for states and 

U.S. territories outside the continental U.S. does not rely on 

the emission performance rates because units in these areas do 

not have access to regional interconnected grids. 
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reasonable implementation of the best system of emission 

reduction (based on all three building blocks) described above. 

In other words, the interim performance rates are consistent 

with a reasonable deployment schedule of BSER technology 

categoriestechnologies as they scale up to their full BSER 

potential by 2030. The performance rates are meant to reflect 

emission performance required across all affected unitsEGUs when 

averaged together and inclusive of lower-emitting BSER 

components. 

 The performance rates are expressed in the form of 

adjusted919 output-weighted-average CO2 emission rates for 

affected EGUs. However, states are authorized to use a converted 

statewide rate-based or mass-based goal as discussed in the next 

section. The EPA has determined that the statewide rate-based 

and mass-based CO2 goals are expressions of the emission 

performance rates equivalent to application of the emission 

performance rates to affected unitsEGUs within a state. 

 

919 As described below, the emission performance rates include 

adjustments to incorporate the potential effects of emission 

reduction measures that address power sector CO2 emissions 

primarily by reducing the amount of electricity produced at a 

state’s affected EGUs (associated with, for example, increasing 

the amount of new low- or zero-carbon generation rather than by 

reducing their CO2 emission rates per unit of energy output 

produced). 
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The EPA is finalizing the performance rates in a manner 

consistent with the proposal, with appropriate adjustments based 

on comments. Stakeholders had the opportunity to demonstrate 

during the comment period that application of one or more of the 

building blocks to that state would not be expected to produce 

the level of emission reduction quantified by the EPA because 

implementation of the building block at the levels envisioned by 

the EPA was technically infeasible, or because the costs of 

doing so were significantly higher than projected by the EPA. 

The EPA has considered all of this input in setting final 

performance rates. 

The remainder of this section addresses two sets of topics. 

First, we discuss several issues related to the form of the 

performance rates. Second, we describe the performance rates, 

computation procedure, and adjustments made between proposal and 

final based on stakeholder feedback in the comment period. 

 Some of the topics addressed in this section are addressed 

in greater detail in supplemental documents available in the 

docket for this rulemaking, including the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule and 

the Greenhouse Gas AbatementMitigation Measures TSD. Specific 

topics addressed in the various TSDs are noted throughout the 

discussion below. 
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B. Emission Performance Rate Requirements 

The EPA has developed a single performance rate requirement 

for existing fossil steam units in the continentalcontiguous

U.S., and a single rate for existing gas turbines in the 

continentalcontiguous U.S., reflecting application of the BSER, 

based on all three building blocks described earlier, to 

pertinent data. The rates are intended to represent CO2 emission 

rates achievable by 2030 after a 2022-2029 interim period on an 

output-weighted-average basis collectively by all affected EGUs, 

with certain computation adjustments described below to reflect 

the potential to achieve mass emission reductions by avoiding 

fossil fuel-fired generation. 

1. Final emission performance rate requirements 

The emission performance rates are set forth in Table 811

below, followed by a description of the computation methodology. 

Table 811. Emission Performance Rates (Adjusted Output-WeightedAverage Pounds of CO2 Per Net MWh From All Affected Fossil FuelFired EGUs). 

Subcategory Interim Rate Final Rate 

Fossil Fuel-Fired Electric 

Steam Generating Units 

1,465534 1,290305

Stationary Combustion 

Turbines 

810832 780771

 
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 The emission performance rates are expressed as adjusted 

output-weighted-average emission rates for each 

technologysubcategory. As discussed later in this section, the 

emission rate computation includes an adjustment designed to 

reflect mass emission reductions associated with lower-emitting 

BSER components. The adjustment is made by estimating the annual 

net generation associated with an achievable amount of 

qualifying incremental lower-carbon and zero-carbon generation 

and substituting those MWhs (along with corresponding emissions) 

for the baseline electricity generation and CO2 emissions from 

the higher-emitting affected EGUs. Under the final rule 

approach, regionally identified building block three3 potential 

generation replaces fossil steam and NGCC generation on a prorata basis corresponding to the historic mix of fossil 

generation in each region. However, as discussed in Section 

VIII, it the state decides to implement these adjustments in its 

state plan, the state must still demonstrate compliance with the 

CO2 emission performance rates for affected EGUs or the 

equivalent state-based goals provided in section VIIbaseline mix 

of fossil generation in each region. 

2. Interim Emission Performance Rates 

CommentersSome commenters suggested that the interim period 

starting in 2020 provided too little time for implementation of 
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Page 1005 of 2153

measures required to demonstrate compliance during the interim 

period. As discussed in section V.A.3.g of this preamble, the 

EPA has determined that an interim period beginning in 2022 

provides sufficient time for states to undertake necessary 

planning exercises and for the implementation of measures 

towards achieving the performance rates. The EPA determined the 

interim rates in a manner similar to proposal, with an 

adaptation to address the revised timing of the interim 

compliance period (beginning in 2022 rather than in 2020 as 

proposed). They reflect the averaging of estimated emission 

performance rates for each year in the interim period (i.e., 

2022-2029). 

The interim performance rates are less stringent than the 

final 2030 emission performance rates because the amount of 

emission reduction potential identified for the BSER increases 

over time, as explained in section V above. 

C. Form of the Emission Performance Rates 

1. Rate-based standardguidelines

 The interim and final emission performance rates for fossil 

steam and NGCC units are presented in the form of adjusted 

output-weighted-average CO2 emission rates that the affected 

fossil fuel-fired units could achieve, on average, through 

application of the measures comprising the BSER (or alternative 
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control methods). Several aspects of this form of emission rate 

are worth noting at the outset: the use of emission rates 

expressed in terms of net rather than gross energy output; the 

use of output-weighted-average emission rates for all affected 

EGUs; the use of adjustments to accommodate incremental NGCC 

generation and renewable energy measures that reduce CO2

emissions by reducing the quantity of fossil fuel-fired 

generation and associated emissions; and the adjustability of 

the goals based on the severability of the underlying building 

blocks. 

a. Rationale for a rate-based standardguidelines. First, the 

EPA sets an emission rate requirement for each source 

categorysubcategory by identifying the technology-specific 

reductions available under the building blocks. ItWe then 

givesgive each state the choice to apply the emission 

performance rates directly to the affected unitsEGUs within the 

state or provides the opportunity to use the statewide ratebased goal or the equivalent mass-based form translated from the 

emission performance rates for state plan purposes. The emission 

performance rates reflect the BSER, and the statewide rate-based 

goal orand statewide mass-based goal are alternative 

implementation metrics for realizing the emission performance 

rates at the aggregate affected fleet level for a state. 
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Stakeholders have expressed support for having the 

flexibility to choose from among the multiple options for 

crafting an implementation plan to realize the BSER. The EPA is 

providing emission performance rate-based standardsguidelines

that apply uniformly to technology categoriessubcategories

nationwide, and the EPA is providing corresponding state 

emission rate goals and state mass goals to maximizefurther 

enhance compliance flexibility for each state. This approach 

allows each state to adopt a plan that it considers optimal and 

is consistent with the state flexibility principle that is 

central to the EPA’s development of this program. 

b. Net vs. gross MWh. The second aspect noted above concerns 

the expression of the goals in terms of net energy output920 – 

that is, energy output encompassing net MWh of generation 

measured at the point of delivery to the transmission grid 

rather than gross MWh of generation measured at the EGU’s 

generator.921 The difference between net and gross generation is 

the electricity used at a plant to operate auxiliary equipment 

 

920 As discussed below in Section VIII on state plans, we are 

similarly determining that states choosing a rate-based form of 

emission performance level for their plans should establish a 

requirement for affected EGUs to report hourly net energy 

output. 

921 For some EGUs, total net or gross energy output also includes 

useful thermal output, in addition to either net or gross 

electric energy output. 
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such as fans, pumps, motors, and pollution control devices. 

Because improvements in the efficiency of these devices 

represent opportunities to reduce carbon intensity at existing 

affected EGUs that would not be captured in measurements of 

emissions per gross MWh, goals are expressed in terms of net 

generation. As noted by commenters, EGUs have familiarity and in 

some places already have in place the equipment necessary to 

collect and report hourly net generation, and we have determined 

that the reporting requirement would therefore not be 

burdensome..922

c. Output-weighted performance rates for all affected EGUs. 

This final rule provides an expression of the BSER that stops 

one step short ofas subcategory-specific emission performance 

rates rather than the state goals provided at proposal. Whereas 

the proposal also estimated the BSER impact on fossil steam and 

NGCC emissions and generation, it went one step further by 

averaging these two technology rates into a single rate for each 

state. Under this final rule, the EPA is identifying the fossil 

steam rate and the NGCC rate separately instead of only 

 

922 Specifically, commenters noted that while net generation is 

not reported to the EPA under 40 CFR Part 75, affected EGUs are 

generally required to report gross and net generation on a 

monthly basis to EIA through form 923 submittal.
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presenting them in a blended fashion at the state level.923 These 

two emission performance rates are the expression of the BSER 

for the final rule for affected EGUs located within the 

continentalcontiguous U.S. 

The modification from a blended emission rate in the 

proposed rule to a technologysubcategory-specific emission 

performance rate for affected EGU categories in the final rule 

was made in response to comments that technology subcategoryspecific emission rates were more analogous to prior 111(d) 

efforts and more consistent with the statute. The EPA received 

significant commentcomments suggesting a technology subcategoryspecific, source-specific requirement rate is consistent with 

past section 111(d) regulations. However, many commenters also 

supported the flexibility provided to states through a state 

goal metric provided at proposal. Therefore, the EPA does 

provide alternative statewide rate-based and mass-based 

compliance goals in the next section. 

 

923 However, as discussed here and in the next section, in order 

to provide maximum flexibility to states, the EPA averages these 

two emission rates together for each state using their adjusted 

2012 baseline generation share to arrive at a single statewide 

emission performance goal. The state has the option to comply 

with this statewide goal through a compliance pathway of its 

choice. This compliance pathway may or may not involve requiring 

its affected units to meet the emission performance rates. 
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The EPA’s main consideration has been to ensure that the 

expression of the BSER reflects opportunities to manage CO2

emissions by shifting generation among different types of 

affected EGUs. Both the performance rates in this final rule and 

the state goals at proposal rely on the adjusted emission rate 

metric to reflect that potential shifting. Specifically, because 

CO2 emission rates differ widely across the fleet of affected 

EGUs, and because transmission interconnections typically 

provide system operators with choices as to which EGU should be 

called upon to produce the next MWh of generation needed to meet 

demand, opportunities exist to manage utilization of high 

carbon-intensity EGUs based on the availability of less carbonintensive generating capacity. For states and generators, this 

means that CO2 emission reductions can be achieved by shifting 

generation from EGUs with higher CO2 emission rates, such as 

coal-fired EGUs, to EGUs with lower CO2 emission rates, such as 

NGCC units. Our analysis indicates that shifting generation 

among EGUs offers opportunities to achieve large amounts of CO2

emission reductions at reasonable costs. The realization of 

these opportunities can be reflected in an emission rate 

established in the form of an output-weighted-average emission 

rate where the weighting reflects the varying levels of 

replacement generation technologies. 
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d. Severability of building blocks. Section V above discusses 

the severability of the three building blocks upon which the CO2

emission performance rates are based. Because the building 

blocks can be implemented independently of one another and the 

emission performance rates reflect the sum of the emission 

reductions from all of the building blocks, if any of the 

building blocks is found to be an invalid basis for the “best 

system of emission reduction ... adequately demonstrated,” the 

rates would be adjusted to reflect the emissions reductions from 

the remaining building blocks. As notedThe sole exception, as 

described above, theis the application of building block 1 in 

isolation, which would not be implemented independently. The

performance rates and statewide goals that would result from any 

combination of the building blocks arecould be computed andusing 

the formulas and data included in the CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule and its 

appendices using the methodology described below and elaborated 

on in that TSD. 

D. Emission Performance Rate-Setting Equation and Computation 

Procedure

 The methodology used to compute the performance rates is 

summarized on a step-by-step basis below in section 3. The 

methodology is described in more detail in the CO2 Emission 
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Performance Rate and Goal Computation TSD for CPP Final Rule, 

which includes a numerical example illustrating the full 

procedure. The quantification of the building blocks used in the 

computation procedure is discussed in Section V above and in the 

Greenhouse Gas AbatementMitigation Measures TSD. 

1. Inventory of likely affected EGUs 

In order to calculate the source-categorysubcategoryspecific emission performance rates reflecting the BSER, the EPA 

first needed to develop a baseline inventory of likely affected 

EGUs in order to estimate the impact of the BSER. The EPA 

developed an inventory of likely coveredaffected units that were 

operating in 2012 or that began construction prior to January 8, 

2014 and that appeared to meet the final rule’s applicability 

criteria.924 This inventory does not constitute a final 

applicability determination, but best reflects the EPA’s 

estimate of units subject to the 111(d) applicability criteria 

as laid out in Section IV. The EPA identified a list of likely 

coveredaffected units at proposal comprised of approximately 

3,000 EGUs. The agency took comment on this list and has made a 

 

924 The EPA’s responsibility is to determine the BSER for all 

affected EGUs. Some of these under construction units may not 

enter operation until 2015 or later, but they are likely 

affected units and therefore appropriate to reflect in the 

baseline and corresponding subcategory-specific emission 

performance rates and state goals. 
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number of updates to the inventory in response to those comments 

and in regards to applicability criteria changes resulting from 

comments. However, the inventory does not reflect a final 

applicability determination, and where a unit’s status was 

unclear, the EPA generally treated the unit’s status in a manner 

consistent with the proposal and publically available reported 

data.925

Since the final rule’s applicability includes under 

construction units, the EPA also identified units that had not 

yet commenced operation inby the 2012 baseline period, but that 

commenced construction before January 8, 2014. The EPA received 

significant comment on the proposal’s sole use of the National 

Electric Energy Data System (NEEDS) to identify these under 

construction units. Commenters suggested that the EPA also 

 

925 The EPA notes that in some cases, it may not yet be possible 

to determine the status of an EGU as affected or not 

affectedunaffected without additional data. There are 

potentially some units excluded or included in the baseline that 

will ultimately have a different status following an 

applicability determination. However, these cases are limited, 

and the effect of any ultimate change in any given unit’s 

applicability status is unlikely to yield a significant change 

in the BSER computation at the regional level. The EPA does not 

believe that discrepancies between the inventory we assume here 

to be affected by the rule and the ultimate applicability status 

of any given unit would introduce any significant bias into the 

calculation of these uniform-technology rates.collective changes 

to the affected fleet inventory will not yield a bias in the 

BSER computation at the regional level. 
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utilize EIA and 2012 proposed unit-level files to help better 

identify under construction units. In some cases, NEEDS did not 

reflect units that had commenced construction. Therefore, the 

EPA updated its approach to identifying units that had commenced 

construction prior to January 8, 2014, but that had not 

commenced operation in 2012. In the final rule, the EPA uses EIA 

data, comments, as well as NEEDS data to identify these “under 

construction” units.926,927,928 

These units that were operating by 2012 along with those 

that had not commenced operation by 2012 but had commenced 

construction by January 8, 2014, reflect the EPA baseline 

inventory of likely affected EGUs. The CO2 Emission Performance 

Rate and Goal Computation TSD for CPP Final Rule explains the 

prime mover, capacity, and fuel criteria used to identify the 

likely affected EGUs.929 

 

926 The NEEDS database was also updated to reflect the latest 

data and commenter input on under construction units. 

927 For purposes of determining emission performance rates, the 

EPA classifies any unit that had begun construction prior to 

Jan. 8, 2014, but had not commenced operation by Dec. 31, 2011 

as “under construction”. SomeMany of these “under construction” 

units have commenced operation at some point during 2012 or 

prior to signature of this final rule. 

928 “Commence” and “construction” are defined in 40 CFR 60.2. 929 The baseline inventory relies on historical data and does not 

incorporate anticipated future retirements. Most commenters 

supported this treatment as they viewed those scheduled 

retirements (and corresponding emission reductions) as an 
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The EPA received significant comment that units that came 

online during the baseline year (e.g., 2012) should be treated 

as under construction rather than operating units in 2012 for 

purposes of estimating baseline values, because their 2012 

operation may be misrepresentative of anticipated future-year 

operation due to partial year operation in 2012. The EPA has 

made an adjustment to flag these units as having commenced 

operation during 2012 and treat them as under construction 

units, consistent with commenters’ suggestion; for BSER 

computational purposes, generation and emissions for these units 

are estimated based on a typicalrepresentative first full year

of operation for that technology class. 

2. Data year 

In the proposed rule, the EPA considered using a 

historical-year data set, or a projected-year data set, or a 

hybrid of the two as a starting point for applying the 

technology assumptions identified under BSER. The EPA proposed 

using 2012 data as it was the most recent data year for which 

complete data were available when the EPA undertook analysis for 

the proposed rule and it reflected actual performance at the 

state level. The EPA took comment on alternative data sets. In 

 

alternative compliance flexibility based on already scheduled 

reductions..
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particular, the EPA issued a NODA on October 30, 2014 (79 FR 

64543) in which itwe provided 2010 and 2011 historic data for 

consideration. 

The EPA received a significant number of comments 

supporting the use of historical data as the basis from which to 

quantify performance rates reflecting BSER. Some commenters 

supported the 2012 data year as the best reflection of the power 

fleet, and some suggested that the EPA use a different year or a 

historical average to control for data anomalies in 2012. 

Moreover, some commenters pointed out that using 2010, 2011, 

2012 data, or an average of the three would not address their 

concerns about recent year anomalies in hydro generation due to 

high snow pack. Some commenters also suggested the EPA use a 

baseline including years prior to 2012, not to increase 

representativeness of the power sector, but as a means of 

recognizing early action. 

In this final rule, the EPA is taking a hybridan approach 

to the baseline year where itwe still largely reliesrely on 

reported 2012 data as the best and most recent available data 

representing the power sector from which to apply the BSER, but 

also including targeted baseline adjustments to address 
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commenter concerns with 2012 data.930 Below, we explain why – at 

the nationwide level - 2012 data are preferable, more objective, 

and more accurate than a prior year, or an average of years, for 

informing the baseline. Then, we explain the adjustments that we 

are making to the 2012 data along with our rationale for such 

adjustments, in response to comments we received. 

Some commenters supported the EPA’s use of 2012 data to 

inform performance rates, and the EPA agrees that 2012 data with 

targeted adjustments, relative to other historical years, best 

reflects the power sector and best informs the performance rates 

that pertain to the BSER. The EPA believes that starting with 

2012 data is more accurate and better informs the BSER than an 

earlier historical year or historical multi-year average for the 

following reasons: 

1) Of the historical data fully available at the time the 

proposal analysis began, 2012 was the most recent and 

best reflects the power fleet. Approximately 43 GW of new 

capacity came online in 2010 and 2011. In other words, 

there was 43 GW of capacity online as of 2012 that had 

 

930 The EPA recognizes that more recent emissions and generation 

data have become available since 2012, but 2012 data constituted 

the most recent year for which full data was available at the 

time the EPA began its analysis for proposal. 
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not been in service at some point during the 2010-2011 

period. Likewise, approximately 1317 GW of capacity that 

operatedwere operable in 2010 and/or 2011 were retired 

prior to 2012.931 Using state-level, prior year data, 

either on its own, or as part of a multi-year baseline, 

is not as representative of the current power fleet as 

the 2012 data, which better reflects significant changes 

in power sector infrastructure. 

2) A three-year baseline would not address some of the 

substantive concerns raised by commenters. Many 

commenters pointed out that using a three-year baseline 

would not address their critical concern about variation 

in the hydrological cycle due to snow pack (particularly 

in the Northwest), because the snow pack was 

significantly above average in both 2011 and 2012. The 

EPA agrees with commenters that we can better address 

their baseline data concerns regarding an average hydro 

year by identifying those states with a significant share 

of hydro generation and variation in that hydro 

generation, and making targeted adjustments to those 

states’ affected fossil generation levels in order to 

 

931 EIA Form 860, 2012.
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reflect a more typical snow-pack year. This procedure is 

described in more detail below and in the Technical 

Support Documents. 

3) In addition to being, in the EPA’s view, a less 

representative baseline of the existing power fleet, a 

multi-year baseline would also likely entail complexity 

when determining how to average together yearly fleet 

data while appropriately accounting for fleet changes 

occurring during those years. The 2012 baseline starting 

point maximizes the EPA’s reliance on latest reported 

operating data and minimizes the need for fleet capacity 

adjustments. For instance, because of year-to-year fleet 

turnover, the averaging of a multiple baseline years 

would require additional assumptions in regards to which 

generation to consider from a fleet that is changing in a 

given state or region (or even where units are switching 

fuel sources such as a coal-to-gas conversion). 

4) Due to the region-based nature of derivingapproach to 

quantify building blocks and the BSER as subcategoryspecific emission performance rates, variations in unitlevel data do not significantly impact the calculation of 

emission performance rates. For instance, if one fossil 

unit is operating less in a given year due to an outage, 
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another fossil unit in the same region is generally 

operating more. Therefore, at the regional level, fossil 

generation doesand emissions do not vary to the same 

degree that unit-level data varies. Moreover, the 

variation at the regional- level that does exist in 2012 

relative to previous years is not necessarily 

randomunrepresentative variation, but illustrates trends 

in the power sector infrastructure that are desirable to 

capture for purposes of determining a representative year 

from which further improvements in CO2 emissions 

performance can be made. Because the EPA is moving from a 

state approach at proposal to a regional approach for 

calculating the expression of the BSER in this final 

rule, unit-level operational variation from year to year 

becomes even less relevant to the calculation of regional 

emission performance rates (i.e., an outage in a fossil 

unit in one region is likely to be offset by increased 

generation from another fossil unit in that same 

region)..

5) Some commenters suggested the EPA use an earlier baseline 

year as a means of recognizing early action. They noted 

that an earlier baseline would reflect a higher-emitting 

fleet and therefore when the same level of building block 
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MWhs are applied, they would result in a higher (i.e., 

less stringent) state goal. The EPA disagrees with this 

view for several reasons. First, the objective of 

selecting a baseline to inform BSER is to have one that 

best reflects the power sector and consequently the best 

system of emission reductions of which the power fleet is 

capable. Using an earlier baseline that “inflates” the 

starting point would undermine this objective, not serve 

it. Second, the EPA disagrees with the premise of this 

comment – that the baseline would change and building 

block potentials would stay the same. For instance, 

building block two is2 functions based on incremental 

generation potential (incremental generation = potential 

generation – actualbaseline generation). This incremental 

value would increase if an earlier baseline period was 

used that had less existing NGCC generation. 

6) Some commenters pointed out that the EPA relied on multiyear historical data in allowance allocation in previous 

rulemakings (e.g., CAIR and/or CSAPR allocations). 

However, that comparison is not relevant to the 

quantification of emission reduction potential under 

111(d). In those previous instances, the EPA was 

considering typical unit-level behavior for allowance 
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allocation purposes – not for determining the emission 

reduction requirements of the program. Those allowance 

allocation determinations were independent of and 

subsequent to the determination of emission reduction 

requirements in those rulemakings. 

7) The EPA received significant comment that 2012 was not a 

representative year for natural gas prices, and thus the 

EPA should use another year. The EPA disagrees with this 

comment, and does not view it as grounds for a change to 

the baseline period. While the EPA does recognize that 

Henry Hub natural gas prices averaged approximately 

$2.75/MMBTU were lower in 2012, which is lower than 

relative to previous years, this does not invalidate the 

suitability of the data year selection. The EPA’s 

objective in selecting a baseline is to identify 

potential reductions when BSER technologies are applied; 

year-to-year variation in market prices for natural gas 

does not frustrate this effort. For instance, a region 

may have generated only 5 MWh of NGCC generation in 2011 

when gas prices were higher, and 10 MWh of NGCC 

generation in 2012 when gas prices dropped. However, this 

does not change the outcome of the EPA quantification of 

the BSER, because the BSERbuilding block is based on the 
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emission reduction potential of the fleet. That potential 

(e.g., a fuller realization of the existing NGCC 

generation potential equivalent to 15 MWh) does not 

change regardless of the year used for baseline NGCC 

generation. Therefore, a different data year may change a 

baseline data point, but it would not change the ending 

pointtotal potential NGCC generation for quantifying the 

emission performance rates in these circumstances.

In summary, the EPA believes that continuing to rely on 

2012 data while incorporating select data adjustments as 

detailed below is not only a reasonable choice and adequately 

supported, but a more reliable and preferable starting point for 

determining the BSER requirements. 

3. Adjustments that the EPA made to the 2012 data 

The EPA made corrections to unit-level 2012 data based on 

commenter feedback. In addition, we also made some adjustments 

to 2012 data, not to address a correction, but to address a 

concern about the representativeness of the data. Although the 

EPA determined that the 2012 data year better informed its BSER 

determination than a preceding year or a multi-year average, 

commenters did identify some limitations that we are addressing 

through targeted adjustments. These are discussed below: 
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1) Adjustments to state-level data to account for annual 

variation in the hydrologic cycle as it relates to fossil 

generation. 

Hydropower plays a unique role in a handful of states in 

that 1) it is 1) a significant portion of their generation 

portfolio, 2) it varies on an annual basis, and 3) 2012 was 

an outlier year for snow-pack (meaning hydropower was above 

and fossil generation was below its historical average). 

The EPA notes that these three conditions are not present 

in other weather-based RE technologies like solar or 

wind.932 Therefore, no similar adjustment was needed to 

account for weather patterns with these technologies. 

Unlike market conditions (e.g., changes in natural gas 

prices) that may produce different generation profiles 

year-to-year but that do not change the overall generating 

potential of the fossil fuel-firedstate’s power fleet, 

variation in the hydrologic cycle does fundamentally change 

the generating potential of the fossil fuel-fired 

unitsstate’s power fleet in hydro-intensive states as they 

 

932 While solar and wind generation may vary on an hourly or daily 

basis, their annual generation profiles are subject to notably 

less variation compared to hydropower. The EPA’s calculation of 

the BSER relies on annual generation data, not on hourly or 

daily generation data.
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no longer have the same generating potential in an average 

year as they had in a “high hydro” year. The CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final 

Rule provides analysis and explains the adjustment that the 

EPA made to the state-level 2012 data for Alaska, Idaho, 

Maine, Montana, Oregon, South Dakota, and Washington to 

better reflect fossil generation in anlevels when hydro 

generation performed at its average yearlevel as observed

over a 1990-2012 baselinetimeframe. The EPA agrees with 

commenters that using a 2010-2012 baseline would not 

address the concern as 2011 was also an outlier year 

relative to historical snow-pack and hydro generation. 

2) Extended unit outages due to maintenance. 

Generally, because of the regional-level approach to 

calculate performance rates, the EPA does not believe that 

unit-level variations in operation influence the regional 

averagesubcategory-specific performance rates reflecting 

BSER purposes. For instance, as some units ramp down, and 

others ramp up to replace their load at the regional level, 

total fossil generation changes little due to these fossilfor-fossil substitutions. Unit-level variation does not 

inherently entail region-wide variation. 
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However, the EPA did receive comment that in limited cases, 

this could have a substantial impact on aan individual

state if it chooses to use a rate-based or mass-based 

statewide goal. Even though the EPA is calculating 

subcategory-specific performance rates that it believes are 

not affected by this type of unit-level variation, it still 

evaluated the possible impacts it may have when 

reconstituting converting to state goals in the next 

section. The EPA examined units nationwide with 2012 

outages to determine where an individual unit-level 

outagesoutage might yield a significant difference in state 

goal computation. When applying this test to all of the 

units informing the computation of the BSER, emission 

performance rates, and statewide goals, the EPA determined 

that the only unit with a 2012 outage that 1) significantly 

impacteddecreased its output relative to preceding and 

subsequent years, by 75 percent or more (signifying an 

outage), and 2) significantly impacted its could 

potentially impact the state’s goal as it constituted more 

than 10 percent of the state’s generation was the Sherco 

unitSherburne County Unit 3 in Minnesota. The EPA therefore 

adjusted this unit’s 2012 fossilstate’s baseline coal steam 

generation upwards (and made a corresponding adjustment to 
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lower NGCC generation assumed to occur in Minnesota in the 

adjusted baseline data) to reflect a more representative 

year for the state in which this 900 MW unit operates. 

3) Many commenters also noted that because the EPA uses annual 

data, 2012 was not representative for units coming online 

part way through the year. The EPA relies on annual data, 

so if a unit is underrepresented in a certain part of the 

year because it is not yet online, then another unit is 

likely over-represented as it is operating more than it 

otherwise would when the second unit commences operation. 

Therefore, the resulting state-level and regional-level 

aggregate annual generation level used in determining the 

BSER may be considered to be representative and there is 

not necessarily a need for any adjustment. 

However, the EPA recognizes that the over-represented and 

under-represented units do not necessarily fall within the 

same state, and therefore this potential difference in the 

state location of the affected units could have an impact 

when estimating appropriate statewide goals. To address 

this comment, the EPA adjusted the 2012 generation data for 

fossil units coming online during 2012 to represent an 

averagea more representative annual operating level for 

that type of unit, which reflecting its incremental impact 
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on generation and emissions. This effectively resulted in 

increased baseline emissions and generation assumed for 

those units beyond their reported partial-year operations 

in 2012. Conceptually, the assumption of full-year 

operation at units that came online partway through 2012 

could pair with an assumed reduction in the operation of 

other units somewhere in the same region. However, the EPA 

made no corresponding deduction to represent this likely 

decreased utilization at other affected units because it 

was impossible to determineproject the state location of 

such units. with certainty and the assumed utilization 

level was meant to reflect the incremental impact on the 

baseline. As a result, this data adjustment marginally 

inflatesincreases the total generation and emissions for 

units reporting in the 2012 baseline beyond the 2012 

reported levels. 

Additionally, as done in proposal, the EPA continued to 

identify under construction units that did not begin 

operation in 2012, but had commenced construction prior to 

January 8, 2014 and would commence operation sometime after 

2012. As described in the next section, the EPA estimated 

baseline generation and emissions for these units as they 

had no 2012 reported data. 
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In summary, this final rule continues to rely on the latest 

reported 2012 data as the foundation for quantifying the BSER. 

However, the EPA has made limited adjustments to the baseline , 

in addition to corrections identified by commenters, to the 2012 

data to address some of the relevant concerns raised by 

commenters. Therefore, the baseline is informed by 2012 data, 

but not limited to 2012 data.933

4. Equation 

4. ThisEquations 

In this section describeswe describe how we develop the 

equationequations used to determine the emission performance 

rates for fossil steam and NGCC units that express and implement 

BSER. More detailed information regarding rate computation, 

including example calculations, can be found in the CO2 Emission 

Performance Rate and Goal Computation TSD for CPP Final Rule, 

which is available in the docket for this action. The following 

paragraphsHere we first present the general principles we follow 

when developing equations to express the BSER; then, we

summarize the steps taken to adjust assemble baseline data to 

 

933 Updated unit-level data reflecting corrections identified by 

commenters to the underlying 2012 file are provided in Appendix 

1 of the CO2 Emission Performance Rate and Goal Computation TSD 

for CPP Final Rule. The adjustments made to the aggregate data 

to address representativeness concerns are provided in Appendix 

3.
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reflect 2012 baseline emissions and generation, and apply the 

building block potential and blocks that constitute the BSER to 

derive performance rates. The next section that will be used by 

states to implement BSER. Section VII then explains how these 

nationwide performance rates are reconstituted into a statewide 

goal metric similar to the proposal ifin order to allow a state 

desires(at its discretion) to use a statewide goal as a 

mechanism for demonstrating compliance at the aggregate state 

level in a state plan instead of, as an alternative to applying 

the emission performance rates to its affected EGUs. The EPA has 

translated these technology-specific emission rates into 

statewide goals that states may use to demonstrate aggregate 

compliance in section VII of the preamble and the CO2 Emission 

Performance Rate and Goal Computation TSD for Final Rule 

directly. 

When developing equations to implement BSER, we adhere to a 

number of basic principles. First, we ensure that the equations 

are consistent with the BSER itself, and in particular, reflect 

the redistribution of generation among fossil steam, NGCC and 

renewables embodied in building blocks 2 and 3. In doing this, 

we account for the interactions between building blocks in a way 

that is consistent with the assessment of incremental building 

block generation potential and the compliance framework for 
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Emission Reduction Credits (ERCs). In particular, we must ensure 

that each increment of building block 3 emission reduction 

potential is applied to either fossil steam or NGCC units but 

not both. The equations we develop must also take account of the 

dual status of existing NGCC units, which are simultaneously 

affected units and provide generation that is an element of the 

BSER itself. 

In addition, we are applying the BSER, as we have done in 

calculating other section 111(d) standards, to a defined 

population of existing affected sources, represented in this 

case by the generation of the source category in the 2012 

adjusted baseline. This provides an empirical historical 

baseline against which we define the performance rates and their 

state goal equivalents. In doing so, we must account for any 

offsetting increases in emissions that result from applying the 

BSER control measures, as we have done in setting other 

standards. For example, when determining BSER for particulate 

matter control, a number of pollution control devices (such as 

sorbent injection technologies) themselves create particulate 

matter. If the particulate matter created by these control 

devices were not appropriately accounted for when developing the 

standard intended to address the primary emissions of 

particulate, this could create an unreasonably stringent PM 
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standard. In the current context, this means recognizing that 

increasing NGCC capacity utilization in accordance with building 

block 2 both offsets higher emitting steam generation and 

increases emissions at the NGCC units themselves, which are also 

affected entities that must demonstrate compliance with the 

BSER. Thus, it is essential that we apply the building blocks in 

a way that avoids creating a level of stringency in the 

performance standards for affected EGUs that goes beyond what we 

have determined to be the BSER – while at the same time ensuring 

that equations apply the building blocks to generate performance 

standards that represent the full application of the BSER to the 

affected EGUs. 

Under section 111, the EPA adopts emission performance 

standards that are based on the BSER. The emission performance 

rates reflect our recognition of the value of giving sources the 

flexibility to adopt equivalent emissions reduction strategies 

and measures that for them may be preferable (in a specific 

circumstance) to the technologies and measures that we define as 

the BSER. An important function of the emission performance 

rates representing the BSER is to provide the flexibility needed 

to allow alternative compliance options, including the 

development of new technologies or the deployment of effective 

technologies outside of the BSER technologies. In the guidelines 
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we issued under section 111(d) for landfill gas, for example, we 

adopted the primary standard based on flaring of any captured 

landfill gas, but we also developed equations that led to an 

expression of the BSER that allowed for the alternative of 

capturing the gas and combusting it in an electrical generating 

unit. 

Finally, in deriving the emission performance rates, there 

are a number of considerations we took into account. First, it 

is important that the baseline from which the rates are derived 

be transparent and based on observable, historical data. Second, 

the emission performance rates must reflect the emission 

reductions achievable through the best system of emission 

reduction. Because the BSER includes shifting of emissions from 

higher-emitting to lower-emitting sources, state compliance 

frameworks will likely involve a combination of physical 

measures at the plant (where either rate or generation may be 

reduced) and some form of credit for lower-emitting generation 

(or demand side measures) outside of the plant. In this context, 

the emission performance rates must provide appropriate 

incentives for affected entities to achieve the emission 

reductions encompassed in the BSER, including through state 

plans that provide crediting for lower-emitting generation. 

Third, and as set forth below, we must account for the EPA’s 
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determination that pro rata implementation of building block 3 

is the best reflection of the potential for renewable energy to 

displace both fossil steam and NGCC, and the dual role of NGCC 

units as both affected sources and a BSER compliance technology. 

This set of considerations was central to the development 

of the BSER equations that the EPA describes next. They were 

particularly important for steps five through seven below which 

address building blocks 2 and 3, building blocks that have both 

significant overlap with each other and which impact steam and 

NGCC units in an integrated way. 

Step-by-Step Discussion of Equations 

Step one (compilation of baseline data). On a unit-level 

basis, the EPA obtained total annual quantities of CO2 emissions, 

net generation (MWh), and capacity (MW) from reported 2012 data 

for alllikely affected EGUs that had commenced operation prior 

to 2012.934 The EPA made limited changes to the historical unit-

 

934 EGUs whose capacity or fossil fuel combustion were 

insufficient to qualify them as “likely affected” EGUs were not 

included in the subcategory-specific rate and goal computations. 

Most simple cycle combustion turbines (CTs) were excluded on 

this basis at proposal, and all simple cycle CTs were excluded 

at final reflecting changes to the applicability language. 

IGCC’s were designated as “other” generation at proposal, but 

they are grouped with coal units for purposes the final rule

category-specific rates. Useful thermal output (UTO) was also 

translated to a MWh equivalent and included in state goals at 

proposal, resulting in more stringent rates for states with more 
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level data based on comments received at proposal. For each 

state and region, the agency aggregated the 2012 operating data 

for all coal-fired steam EGUs as one group, all oil- and gasfired steam EGUs as a second group, and all NGCC units as a 

third group. The EPA adjusted these state values upwards in a 

limited number of instances to reflect the hydrohydropower and 

unit outage concerns raised in comments and described above. Per 

the adjustmentsAs discussed above, the EPA first only aggregated 

the reported data for units that commenced operation prior to 

2012. For those “likely” affected units that commenced operation 

during 2012, the EPA treated that capacity consistent with its 

framework for “under construction” affected unitsunder 

construction affected units, which were added next. This was 

done in response to comments recognizing the fact that the year 

during which a unit commences operation may not have been 

representative of its potential generation and emissions. 

For the “under construction” units (i.e., those under 

construction prior to January 8, 2014 but which had not 

 

cogeneration sources, but UTO is not included in this final rule 

emission performance rate or state goal calculations as a result 

of comments regarding potentially adverse impacts on 

cogeneration units. and uncertainty of thermal load outputs. As 

described in the state plan section of the preamble, units may 

still quantify and convert UTO (i.e., taking credit for waste 

heat capture) when demonstrating compliance. See the 

applicability criteria described in Section IV.CD above. 
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commenced operation by December 31, 2011), the EPA estimated 

their incremental impact on the baseline generation and 

emissions using their capacity. The EPA assumed a 55 percent 

capacity factor for under construction NGCC units and a 60 

percent capacity factor for under construction fossil steam 

units, which are consistent with the values and methodology the 

EPA proposed for under construction units.935 These values are 

based oninformed by the average2012 capacity factors for other 

units in these technology classes coming online in the 2007-2011 

time frame.that recently commenced operation.936 Using these 

capacity factors along with the capacity for the units, the EPA 

 

935 The EPA notes that we did not identify any under construction 

coal units at proposal, but we are using a methodology in this 

final rule for newly categorized under construction coal units 

similar to our under construction assessment of NGCC at 

proposal.

936 The EPA received comment on the assumed 55 percent capacity 

factor for under construction NGCC EGUs. Some comments suggested 

the value was too large of an estimation for incremental 

generation as some of that 55 percent utilization would have a 

replacement impact on 2012 operating generation. Others 

suggested it should be larger as a particular planned under 

construction unit was anticipated to have a higher utilization 

rate. The EPA reviewed operating patterns of EGUs that came 

online, and determined a 55 percent and 60 percent capacity 

factor assumption for under construction NGCC and coal EGUs 

respectively are a reasonable estimate for informing the 

incremental emissions and generation from under construction 

units. It recognizes that some of these units may indeed operate 

at a higher utilization level, but also recognizes that some of 

the generation may have a replacement effect instead of an 

incremental one. 
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estimated an annual baseline generation value for these units. 

The agency then estimated annual baseline CO2 emissions for these 

under construction units using the average emission rate of 

generating units of the same technology in the state where the 

under construction unit is located. Where no generators of the 

same technology existed in a given state, the EPA used the 

national baseline average for that technology. This is similar 

to the adjustment made at proposal for under construction units, 

with the main difference being units that commenced operation in 

2012 are now also treated as “under construction” for baseline 

data purposes in the final rule. 

The estimated emissions and generation for under 

construction units were added to the 2012 reported emissions and 

generation data for the affected units that had already 

commenced operation prior to 2012 to derive an adjusted 

historichistorical baseline total for each state and region.that 

was reflective of all likely affected 111(d) sources.937 

Step two (aggregation to the regional level). The EPA took 

comment on applying building blocks at the regional level, and 

 

937 The EPA received some comments suggesting that under 

construction units should not be included in the quantification 

of BSER and/or rate calculations, and other comments supporting 

their inclusion. The EPA determined that including it was 

consistent with our responsibility under the 111(d) statute to 

define a Best System of Emission Reduction for existing units. 
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received significant comment supporting such an approach. 

Therefore, whereas the proposal aggregated the 2012baseline data 

to the state level, the final rule further aggregatesaggregated

it to the regional level prior to building block application. 

The regions reflect the Eastern, Western, and Texas 

Interconnections. The shift to a regional framework was based on 

comments suggesting that the EPA would better capture the 

interstate impacts of the building blocks and reflect the 

interconnected nature of the electric grid under a regional 

structure. The basis for the regions areis defined and discussed 

in Section V.A.3)..

Step three (presentationidentification of source category 

baseline emission rates). As discussed in the beginning of this 

section, the EPA took a technology-specific approach to setting 

standards.quantifying guidelines. Therefore, whereas the 

proposal first averaged the fossil steam rate and NGCC rate 

together before applying the building blocks and defining state 

goals, the final rule appliesapplied the building blocks at the 

regional level maintainingto give a separate fossil steam rate 

and a NGCC rate for each region. The starting point for 

calculating the technologysubcategory-specific emission 

performance rates iswas the adjusted baseline regional emission 

rate and generation valuerates for both fossil steam and NGCC 
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separatelyin the year 2012 with the modifications discussed 

above. 

Step four (application of building block one1). The 

totalbaseline CO2 emissions amount for the coal-fired steam EGU 

groupfleet in each region was reduced by 2.1, 2.3, and 4.3 

percent in the Western, Texas, and Eastern Interconnections 

respectively, while the coal generation level iswas held 

constant, reflecting the EPA’s assessment of the average 

opportunities in each region to reduce CO2 emission rates across 

the existing fleet of coal-fired steam EGUs through heat rate 

improvements that are technically achievable at a reasonable 

cost. The EPA then averagesaveraged together the region’s 

baseline oil- and natural gas-fired steam rate with its building 

block 1 adjusted coal steam rate to get a fossil steam rate post

-building block 1.938,939 

 

938 Building block 1 analysis acknowledges some variation in heat 

rate improvement potential at different units. The 

implementation of this building block reflects a heat rate 

improvement on average across a region’s coal fleet, not 

necessarily a heat rate improvement at every unit. 

939 Building block 1 analysis acknowledges some variation in heat 

rate improvement potential at different units. The 

implementation of this building block simply reflects a heat 

rate improvement on average across a region’s coal fleet, not 

necessarily a heat rate improvement at every unit. Baseline OG 

steam emissions are added to adjusted coal emissions and divided 

by baseline OG steam generation and baseline coal generation.
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 Step five (application of building block three3). At 

proposal, the EPA incorporated incremental RE MWhs (where 

incremental means the amount above the adjusted 2012 baseline)

by adding them to the denominator of the emission rate goal. In 

response to comments on this approach, the EPA issued a NODA 

discussing an alternative methodology of incorporating building 

block three3 in a manner more analogous to building block two2

treatment, where the incremental MWhs identified for the 

building block replace baseline fossil MWhs levels (and 

corresponding emissions) on a one-to-one basis. The EPA is 

adopting this replacement methodology for building block three3

in the final rule consistent with comments noting that such a 

computational procedure better reflects the reduction potential 

of that building block. 

InUnder this revised equation, part of building block three 

incremental RE potential and methodology, all of building block 

two2 incremental NGCC potential areand part of building block 3 

incremental RE potential were ultimately applied to replace 

higher-emitting fossil steam generation and emissions. Because 

incremental RE potential is lower emitting than, while the 

remaining building block two incremental 3 potential was applied 

to replace NGCC potential,generation and emissions. Commenters 

noted that under this approach building block three’s 
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Page 1041 of 2153

replacement impact is calculated 3 should be applied first when 

determining the impact on technology rates for each affected 

fossil-fuel category. Calculating building block three 

replacement impacts first is also consistent with comments, or

the EPA received noting that this step is necessary to ensure 

thatwould understate the EPA can subsequently calculate the full 

potential of building block 2 potentialby subtracting out some 

NGCC generation after the 75 percent utilization level of NGCC 

had been applied to replace higher-emitting fossil steam. The 

EPA agrees and calculated the building block 3 impacts first in 

developing the emission performance rates. 

FirstTo implement this, first, building block three3

replacement potential iswas identified for each region to arrive 

at a total amount of incremental zero-emitting generation hours 

available to replace fossil generation in the region. 

Next,Because renewable generation can replace both fossil steam 

and NGCC on the grid, the EPA determined that it was appropriate 

to apply these incremental zero -emitting generation hours are 

assumed to replace generation and associated emissions from each 

of the fossil steam and NGCC fleets in the region on a pro-rata 
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Page 1042 of 2153

basis in the following manner.940 The EPA determinesdetermined

the percent of fossil steam generation and the percent of NGCC 

generation of total affected fossil generation in each region’s 

baseline. ItWe then assignsassigned those percentages of the 

incremental zero-emitting MWhs to each of those technology 

source categories.941 The incremental zero-emitting generation 

assigned to thateach technology replacesreplaced the respective 

same amount of fossil generation from that technology’s baseline 

value. The numerator (emissions) is also effectively reduced at 

this stage by the amount of average CO2 emissions associated with 

the replaced fossil generation. 

Step six (application of building block two2). If the 

remaining generation level for the NGCC fleet in a region, 

taking into account the previous stepsstep’s replacement of NGCC 

 

940 The EPA took comment on a pro-rata or an intensity-based 

replacement approach. In this final rule, the EPA agrees with 

commenters that a pro-rata approach is a better reflection of 

the BSER. Incremental RE generation has, and is likely to 

continue, to replace both steam and gas turbine generation and 

the BSER captures this through a pro-rata distribution of 

identified building block 3 potential. 

941 For example, if 100 MWh of incremental zero emitting 

generation is available in a given region and that region had 70 

percent of its affected fossil generation coming from fossil 

steam units historicallyin the baseline and 30 percent from NGCC 

units – then 70 MWhs of the incremental zero-emitting generation 

are assumedapplied to replace baseline fossil steam generation 

and 30 MWhs are assumedapplied to replace baseline NGCC 

generation. 
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Page 1043 of 2153

generation, iswas less than 75 percent of the fleet’s potential 

summertime generating capacity (75 percent the potential 

capacity factor the EPA determined to represent the BSER), then 

the NGCC generation in the region iswas assumed to increase to 

levels equal to the lesser of 1) its potential at a 75 percent 

capacity factor942 or 2) a generation level above which there is 

no longer fossil steam generation remaining within the same 

region to replace. In other words, the regional NGCC capacity 

factor iswas only assumed to reach 75 percent if there iswas 

sufficient higher-emitting fossil steam generation that it could 

replace after step five. The incrementalincrease in NGCC 

generation replaces at this step compared to the post-building 

block 3 level was matched by an equal decrease in fossil steam 

generation in the region on a one-for-one basis. This 

replacement reduces the amount of fossil steam generation in the 

fossilreflecting the 1 for 1 MWh hour replacement. At this 

point, the generation for both steam and NGCC reflect the final 

distribution of generation between the subcategories after 

application of the building blocks. But the emission performance 

rates must account for CO2 emissions and generation from 

incremental gas and renewable generation that comprise building 

 

942 In early years, will be less than 75 percent due to building 

block 2 gradual deployment. 
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blocks 2 and 3, to reflect and enable the emission reductions 

achievable under the best system of emission reduction, and 

ensure that the shared implementation of the BSER by steam rate 

denominator as well as the amount of fossil steam emissions in 

the numerator.943

As explained in step seven, when determining the final 

fossil steam rate, this incremental NGCC generation and 

corresponding emissions are assigned to the fossil steam rate 

denominator and numerator respectively in a manner analogous to 

building block three. That is, the incrementaland NGCC 

generation that is replacing fossil steam generation is included 

in the fossil steam denominator and the incremental emissions 

are included in the numerator.944 is reflected in the rates. 

Step seven (arriving at the adjusted technology-specific 

rates for the region). In step four, the EPA calculated a 

regional fossil steam emission rate that reflected the building 

block 1 heat rate improvement. In steps five and six, it 

 

943 For purposes of determining the emission performance rates 

for fossil steam, incremental NGCC generation is defined as the 

final adjusted NGCC generation level minus the baseline level. 

944 Inclusion of the generation and emissions from incremental 

NGCC in the fossil steam rate is necessary to reflect the 

emission reductions associated with building block two. An 

unadjusted fossil steam rate on its own would not reflect any 

change as generation and emissions from replaced fossil steam 

would decrease proportionally when building block two is 

applied. 
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calculated an amount of remaining fossil steam generation and 

NGCC generation after building blocks two and three were 

applied. Step seven quantifies theaccounting for and 

facilitating the emission reductions achievable through the 

implementation of the best system of emission reduction). 

This step quantifies the aggregate emission changes 

associated with the emission rate improvement and generation 

replacement patterns described in steps four, five, and six to 

arrive at an adjusted fossil steam emission rate and an adjusted 

NGCC emission rate for each region reflectingthat will, as 

discussed above, (1) enable the implementation of all three 

building blocks., (2) be based on observable, concrete 

baselines, and (3) reflect the BSER. 

First, in developing the emission performance rates, the 

EPA had to answer the question of how to reflect the building 

blocks in the equations defining the rates in a manner that 

would enable the generation shifts that are essential components 

of the BSER. In the case of building block 3, the EPA 

accomplished this by incorporating the pro rata share of 

incremental (above baseline) zero emitting generation into the 

emission rates for each group of affected EGUs, thus ensuring 

that these EGUs would have to include a corresponding amount of 

zero-emitting generation in their compliance calculations, 
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Page 1046 of 2153

either through the acquisition of credits or through some other 

mechanism as determined by their state in its implementation 

plan. 

For building block 2, a similar mechanism is needed. 

Accordingly, a portion of the NGCC generation and emissions used 

to replace fossil steam must be averaged into the steam rate, 

analogous to what was done with building block 3. The EPA 

considered two approaches to define the quantity of NGCC 

generation and emissions to be averaged into the steam rate: (1) 

incremental NGCC generation after the implementation of building 

block 3 and (2) incremental NGCC generation from baseline 

levels. For the reasons below, the EPA has determined that the 

second approach better reflects the considerations discussed 

above. 

As discussed above, it is beneficial that the baseline from 

which emission performance rates are derived be transparent and 

based on observable historical data. The first approach, 

however, depends on the level of incremental NGCC generation 

relative to what is available after the implementation of 

building block 3. This level of NGCC generation (obtained after 

replacing baseline levels of generation with NGCC’s pro rata 

share of incremental RE generation) only exists as an 
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Page 1047 of 2153

intermediate step in the BSER calculation. It is not based on an 

observable or concrete level of generation. 

In Section VIII we discuss methods for creating ERCs for 

implementing shifting of generation from steam to NGCC, and this 

discussion illustrates the value of relying on an observable and 

concrete baseline. In that section we suggest that incentivizing 

and facilitating the purchase of ERCs as a compliance option for 

steam units could be implemented through the use of a factor 

that creates a fraction of an allowable credit for each hour 

that an NGCC operates. This factor is derived from the 

incremental generation of NGCC post-building block 2, relative 

to the baseline. While a different factor could be derived from 

the hypothetical intermediate level resulting from the pro rata 

application of zero emitting generation to NGCC in building 

block 3 (by transferring the full amount of NGCC emissions and 

generation replacing steam generation in building block 2), the 

EPA believes that grounding baselines in historical data (such 

as those used to derive the 2012 baseline) is both more 

transparent and easier to understand in a way that is more 

useful to states and utilities, in contrast to the practical 

challenges of relying on a calculated level that corresponds to 

an interim step within the emission performance rate 

calculation. As long as the crediting framework for creating 
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Page 1048 of 2153

ERCs is consistent with the amount of gas emissions and 

generation that is transferred to the coal rate, either the 

chosen option or the option of transferring the entire quantity 

of gas emissions and generation that occurred in step six to the 

coal rate would provide an incentive for the power market to 

implement the shift in generation from coal to gas.945

Also as discussed above, it is important that the 

compliance equations reflect the BSER pro rata allocation of 

renewable energy to fossil steam and NGCC generation. The first 

approach to define the quantity of NGCC generation and emission 

to be averaged into the steam rate would require the steam rate 

to take into account the total additional NGCC generation that 

results from the application of building block 3 before building 

block 2 has been applied. This approach would reflect in the 

compliance rate for steam units a greater share of the 

implementation of building block 3. Ensuring that emission 

performance rates for both steam and gas units reflect the 

 

945 The EPA recognizes that real world market dynamics will 

necessarily differ from the BSER assumptions, and has designed 

the emission guidelines to provide flexibility beyond the 

emission reduction opportunities identified in the BSER. The 

essential criteria, however, are that the emission rates and 

crediting framework are consistent with the BSER and provide the 

incentives needed to facilitate the emission reduction measures 

reflected in the BSER and together produce an achievable 

compliance framework for sources. 
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Page 1049 of 2153

emission reduction potential of building block 3 is integral to 

the building block 3 methodology and also recognizes that 

application of building block 3 on a pro-rata basis was intended 

to achieve emission reductions from both NGCC and fossil steam 

commensurate with their emissions reduction opportunities. 

If the EPA were to use the increment of NGCC emissions and 

generation derived at the intermediary step after the 

application of building block 3, rather than the increment 

relative to the 2012 baseline, the effect would be to largely 

assign to fossil steam the building block 3 generation shift 

apportioned to NGCC. That, in turn, would have undermined the 

fact that building block 3 was determined to be a BSER measure 

applicable to the entire source category, comprising NGCC as 

well as fossil steam, and would have conflicted with the 

preceding steps we are taking to develop the equations. Instead, 

by using only the incremental NGCC generation relative to the 

baseline, the EPA has ensured that the logic behind the pro rata 

displacement of fossil generation by RE generation is reflected 

in the emission rates. Having established the appropriate way to 

measure the amount of incremental gas generation placed in the 

fossil steam rate, the EPA is able to calculate the subcategoryspecific emission performance rates. For the numerator of the 

fossil steam rate, the EPA multipliesmultiplied the remaining 
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Page 1050 of 2153

fossil steam generation (post Step-step six) by the fossil steam 

rate reflecting the heat rate improvement from building block 1 

(Stepstep four). ItWe then addsadded in the emissions associated 

with the incremental NGCC generation from building block 2 (step 

six) by multiplying the incremental NGCC generation (deltaas 

discussed above (difference between the baseline NGCC generation 

level and post -step six NGCC generation) by the baseline NGCC 

rate for that region.946 This constitutes the numerator of the 

fossil steam emission rate. 

For the fossil steam denominator, the EPA addsadded the 

remaining fossil steam generation (post -step six), the 

incremental NGCC generation defined above, and the amount of 

zero emitting building block three3 MWhs assignedapportioned to 

replace fossil steam generation in the region (step five). 

Dividing the fossil steam numerator described above intoby this 

fossil steam denominator resultsresulted in a regional adjusted 

fossil steam rate reflecting the three building blocks.

For the NGCC uniform technologyperformance rate, the EPA 

calculatescalculated a numerator in a similar manner. First, it 

 

946 See CO2 Emission Performance Rate and Goal Computation TSD for 

CPP Final Rule for an illustration of this step. The EPA defined 

the “incremental NGCC generation” in this step in a manner 

consistent with its measurement and use described in section 

VIII of this preamble. 
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Page 1051 of 2153

takeswe took the remaining NGCC generation (post step six) and 

multipliesmultiplied it by the regional baseline NGCC rate to 

calculate the total emissions in the numerator. For the 

denominator, the EPA added the remaining NGCC generation (post 

step six) to the amount of zero-emitting building block three3

generation assigned to that technology in step five. Dividing 

the emissions intoby this total generation value (inclusive of 

the RE generation assignedapportioned to replace NGCC) 

providesprovided a regional adjusted NGCC rate.947 

Step eight (determining the nationwide 

technologysubcategory-specific emission performance rate). 

Following step seven, we evaluated the resulting adjusted 

fossil steam rates and NGCC rates for each region are evaluated. 

Theand identified the highest (least stringent) emission rate 

among the three regions for each technology category is 

 

947 See CO2 Emission Performance Rate and Goal Computation TSD for 

CPP Final Rule for an illustration of this step. We note that 

the entire NGCC generation level (inclusive of the amount 

assigned to the fossil steam rate) expected post building block 

application is included in the NGCC rate calculation. Including 

the entire NGCC generation in the NGCC rate recognizes the 

simultaneous compliance responsibility of affected NGCC units 

while the fossil steam rate recognizes its mitigation potential 

through incorporation of the incremental NGCC generation 

component. Failing to do so would result in a NGCC rate lower 

than that expected after full implementation of the building 

blocks and create a compliance inconsistency when reporting all 

generation.
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identified among the three regions.. This becomes the nationwide 

emission performance rate for that technology class. This 

ensures that the same rates are applied to facilities in each 

region and that these rates are achievable by facilities in all 

three regions. 

Finally, the EPA repeatsrepeated steps four through eight 

for each year 2022-2030.948 The resulting annual rates vary 

because the amount of building block two2 and three3 potential 

in each year varies. The rates for years 2022-2029 arewere

averaged together to calculate an interim rate, and the 2030 

value becomes the final emission performance rate for that year 

forward. 

 It bears emphasis that the procedure described above was 

used only to determine emission performance rates, and the 

particular data inputs used in the procedure are not intended to 

represent specific requirements that would apply to any 

individual EGU or to the collection of EGUs in any state. The 

specific requirements applicable to individual EGUs, to the EGUs 

 

948 At proposal, the EPA repeated this step over a 10 year period. 

The building blocks and corresponding BSER emission rates 

increased for ten consecutive years (2020-2029) in the EPA’s 

rate calculation. In this final rule, the EPA has maintained the 

same 2030 compliance period for final rates but adjusted the 

start date to 2022 based on comments. Therefore, the deployment 

of building blocks is spread over a nine year period (2022-2030) 

instead of the proposed 10 year period. 
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in a given state collectively, or to other affected entities in 

the state, would be based on the emission standards established 

through that state’s plan. The details of how states could 

demonstrate compliance with the emission performance rates or 

statewide goals through different state plan approaches that 

recognize emission reductions achieved through all the building 

blocks are discussed further in section VIII on state plans. 

 Finally, the procedures and assumptions in the equation to 

calculate emission performance rates are not intended to reflect 

a compliance scenario in a future year, but rather reflect a 

representative year in which the building blocks are applied. 

The power sector fleet will continue to turn over, and in some 

cases has already experienced turnover beyond the baseline 

period. However, while the system’s fleet may change, the EPA 

believes this turnover will only further promote the feasibility 

of the emission performance rates. Fleet turnover has trended 

towards, and is expected to continue to trend towards, loweremitting generation sources that will make reductions more 

readily available. 

 The CO2 emission performance rates described in Table 8 

above are relevant for the continental U.S. jurisdictions. 

Affected EGUs in Alaska, Hawaii, Guam, and Puerto Rico are not 

subject to these rates. Because the continental U.S. (CONUS) 
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Page 1054 of 2153

BSER relies on a region-wide determination of potential 

reductions, the non-continental United States jurisdictions with 

affected EGUs are not subject to this regional BSER framework. 

For these non-CONUS jurisdictions, the EPA developed a blended 

emission rate similar to proposal (but incorporating updated 

building block assumptions) and described in the technical 

support document entitled “CO2 Emission Performance Rate and Goal 

Computation TSD for Final Rule,” which is available in the 

docket. 

VII. StatewideState-Specific CO2 Emission Performance Goals 

A. Overview 

In section VI of this preamble, the EPA provides the 

methodology for computing source categorysubcategory-specific CO2

emission performance rates, based on the BSER. The subcategoryspecific CO2 emission performance rates are the quantitative 

expression of the BSER as determined by the EPA. In this 

section, we provide state rate-based goals and mass-based goals 

that can be used in the alternative, by states, as an equivalent 

quantitative expression of the BSER in establishing standards of 

performance for affected EGUs in state plans. In this section, 

the EPA also describes reasons for providing state-specific 

rate-based goals and mass-based goals equivalent to the emission 

performance rates, supported by the many requests from 
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commenters for the provision of these alternative expressions of 

the BSER established by the EPA. We further ensure this 

equivalence, and therefore reflection of the BSER, by requiring 

that rate-based state goals and mass-based state goals fully 

implement the BSER, including by ensuring that affected EGUs 

operating under mass-based emission standards are not incented 

by dint of the mass-emissions constraint to shift generation to 

unaffected fossil fuel-fired sources to an extent that deviates 

from, or negates, the implementation of the BSER. 

The EPA is reconstituting the emission performance rates 

discussed in section VI into statewide CO2 emission performance 

goals for each state for the purpose of facilitating states’ 

development of state plans encompassing maximum flexibilities in 

implementing the BSER. This state-specific goal is not a 

compliance requirement, but rather an alternative yet equivalent 

expression of the BSER that the state may choose to use to 

establish emission standards for its affected EGUs. The state 

goal is the equivalent of the technology-specific CO2 emission 

performance rates and represents the equivalent of the state’s 

applying the emission performance rates directly to its affected 

EGUs in the form of standards of performance. As discussed 

further in section VIII on state plans, the states are charged 

with setting emission standards for the affected EGUs in their 
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respective jurisdictions such that the affected EGUs operating 

under those standards together satisfy the requirements of the 

final emission guidelines and statute by meeting the emission 

performance rates or equivalent statewide emission performance 

goals, and thereby meet emission standards that reflect the 

BSER. 

In the June 2014 proposal, the EPA proposed a set of statespecific emission rate-based CO2 goals (in lbs of CO2 per MWh of 

electricity generated). In addition, the EPA issuedproposed

emission rate-based CO2 goals for areas of Indian country and 

U.S. territories with affected EGUs in a supplemental proposal 

on November 4, 2014. To provide flexibility to states, 

territories, tribes and implementing authorities, the proposals 

authorized each implementing authority to translate the form of 

the goal to a mass-based form (i.e., goals expressed in terms of 

total tons of CO2 per year from affected EGUs), as long as the 

translated goal achieves thewas equivalent in stringency.to the 

rate-based goal. Upon issuance of the proposed rule, the EPA 

continued the extensive outreach effort to stakeholders and 

members of the public that the EPA had engaged in for many 

months preceding the proposal. We also issued a notice of data 

availability (79 FR 67406, November 13, 2014) and technical 

support document (Docket ID no.:: EPA-HQ-OAR-2013-0602-22187) to 
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further clarify potential methods for the translation to a massbased equivalent. The outreach provided additional opportunities 

for all jurisdictions with affected EGUs – both individually and 

in regional groups – as well as numerous industry groups and 

non-governmental organizations, to meet with the EPA and ask 

clarifying questions about, and give initial reactions to, the 

proposed components, requirements and timing of the rulemaking. 

As a result of the outreach and notice of data availability, the 

EPA received informed substantive comments for the EPA to 

consider for the final rule. 

Numerous commenters encouraged and supported the EPAEPA’s 

efforts to allow states the maximum possible degree of 

flexibility in developing plans for their affected EGUs, 

whethereither as a mass-based or rate-based CO2 goal is chosen. 

States and other stakeholders supported the option to translate 

rate-based goals to mass-based goals infor state plans and 

requested a simple and transparent method for determining massbased statewide CO2 goals that are equivalent to statewide ratebased CO2 goals. and thus reflective of the BSER. We received 

substantivesubstantial comments on the potential methodologies 

for the translation of rate-based goals to mass-based goals. 

Several commenters requested that the EPA provide the 

translation to a statewide mass-based goals directly while 
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others requested flexibility to translate to mass using a 

variety of methodologies and tools. The In the context of these 

comments, the EPA is providinghas considered the appropriateness 

of rate-based and mass-based statewide goals in this final rule 

in place of having states determine the mass values themselves. 

Usingas an expression of BSER and their equivalence to the 

quantitative expression of BSER through the two CO2 emission 

performance rates. 

Based on the comments received, the EPA is providing a 

straightforward and translation methodology from the CO2 emission 

performance rates to yield statewide rate-based and mass-based 

CO2 emission performance goals; section described in this 

section. The EPA is providing state mass-based goals in this 

final rule in place of having states determine the mass 

themselves. The mass-based goals are the result of a 

mathematical derivation that provides goals that are an 

equivalent expression of the BSER. Section VIII below discusses 

mechanisms for states to plan for and demonstrate achievement of 

the statewide CO2 emission performance goals. 

The EPA is aggregating the performance rates discussed in 

section VI into statewide CO2 emission performance goals for each 

state to facilitate states’ efforts to formulate compliance 

plans encompassing maximum flexibilities. This statewide goal is 
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not a compliance requirement, but rather an option that the 

state may choose to use to demonstrate that its affected fleet 

is complying with the technology-specific emission performance 

rates on average if a state chooses not to apply the performance 

rates to its affected EGUs directly. As discussed further in 

section VIII on state plans, the states, in turn, are charged 

with setting specific emission standards for the EGUs in their 

respective jurisdictions such that the EGUs operating under 

those standards together satisfy the requirements of the final 

emission guidelines as expressed by the emission performance 

rates or statewide emission performance goals. 

CAA section 111(d) requires states to submit a plan that 

establishes standards of performance for affected EGUs that 

implement the BSER. States meet the statutory requirements of 

CAA section 111(d) and the requirements of the final emission 

guidelines by submitting emission standards for affected EGUs 

that meet the performance rates, which reflect the application 

of the BSER as determined by the EPA. Therefore, as a first step 

for states that choose to submit plans that meet the rate-based 

or mass-based goals, the goals must be determined to have 

equivalence as an application of the BSER. For the rate-based 

and mass-based state goals provided here, this equivalence is 

evident in the mathematical derivation of the goals, as is 
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described in sections VII.B and VII.C below. 

Further (as described in section VIII.J), the state plan 

must demonstrate that it has measures in place to ensure that 

any alternative to the performance rates (i.e., rate-based or 

mass-based state goals that it uses to establish standards of 

performance) does not result in affected EGUs’ failing to 

implement either the BSER measure themselves or alternative 

methods of compliance with emission standards that achieve 

equivalent reductions in emissions or carbon intensity. The EPA 

has identified one way in which affected EGUs could fail to 

meet, at a minimum, of the emission performance levels that 

would result from implementing the BSER, which state plans must 

do. 

Specifically, the EPA has determined that the three 

building blocks are the BSER, including shifting generation from 

an affected EGU to a lower-emitting affected EGU or to a nonemitting EGU and that states are required to establish standards 

of performance that require affected EGUs to achieve, at a 

minimum, the emission performance levels that reflect the BSER 

(recognizing that affected sources may choose from a range of 

equivalent actions (e.g., undertaking the measures included in 

the building blocks, shifting generation to low-emitting or 

zero-emitting resources not included in the building blocks or 
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achieving demand-side EE or transmission efficiency – either 

through operational undertakings, direct investment or emissions 

trading). Substantial shifting of generation from affected EGUs 

to new fossil fuel-fired EGUs, such as new NGCC units, 

represents a deviation from implementing the BSER or its 

compliance equivalent. 

Since the two subcategory-specific emission performance 

rates represent the BSER, states that established standards of 

performance at or below those rates, by definition, would be 

implementing state plans that created no risk that affected EGUs 

would shift generation to new fossil-fired EGUs to an extent 

that would deviate from the BSER. Similarly, the EPA has 

determined that states using rate-based goals as the foundation 

for plans implementing the BSER are unlikely to foster 

generation shifts to new fossil fuel-fired sources to an extent 

that would deviate from the BSER. In contrast, however, EPA 

analysis has identified a concern that a mass-based state plan 

that failed to include appropriate measures to address leakage 

could result in failure to achieve emission performance levels 

consistent with the BSER.949 Section VII.B. describes how the 

form of the rate-based state goals minimizes the risk of 

 

949 See Chapter 3 of the Regulatory Impact Analysis for more 

information on this analysis, which is available in the docket. 
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generation shifts to new fossil fuel-fired sources, or 

“leakage,” by providing affected EGUs with a sufficient 

incentive to run, similar to the performance rates. Section 

VII.D. discusses how there is a potential for leakage under 

mass-based state goals because affected EGUs are incented to 

operate in a manner – in particular, by shifting generation to 

new NGCC units (as opposed to shifting generation as 

contemplated by the BSER or undertaking equivalent alternative 

compliance actions) –that would result in negating the 

equivalence with the emission performance rates and thus the 

BSER, and specifies that requirements are needed in mass-based 

implementation to assure those incentives are realigned.950 

B. Reconstituting Statewide Rate-based CO2 Emission Performance 

Goals from the Source CategorySubcategory-Specific Emission 

Performance Rates 

In order to provide states flexibility for planning 

purposes, the EPA is providing a state-specific averaging of the 

technologysubcategory-specific emission performance rates to 

determine a statewide goal similar to the state goal metric 

issued at proposal.. While the emission performance rates 

 

950 The specific mass-based plan requirements are explained in 

detail in section VIII.J. 
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reflect the standardsquantification of performance based on the 

BSER and embody the reductions estimated under building blocks 

1, 2, and 3, the statewidestate goals reflect onean equivalent

approach through which states may choose to adopt and implement 

those standards. subcategory-specific performance rates. 

The EPA quantified the potential reductions of the BSER in 

the subcategory-specific emission performance rates established 

in section VI. These rates themselves reflect the reduction 

potential expected in emission rates under the BSER for each 

year from 2022 to 2030. To establish state goals, the EPA 

applied these rates to the baseline generation levels to 

estimate the affected fleet emission rate that would occur if 

all affected EGUs in the fleet met the subcategory-specific 

rates. This step respects the flexibility of sources to meet the 

rates in any manner that they see fit (e.g., on-site abatement 

technology, fuel switching, co-firing, credit purchase, etc.), 

and does not limit them to their building block assumptions. For 

example, the EPA derived the statewide rate-based CO2 emission 

performance goals for 2030 by multiplying the fossil steam 

emission performance rate for 2030 by the baseline fossil steam 

generation in a state and multiplying the NGCC emission 

performance rate for 2030 by the baseline NGCC generation in a 

state. The resulting emissions for fossil steam and NGCC are 
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then added together for each state. This emission total is 

divided intoby that state’s baseline generation values from the 

likely affected unitsEGUs in order to develop a state’s ratebased CO2 emission performance goal for 2030. This blended rate 

reflects the aggregatecollective emission rate a state may 

expect to achieve when its fleet is baseline fleet of likely 

affected EGUs continues to operate at baseline levels while 

meeting its technology-specific emission performance 

rates.subcategory-specific emission performance rates reflecting 

the BSER. The EPA believes that using the adjusted 2012 baseline 

is the most appropriate way to combine the rates. First, as 

explained in Section VI, the EPA believes there are significant 

advantages to using real world data to set a baseline rather 

than using projected data. The adjusted 2012 data is the logical 

starting point because it is the data that all of the emission 

performance rates (discussed in Section VI) are based 

upon. Furthermore, it is clear that generation shifts as 

projected under the BSER are not the appropriate baseline. The 

emission performance rates already factor in the BSER 

assumptions about changes in generation (e.g., implementation of 

building block 2 significantly lowers the emission performance 

rate for fossil-steam units). If, on top of that, changes in 

generation were factored into the calculation of a combined 
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rate, those changes in generation would be factored into the 

combined rate twice (once when calculating the individual 

emission performance rates and a second time, when incorporating 

those rates into a combined state rate). 

This step is repeated for yearseach year from 2022-2029 

using the emission performance rates calculated for each of 

those years in the previous section. The resulting state 

emission rates for each year 2022-2029 are then averaged 

together to determine the state’sThe EPA also repeats this step 

for the interim rate-based emission performance goal. This 

results in state goal using the interim and final statewide goal 

values unique to each state’s historical blend of fossil steam 

and NGCC generation. 

subcategory rates. The EPA alsothen averages together the 

annual amounts in increments of 3 years, 3 years, and 2 years 

for 2022-2024, 2025-2027, and 2028-2029 to estimate emission 

rate averages for those periods that can provide one 

illustrative pathway for states to consider in meeting their 

interim goals. These three3- and two 2-year incrementsincrement

are not regulatory guidelines or equivalents for interim goals, 

but rather benchmarks for demonstrating plan performance as 

discussed in Section VIII.F illustrative of a type ofpotential
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gradual reduction compliance strategy that states may use to 

reach their interim and final statewide goalsstategoals. 

The EPA is providingAs described in the steps above, the 

statewide goals represent an equivalent arithmetic combination 

of the subcategory-specific emission performance rates, weighted 

by the historical baseline generation levels upon which the BSER 

is premised. In particular, as discussed above, the method for 

deriving these goals assures equivalent flexibility by applying 

the CO2 emission performance rates to the baseline levels, which 

respects the flexibility of affected EGUs to meet the rates in 

whatever way they wish. This corresponding treatment of affected 

EGUs based on the adjusted 2012 baseline ensures sufficient 

incentive to affected existing EGUs to generate and thus avoid 

leakage, similar to the CO2 emission performance rates (this is 

further discussed in section VII.D below). Consequently, the 

statewide goals are equivalent to the CO2 emission performance 

rates and are thus an equivalent expression of the BSER. The 

rate-based statewide goals are provided below in Table 12. 

C. Quantifying Mass-based CO2 Emission Performance Goals from the 

Statewide Rate-based CO2 Emission Performance Goals 

The EPA is also establishing mass-based statewide CO2

emission performance goals for each state, which are provided 

below. The in Table 12. For state plans choosing to meet a mass-
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based goal, such a goal must be equivalent to the CO2 emission 

performance rates in their application of the BSER, as required 

by the statute and the final emission guidelines. In the 

following discussion we describe the mathematical calculations 

that provide an equivalent expression of the BSER. In evaluating 

the equivalence of the form of mass goals, the EPA must also 

recognize the impact that the form of the standard has on the 

relative incentives that the implementation of these goals 

provides to affected and unaffected EGUs. This section specifies 

how we have established a quantitative basis for mass goals that 

is equivalent to CO2 emission performance rates. The next section 

(section VII.D) specifies how we require state plans to ensure 

equivalence to the CO2 emission performance rates through certain 

requirements that realign the potential difference in incentives 

provided to affected and unaffected EGUs to generate under a 

mass-based implementation compared to a rate-based 

implementation that could result in leakage. 

The starting place for quantifying mass-based statewide CO2

emission performance goals are based on the tonnage totals 

fromis the emission amounts directly represented in the 

numerator of the statewide rate-based CO2 emission performance 

goals. These mass levels are then adjusted to account for the 

ability of affected EGUs to increase utilization under Each 
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state-specific emission amount is the product of the fossil 

steam emission performance rate and historical fossil steam 

generation, added to the product of the NGCC emission 

performance rate and historical NGCC generation. The resulting 

emission amounts for each state represent the emissions 

associated with rate-based compliance by engaging in at 

historical generation levels. 

However, under a rate-based state plan, all affected EGUs 

have the opportunity to increase utilization, provided that 

sufficient emission reduction strategies thatmeasures are in 

excess of what isavailable to maintain the necessary to 

demonstrate compliance if affected EGUs choose to replace their 

own generation.ratio of emissions to generation as quantified by 

the subcategory-specific emission performance rates. Due to the 

nature of the emission performance rate methodology, which 

selects the highest regional valueof the three interconnectionbased values for each source category as the CO2 emission 

performance rate, there are cost-effective emission reduction 

lower-emitting generation opportunities originally quantified 

under the building blocks 2 and 3 that wereare not ultimately 

captured in the emission performance rates. necessary for 

affected EGUs in the Western and Texas interconnections to 

demonstrate compliance at historical generation levels. The EPA 
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recognizes that these cost-effectivelower-emitting generation

opportunities are available to affected EGUs in a rate-based 

compliance settingat a national level as a means of increasing 

utilization to increase their own output (and, as a result, 

their own emissions) while maintaining the relevant emission 

performance rate. To afford affected EGUs subject to a massbased goal similar compliance flexibility under massas EGUs 

subject to a rate-based compliancegoal, the EPA has 

translatedquantified the emissions associated with the potential 

realization of these excess emission reductionlower-emitting 

generation opportunities (which were quantified at the regional 

level) to a tonnage basis and thenand incorporated those 

additional tons into each state’s mass-based goal on the .951

Because the derivation of these mass-based goals respects the 

arithmetic of the subcategory-specific emission performance 

rates and the flexibility of affected EGUs to achieve those 

rates while utilizing up to the full potential quantified in the 

building blocks, the derivation of these mass-based state goals 

offers an equivalent expression of BSER in mass form. 

 

951 For more detail on this methodology, please refer to the CO2

Emission Performance Rate and Goal Computation TSD for CPP Final 

Rule, which is available in the docket. 
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The mass goals for existing sources are presented in Table 

13. Although their derivation is equivalent to the subcategoryspecific emission performance rates, in order to maintain this 

equivalence in the establishment of emission standards in state 

plans mass goals must be implemented in combination with 

requirements that align the incentives provided to affected and 

unaffected EGUs, specifically in order to prevent leakage. 

D. Addressing Potential Leakage in Determining the Equivalence 

of State-Specific CO2 Emission Performance Goals 

As described in section VI, the subcategory-specific 

emission performance rates reflect the BSER as determined by the 

EPA. This final rule allows states to establish emission 

standards that meet either rate-based or mass-based state goals. 

As stated above, rate-based state goals were published in the 

proposed rule, and commenters not only supported having the 

flexibility to use rate-based goals or mass-based goals as part 

of state plans, but also requested that the EPA include massbased goals in this final rule. But to ensure the equivalence of 

mass-based state goals, we must consider how the form of the 

goal affects its implementation and how the incentives it 

provides to affected EGUs on the interstate grid affect whether 

or not the BSER is fully implemented. 
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Because of the integrated nature of the utility power 

sector, the form of the emission performance requirements for 

existing sources may ultimately impact the relative incentives 

to generate and emit at affected EGUs as opposed to shifting 

generation to new sources, with potential implications for 

whether a given set of standards of performance is, at a 

minimum, consistent with the BSER, in the context of overall 

emissions from the sector. In this context, we, again, define as 

“leakage” the potential of an alternative form of implementation 

of the BSER (e.g., the rate-based and mass-based state goals) to 

create a larger incentive for affected EGUs to shift generation 

to new fossil fuel-fired EGUs relative to what would occur when 

the implementation of the BSER took the form of standards of 

performance incorporating the subcategory-specific emission 

performance rates representing the BSER. In the proposal, the 

EPA recognized that the statutory construction regarding the 

BSER is to reduce emissions, which can be achieved through 

shifts of generation. Movement of generation between and among 

sources is needed to produce overall reductions, particularly 

movement from higher-emitting affected EGUs to lower-emitting 

affected EGUs, and from all affected EGUs to zero-emitting RE. 

In all of these cases, the fossil sources involved in these 
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generation shifts are subject to obligations under this final 

rule.952

However, leakage, where shifts in generation to unaffected 

fossil fuel-fired sources result in increased emissions, 

relative to what would have happened had generation shifts 

consistent with the BSER occurred, is contrary to this 

construction. Therefore, if the form of the standard does not 

address leakage or incents the kinds of generation shifts that 

we identify as leakage, the states must otherwise address 

leakage in order to ensure that the standards of performance 

applied to the affected EGUs are, in the aggregate, at least 

equivalent with the emission performance rates, and therefore 

appropriately reflect the BSER as required by the statute. 

Commenters noted that shifting generation and emissions from 

existing sources to new sources undermined the intent of this 

rule and the overall emission reduction goals, and that 

 

952 The final rule includes state plan conditions to prevent 

perverse incentives that could otherwise result in greater 

overall emissions when generation shifts across affected EGUs. 

For example, states that wish to engage in rate-based trading 

through an emission standards plan type must adopt plans 

designed to achieve either a common rate-based state goal or the 

subcategory-specific emission performance rates (see section 

VIII.L). Such a state plan condition avoids encouraging 

generation to shift from a state with a relatively lower state 

goal to a state with a relatively higher state goal solely as a 

response to the form of CPP implementation. 
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requiring states to address leakage is consistent with the the 

obligation that states establish standards of performance that, 

in the aggregate, at a minimum, reflect the BSER for affected 

EGUs operating in the interconnected electricity sector. 

This section specifically addresses the need for state 

plans designed to achieve either rate- or mass-based state goals 

to ensure that their plans succeed in implementing standards of 

performance that reflect the BSER by minimizing the difference 

in incentives provided to affected EGUs and new sources to 

generate in order to maintain equivalent emission performance 

with the CO2 emission performance rates. 

Rate-based goals do not in our view implicate leakage to an 

extent that would negate or limit the implementation of the BSER 

because under a rate-based state goal, similar to the 

subcategory-specific emission performance rates, existing loweremitting affected EGUs, primarily NGCC units, are incentivized 

to increase their utilization in order to improve the average 

emission rates of affected EGUs overall. New units that are not 

subject to the rate-based state goal, and that are not an 

allowable measure for adjusting an EGU’s CO2 emission rate, will 

not have this incentive to increase utilization, and as a 

result, the imposition of a rate-based goal on affected EGUs is 

unlikely to encourage increased generation and emissions from 
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unaffected new EGUs. The form of the rate-based state goals 

provides an equivalent or greater incentive to affected existing 

EGUs as they are provided in the CO2 emission performance rates, 

and similarly avoid the potential for leakage. Under both 

approaches, existing NGCC units can generate ERCs. These ERCs 

provide an economic incentive to utilize existing NGCC units 

rather than new NGCC units. Further, ERCs from incremental RE 

incentivize new renewable generation over new NGCC generation. 

Both of these features, which exist in the context of 

implementation with a state rate-based goal or CO2 emission 

performance rates, provide significant incentives to ensure 

that, consistent with the BSER, shifting of generation does not 

occur between existing fossil fuel-fired units and new NGCC 

units. 

Mass-based goals for existing sources, however, incur a 

leakage risk to the extent that they incent generation shifts 

from affected EGUs to unaffected fossil fuel-fired sources in a 

way that negates the reliance on the BSER. In contrast to 

various forms of rate-based implementation, mass-based 

implementation in a state plan can unintentionally incentivize 

increased generation from unaffected new EGUs as a substitute 

action for reducing emissions at units subject to the existing 

source mass goal in ways that would negate the implementation of 
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the BSER and would result in increased emissions. This occurs 

because, unlike in a rate-based system where rate-based 

averaging lowers the cost of generation from existing NGCC units 

relative to generation from new NGCC units, in a mass-based 

system the allowance price increases the cost of generation from 

existing NGCC units relative to generation from new NGCC units. 

The extent to which electricity providers opt to rely on this 

increase in unaffected new source utilization as a substitute 

for improving the emissions performance across existing sources 

would be fundamentally inconsistent with relying on the BSER to 

reduce emissions as the basis of that the subcategory-specific 

emission performance rates. 

As a result, notwithstanding the fact that mass goals for 

existing sources are quantified in a way that is an equivalent 

expression of the BSER, the form of mass goals is only 

equivalent if leakage is satisfactorily addressed in the state 

plan’s establishment of emission standards and implementation 

measures. The EPA is therefore requiring that states adopting a 

mass-based state plan include requirements that address leakage, 

or otherwise provide additional justification that leakage would 

not occur under the state’s share of 2012 affected EGU 
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generation.953implementation of mass-based emission standards. 

This requirement enables states to establish standards of 

performance that meet a mass-based goal equivalent to the 

performance rates and therefore reflect the BSER, as required by 

section 111(d). The required demonstration and options for state 

plans to minimize leakage are discussed in detail in section 

VIII.J of this preamble. 

Further supporting the need for this requirement, the EPA 

has evaluated the mass goals in concert with some of the options 

to minimize leakage described in that section. As mentioned 

above, the EPA analysis identified a concern regarding leakage 

in a mass-based approach, namely that the mass-based 

implementation without measures to address leakage produced 

higher generation from new NGCC units and lower emission 

performance when compared to a rate-based implementation. 

Further analysis where implementation of the mass-based goals 

was coupled with measures to address leakage produce utility 

power sector emissions performance that is similar to emissions 

performance under the rate goals.954

 

953 For more detail on the translation methodology, please refer 

to the technical support document, CO2 Emission Performance Rate 

and Goal Computation TSD for Final Rule, which is available in 

the docket. 

954 See Chapter 3 of the Regulatory Impact Analysis for more 

information on this analysis, which is available in the docket. 
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E. State Plan Adjustments of State Goals 

The EPA notes that it is the emission performance rates in 

section VI that constitute the application of the BSER to the 

affected EGUs and servesserve as the chief regulatory 

requirement of this rulemaking. The statewide CO2 rate-based and 

mass-based emission performance goals provided here are metrics 

that states may choose to adopt when demonstrating compliance at 

the state level, and states may consider these goals when 

determining how to set unit-level compliance requirements. The 

EPA believes that the regional nature of determining the 

emission performance rates encompasses a large population size 

and makes it robust against unit-level variation and unit-level 

inventory discrepancies. The EPA does acknowledge that statelevel rate-based goals or mass-based goals may be sensitive to 

inventoryapplicability changes within a state’s fleet. That 

isaffected population. In the proposal, the EPA used a 

representative baseline that aggregated data for “likelywhat it 

believed to be affected” units and asked states, companies and 

other stakeholders to provide corrections in their comments. We 

received input from many commenters and have corrected 

information as appropriate. Therefore, we believe the baseline 

to be accurate. However, if subsequent applicability review or 

formal applicability determinations change the status of these 
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units as of 2012 in regards to their inclusionbeing affected or 

exclusion in the state’s inventory, the EPA will consider 

allowingunaffected by this rulemaking, states can, via State 

Planstate plan submittal, to or revision, adjust their statewide 

rate or mass goal by up to 1% if such areflect this change is 

necessaryof status. 

This adjustment flexibility provision is based on comments 

received at proposal. For example, some stakeholders noted that 

the affected status of particular units was unclear. The EPA 

recognizes that all the necessary data to determine the affected 

status of some units may not be available at this time. As 

stated in the previous sectionabove, the EPA does not believe 

unit-level variation or inclusion/exclusion disparities between 

baseline inventory and affected units will impact the regionally 

determined emission performance rates discussed in the previous 

section. However, variations in baseline data or inventory may 

have an impact on the state-level rate-based or mass-based goals 

provided in this section. Therefore, the EPA is allowing the 

flexibility for states to demonstrate the need for this type of 

adjustment under the justifications above and utilize an 

adjusted value for compliance purposes when submitting its state 

plan. or revising its state plan. The EPA will evaluate the 

appropriateness of such an adjusted value based on the state’s 
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demonstration and evaluate the approvability of a plan or plan 

revision accordingly.

 As described in the previous section, the non-continental 

United States (non-CONUS) jurisdictions with affected sources 

(Alaska, Hawaii, Guam, and Puerto Rico) required a different 

Best System of Emission Reduction framework as the regional 

nature of deriving emission performance rates was not 

appropriate for their more isolated systems. Therefore, the EPA 

determined bottom-up state goals for these non-CONUS 

jurisdictions based on the same building blocks used for the 

continental United States, but without the regional framework 

component. It then assigned the non-CONUS areas the less 

stringent of their state/jurisdictional specific bottom-up rate 

or the rate resulting from applying the continental technologyspecific emission rates into a non-CONUS jurisdictional goal 

based on that jurisdictions historic mix of fossil steam and 

NGCC generation. This “lesser of” approach is consistent with 

limiting the BSER so that no region or jurisdiction has to do 

more than the region with the least reduction potential. 

Table 9Rate-based statewide CO2 emission performance goals 

are listed below in Table 12. Mass-based statewide CO2 emission 

performance goals are found in Table 13. 
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Table 12. Statewide955 Rate-Based CO2 Emission Performance Goals 

(Adjusted Output-Weighted-Average Pounds of CO2 Per Net MWh From 

All Affected Fossil Fuel-Fired EGUs) 

State Name

Interim 

Goal - 

Step 1 

Interim 

Goal - 

Step 2 

Interim 

Goal - 

Step 3 

Interim 

Goal Final Goal 

Alabama 1,244 1,133 1,060 1,157 1,018 

AlaskaArizona* 1,263 1,149 1,074 1,173 1,031 

Arkansas 1,411 1,276 1,185 1,304 1,130 

Arizona* 

California 961 890 848 907 828 

Colorado 1,476 1,332 1,233 1,362 1,174 

Connecticut 899 836 801 852 786 

Delaware 1,093 1,003 946 1,023 916 

Florida 1,097 1,006 949 1,026 919 

Lands of the Fort 

Mojave Tribe 

Georgia 1,290 1,173 1,094 1,198 1,049 

Guam 

Hawaii 

Iowa 

Idaho 877 817 784 832 771 

Illinois 1,582 1,423 1,313 1,456 1,245 

Indiana 1,578 1,419 1,309 1,451 1,242 

Iowa 1,638 1,472 1,355 1,505 1,283 

Kansas 1,654 1,485 1,366 1,519 1,293 

Kentucky 1,643 1,476 1,358 1,509 1,286 

Lands of the Fort 

Mojave Tribe 877 817 784 832 771 

Lands of the 

Navajo Nation 1,671 1,500 1,380 1,534 1,305 

Lands of the 

Uintah and Ouray 

Reservation 1,671 1,500 1,380 1,534 1,305 

Louisiana 1,398 1,265 1,175 1,293 1,121 

Maine 888 827 793 842 779 

 

955 The EPA has not developed statewide rate-based or mass-based 

CO2 emission performance goals for Vermont and the District of 

Columbia because current information indicates those 

jurisdictions have no affected EGUs. 
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Maryland 1,644 1,476 1,359 1,510 1,287 

Massachusetts 956 885 844 902 824 

Maryland 

Maine 

Michigan 1,468 1,325 1,228 1,355 1,169 

Minnesota 1,535 1,383 1,277 1,414 1,213 

Missouri 

Mississippi 1,136 1,040 978 1,061 945 

Missouri 1,621 1,457 1,342 1,490 1,272 

Montana 1,671 1,500 1,380 1,534 1,305 

Lands of the 

Navajo Nation 

North Carolina 

North Dakota 

Nebraska 1,658 1,488 1,369 1,522 1,296 

Nevada 1,001 924 877 942 855 

New Hampshire 1,006 929 881 947 858 

New Jersey 937 869 829 885 812 

New Mexico* 1,435 1,297 1,203 1,325 1,146 

Nevada 

New York 1,095 1,005 948 1,025 918 

North Carolina 1,419 1,283 1,191 1,311 1,136 

North Dakota 1,671 1,500 1,380 1,534 1,305 

Ohio 1,501 1,353 1,252 1,383 1,190 

Oklahoma 1,319 1,197 1,116 1,223 1,068 

Oregon 1,026 945 896 964 871 

Pennsylvania 1,359 1,232 1,146 1,258 1,095 

Puerto Rico 

Rhode Island 877 817 784 832 771 

South Carolina 1,449 1,309 1,213 1,338 1,156 

South Dakota 1,465 1,323 1,225 1,352 1,167 

Tennessee 1,531 1,380 1,275 1,411 1,211 

Texas 1,279 1,163 1,086 1,188 1,042 

Lands of the Ute 

Tribe of the 

Uintah and Ouray 

Reservation 

Utah* 1,483 1,339 1,239 1,368 1,179 

Virginia 1,120 1,026 966 1,047 934 

Washington 1,192 1,088 1,021 1,111 983 
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Wisconsin 

West Virginia 1,671 1,500 1,380 1,534 1,305 

Wisconsin 1,479 1,335 1,236 1,364 1,176 

Wyoming 1,662 1,492 1,373 1,526 1,299 

* Excludes EGUs located in Indian country within the state. 

Table 1013. Statewide Mass-Based CO2 Emission Performance Goals 

(Adjusted Output-Weighted-Average Tons of CO2 Fromfrom All 

Affected Fossil Fuel-Fired EGUs) 

State 

Interim 

Goal - 

Step 1

Interim 

Goal - 

Step 2

Interim 

Goal - 

Step 3

Interim 

Goal Final Goal 

Alabama 66,164,470 60,918,973 58,215,989 62,210,288 56,880,474

Alaska 

Arizona* 35,189,232 32,371,942 30,906,226 33,061,997 30,170,750 

Arkansas 36,032,671 32,953,521 31,253,744 33,683,258 30,322,632 

California 53,500,107 50,080,840 48,736,877 51,027,075 48,410,120 

Colorado 35,785,322 32,654,483 30,891,824 33,387,883 29,900,397 

Connecticut 7,555,787 7,108,466 6,955,080 7,237,865 6,941,523 

Delaware 5,348,363 4,963,102 4,784,280 5,062,869 4,711,825 

Florida 

119,380,47

7 110,754,683 106,736,177 112,984,729 105,094,704 

Georgia 54,257,931 49,855,082 47,534,817 50,926,084 46,346,846 

Guam 

Hawaii 

Idaho 1,615,518 1,522,826 1,493,052 1,550,142 1,492,856 

Illinois 80,396,108 73,124,936 68,921,937 74,800,876 66,477,157 

Indiana 92,010,787 83,700,336 78,901,574 85,617,065 76,113,835 

Iowa 30,408,352 27,615,429 25,981,975 28,254,411 25,018,136 

Kansas 26,763,719 24,295,773 22,848,095 24,859,333 21,990,826 

Kentucky 76,757,356 69,698,851 65,566,898 71,312,802 63,126,121 

Lands of the 

Fort Mojave 

Tribe 636,876 600,334 588,596 611,103 588,519 

Lands of the 

Navajo Nation 26,449,393 23,999,556 22,557,749 24,557,793 21,700,587 

Lands of the 

Ute Tribe of 

the Uintah 

and Ouray 

Reservation 2,758,744 2,503,220 2,352,835 2,561,445 2,263,431 
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Louisiana 42,035,202 38,461,163 36,496,707 39,310,314 35,427,023 

Maine 2,251,173 2,119,865 2,076,179 2,158,184 2,073,942 

Maryland 17,447,354 15,842,485 14,902,826 16,209,396 14,347,628 

Massachusetts 13,360,735 12,511,985 12,181,628 12,747,677 12,104,747 

Michigan 56,854,256 51,893,556 49,106,884 53,057,150 47,544,064 

Minnesota 27,303,150 24,868,570 23,476,788 25,433,592 22,678,368 

Mississippi 28,940,675 26,790,683 25,756,215 27,338,313 25,304,337 

Missouri 67,312,915 61,158,279 57,570,942 62,569,433 55,462,884 

Montana 13,776,601 12,500,563 11,749,574 12,791,330 11,303,107 

Nebraska 22,246,365 20,192,820 18,987,285 20,661,516 18,272,739 

Nevada 15,076,534 14,072,636 13,652,612 14,344,092 13,523,584 

New Hampshire 4,461,569 4,162,981 4,037,142 4,243,492 3,997,579 

New Jersey 18,241,502 17,107,548 16,681,949 17,426,381 16,599,745 

New Mexico * 14,789,981 13,514,670 12,805,266 13,815,561 12,412,602 

New York 35,493,488 32,932,763 31,741,940 33,595,329 31,257,429 

North 

Carolina 60,975,831 55,749,239 52,856,495 56,986,025 51,266,234 

North Dakota 25,453,173 23,095,610 21,708,108 23,632,821 20,883,232 

Ohio 88,512,313 80,704,944 76,280,168 82,526,513 73,769,806 

Oklahoma 47,577,611 43,665,021 41,577,379 44,610,332 40,488,199 

Oregon 9,097,720 8,477,658 8,209,589 8,643,164 8,118,654 

Pennsylvania 

106,082,75

7 97,204,723 92,392,088 99,330,827 89,822,308 

Rhode Island 3,811,632 3,592,937 3,522,686 3,657,385 3,522,225 

South 

Carolina 31,025,518 28,336,836 26,834,962 28,969,623 25,998,968 

South Dakota 4,231,184 3,862,401 3,655,422 3,948,950 3,539,481 

Tennessee 34,118,301 31,079,178 29,343,221 31,784,860 28,348,396 

Texas 

221,613,29

6 203,728,060 194,351,330 208,090,841 189,588,842 

Utah * 28,479,805 25,981,970 24,572,858 26,566,380 23,778,193 

Virginia 31,290,209 28,990,999 27,898,475 29,580,072 27,433,111 

Washington 12,395,697 11,441,137 10,963,576 11,679,707 10,739,172 

West Virginia 62,557,024 56,762,771 53,352,666 58,083,089 51,325,342 

Wisconsin 33,505,657 30,571,326 28,917,949 31,258,356 27,986,988 

Wyoming 38,528,498 34,967,826 32,875,725 35,780,052 31,634,412 

* Excludes EGUs located in Indian country within the state. 

F. VIIIGeographically Isolated States and Territories with 

Affected EGUs 
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Alaska, Hawaii, Guam, and Puerto Rico constitute a small 

set of states and U.S. territories representing about one 

percent of total U.S. EGU GHG emissions. Based on the current 

record, the EPA does not possess all of the information or the 

analytic tools needed to quantify the application of the BSER 

for these states and territories, particularly data regarding 

renewable energy costs and performance characteristics needed 

for building block 3 of the BSER. The NREL data for RE that the 

EPA is relying upon for building block 3 does not cover the noncontiguous states and territories. 

 The EPA acknowledges that NREL has collaborated with the 

state of Hawaii to provide technical expertise in support of the 

state’s aggressive goals for clean energy, including analyses of 

the grid integration and transmission of solar and wind 

resources.956 The EPA also recognizes that there are studies and 

data for some renewable resources in some of the other noncontiguous jurisdictions. However, taken as a whole, the data we 

currently possess do not allow us to quantify the emissions 

reductions available from building block 3 using the same 

methodology used for the contiguous states encompassed by the 

three interconnections. Lastly, the IPM model used to support 

 

956 Hawaii Solar Integration Study, NREL Technical Report 

NREL/TP-5500-57215, June 2013. 
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the EPA’s analysis is geographically limited to the contiguous 

U.S. As a result of these factors, the EPA currently lacks the 

necessary analytic resources to set emission performance goals 

for these areas. 

Because of the lack of suitable data and analytic tools 

needed to develop area-appropriate building block targets as 

defined in section V, the EPA is not setting CO2 emission 

performance goals for Alaska, Hawaii, Guam, or Puerto Rico in 

this final rule at this time. The EPA believes it is within its 

authority to address performance goals only for the contiguous 

U.S. states in this final rule. Under section 111(d), the EPA is 

not required, at the time that the EPA promulgates section 

111(b) requirements for new sources, to promulgate emission 

guidelines for all of the sources that, if they were new 

sources, would be subject to the section 111(b) requirements if 

there is a reasonable basis for deferring certain groups of 

sources. As discussed, in this rule, the EPA has a reasonable 

basis for deferring setting goals for these four jurisdictions. 

In addition, the Courts have recognized the authority of 

agencies to develop regulatory programs in step-by-step fashion. 

As the U.S. Supreme Court noted in Massachusetts v. EPA, 549 

U.S. 497, 524 (2007): “Agencies, like legislatures, do not 

generally resolve massive problems in one fell regulatory 
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swoop;” and instead they may permissibly implement such 

regulatory programs over time, “refining their preferred 

approach as circumstances change and as they develop a more 

nuanced understanding of how best to proceed.”957 

The EPA recognizes, however, that EGUs in Alaska, Hawaii, 

Puerto Rico, and Guam emit CO2 and that there are opportunities 

to reduce the carbon intensity of generation in those areas over 

time. We recognize further that there are efforts underway to 

increase the use of renewable energy in these jurisdictions. In 

particular, we recognize that Hawaii has tremendous 

opportunities for renewable energy and has adopted very 

ambitious goals: 40 percent clean energy by 2030 and 100 percent 

by 2045. Since 2008, Alaska has apportioned in excess of $1.34 

billion pursuing its aspirational goal of 50 percent of the 

state’s total yearly electric load from renewable and 

alternative energy sources by 2025. Puerto Rico’s goal is to 

achieve 20 percent renewable energy sales by 2035, and the 

territory is working hard to meet the requirements of the 

 

957 See, e.g., Grand Canyon Air Tour Coalition v. F.A.A., 154 

F.3d 455, 471 (D.C. Cir. 1998) (ordinarily, agencies have wide 

latitude to attack a regulatory problem in phases and that a 

phased attack often has substantial benefits); National 

Association of Broadcasters v. FCC, 740 F.2d 1190, 121-11 (D.C. 

Cir. 1984) (“We have therefore recognized the reasonableness of 

[an agency’s] decision to engage in incremental rulemaking and 

to defer resolution of issues raised in a rulemaking....”). 
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Mercury and Air Toxics Standards, which will reduce emissions 

from its power plants substantially. Guam’s RPS is to achieve 25 

percent renewable energy sales by 2035. 

The agency intends to continue to consider these issues and 

determine what the appropriate BSER is for these areas. As part 

of that effort, the agency will investigate sources of 

information and types of analysis appropriate to devise the 

appropriate levels for building block 3 and BSER performance 

levels. Because we recognize that these areas face some of the 

most urgent climate change challenges, severe public health 

problems from air pollution and some of the highest electricity 

rates in the U.S., the EPA is committed to obtaining the right 

information to quantify the emission reductions that are 

achievable in these four areas and putting goals in place soon. 

VIII. State Plans 

A. Overview 

After the EPA establishes the emission guidelines that set 

forth the BSER, each state with one or more affected EGUs958

 

958 In this section, the term “state” encompasses the 50 states 

and the District of Columbia, U.S. territories, As stated 

previously, states with one or more affected EGUs will be 

required to develop and implement plans that set emission 

standards for affected EGUs. The CAA section 111(d) emission 

guidelines that the EPA is promulgating in this action apply to 

only the 48 contiguous states and any Indian tribe that has been 
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shall then develop, adopt and submit a state plan under CAA 

section 111(d). Each state’s obligation under section 111(d) and 

under these guidelines is to establish a standard of performance 

) that establishes standards of performance for the affected 

EGUs in its jurisdiction in order to implement the BSER. That 

standard of performance may expressly incorporate theStarting 

from the foundation of CAA section 111(d) and the EPA’s 

implementing regulations (40 CFR part 60 subpart B), the EPA’s 

proposal laid out a number of options, variations and 

flexibilities that were intended to provide states and affected 

EGUs the ability to design state plans that accorded with 

states’ specific situations and policies (now and in the 

future), and to ensure reliability and affordability of 

electricity across the system and for all ratepayers. The 

proposal has prompted numerous discussions between and among 

stakeholders, especially states and groups of states, including 

state environmental and energy regulators and policy officials. 

The EPA has received many comments from a wide range of 

stakeholders seeking a final rule that afforded freedom and 

flexibility to consider a wide range of standards of performance 

 

approved by the EPA pursuant to 40 CFR 49.9 as eligible to 

develop and implement a CAA section 111(d) plan. Because Vermont 

and the District of Columbia do not have affected EGUs, they 

will not be required to submit a state plan.
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to implement the BSER, but also providing significant feedback 

on the elements and options in the proposal and constructive 

suggestions for alternative approaches. The EPA has carefully 

considered all of this input, and is finalizing emission 

guidelines that continue to provide a variety of options for 

states to fashion their plans in ways legally supportable by the 

CAA, while also making certain adjustments to address key 

comments. 

The next few paragraphs present an overview of the main 

features of the final emission guidelines, highlighting key 

changes from proposal. In the rest of this section, we describe 

in detail the various elements of the final emission guidelines’ 

requirements for state plans. 

The proposal contained rate-based goals for each state, 

reflecting a blended reduction target for that state’s fossil 

fired EGUs, and provided that states could either meet that 

rate-based goal or convert it to a mass-based equivalent goal. 

Reflecting the final BSER described in section V and in response 

to many comments desirous that the EPA establish mass-based 

goals in the final rule, these final guidelines include three 

approaches that states may adopt for purposes of implementing 

the BSER, any one of which a state may use in its plan. These 

are: 1) establishing standards of performance that apply the 
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subcategory specific CO2 emission performance rates the EPA has 

set forth in these guidelines to express the BSER, or, as an 

alternative, the state may establish standards of performance at 

different levels for different EGUs. As a second alternative, 

the state may adopt to their affected EGUs, 2) adopting a 

combination of standards and/or other measures apart from or in 

addition to standards of performance for its affected EGUs. 

These guidelines include rate-based and mass-based CO2 emission 

goals for each statethat achieve state-specific rate-based goals

that represent the equivalent inweighted aggregate of the CO2

emission performance rates applied to the affected EGUs in each 

state; states that adopt either of the two alternative 

approaches – differential standards of performance among their 

affected EGUs or “state measures” - must demonstrate that, in 

the aggregate, the differential standards of performance and/or 

measures they adopt will result in their affected EGUs meeting 

in the aggregate either the states’ respective rate-based CO2

emission goals or mass-based CO2 emission goals. The EPA believes 

that it is appropriate to allow states this significant 

flexibility in both the timing and location of emission 

reductions because CO2 is a global pollutant, and where and when 

the reductions occur is not as significant to the environmental 

outcome as compared to many other conventional pollutants. 
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Each state must decide whether to adopt a plan to meet the 

CO2 emission performance rates for affected EGUs – either as 

emission standards for each EGU reflecting the CO2 emission 

performance rates that represent BSER or as emission standards 

differentiated among its affected EGUs, or adopt and implement, 

in the rate-based metric or in the , and 3) adopting a program 

to meet mass-based metric, the CO2 emission goals set forth by 

the EPA for the state. As already stated, the EPA is 

establishing goalsthat represent the equivalent of the ratebased goal for each state in order to. These alternatives, as 

well as the other options we are finalizing, ensure that both

that states and affected EGUs enjoy the maximum flexibility and 

latitude in meeting the requirements of the emission guidelines 

and that the BSER is fully implemented by each state. For its 

plan, a state 

In the proposal, we provided two designs for state plans: 

one where all the reduction obligations are placed directly on 

the affected EGUs and one, which we called the “portfolio 

approach,” that could include measures to be implemented, in 

whole or in part, by parties other than the affected EGUs. In 

the final guidelines, we retain that basic choice, but with some 

modifications to respond to comments we received, especially on 

the portfolio approach. In their plans, states will be able to 
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choose to either to impose federally enforceable emission 

standards that fully meet the emission guidelines directly on 

affected EGUs (the “emission standards” approach) or to use a 

“state measures" approach, which would comprisebe composed, at 

least in part, of measures implemented by the state that are not 

included as federally enforceable components of the plan, with 

but result in the affected EGUs meeting the requirements of the 

emission guidelines. A state measures type plan must include a 

backstop of federally enforceable standards on affected EGUs 

that fully meet the emission guidelines and that would be 

triggered if the state measures fail to result in the affected 

EGUs achieving on schedule the required emissionsemission

reductions.

States that choose an emission standards plan may establish 

as standards of performance for their affected EGUs the 

subcategory specific CO2 emission performance rates, which 

express the BSER.959 This would satisfy the requirement described 

in section VIII.D.2.a.3 that a state demonstrate its plan would 

achieve the CO2 emission performance rates; in this case, no 

further demonstration would be necessary. Alternatively, a state 

may establish emission standards for affected EGUs at different 

 

959 Rate-based and mass-based emission standards may incorporate 

the use of emission trading.
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levels from the uniform subcategory-specific emission 

performance rates, provided that when implemented, the emission 

standards achieve the CO2 emission performance rates or state 

rate- or mass-based CO2 emission goal set forth by the EPA for 

the state. States that adopt differential standards of 

performance among their affected EGUs must demonstrate that, in 

the aggregate, the differential standards of performance will 

result in their affected EGUs meeting the CO2 emission 

performance rates, the state’s rate-based CO2 emission goal or 

its mass-based CO2 emission goal. 

In the proposal, we proposed that states could use the 

portfolio approach to meet either a rate- or mass-based goal. In 

these final emission guidelines, the state measures approach is 

available only for a state choosing a mass-based CO2 emission 

goal, to provide certainty that the state measures are achieving 

the required emission reductions. Similar to emission standards 

plans with differential standards of performance, states that 

adopt state measures plans must demonstrate that the state 

measures, alone or in conjunction with any federally enforceable 

emission standards on affected EGUs also included in the state 

plan, will result in the affected EGUs in the state meeting the 

state’s mass-based CO2 emission goal. A “state measures” type 

plan must also include a backstop provision – triggered if, 
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during the interim period, the state plan fails to achieve the 

emission reduction trajectory identified in the plan or if, 

during the final phase, the state plan fails to meet the final 

state mass-based CO2 emission goal – that would impose federally 

enforceable emission standards on the affected EGUs adequate to 

meet the emission guidelines when fully implemented. 

The final guidelines reflect the changes to the timing of 

the reductions within the interim period, which is laid out in 

section V as part of the determination of the BSER. States may 

adopt in their plans emission reduction trajectories different 

from the illustrative three-step trajectory included in these 

guidelines for purposes of creating a “glide path” between 2022 

and 2029, provided that the interim and final CO2 emission 

performance rates or state CO2 emission goals are met. 

We recognize that while we are establishing 2022 as the 

date by which the period for mandatory reductions must start as 

part of our BSER determination, utilities and other parties are 

moving forward with projects that reduce emissions of CO2 from 

affected EGUs. We received numerous comments urging us to allow 

credit for these early actions. The final guidelines encourage 

those early reductions, by making clear that states may, in 

their plans, allow EGUs to use allowances or ERCs generated 

through the Clean Energy Incentive Program. The final guidelines 
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also require that states include in their final plans a schedule 

of the actions they will be taking to ensure that the period for 

mandatory reductions will begin as required starting in 2022, 

and submit a progress report on those actions. 

For all types of plans, the final guidelines make clear 

that states may adopt programs that allow trading among affected 

EGUs. The final guidelines retain the flexibility for states to 

do individual plans, or to join with other states in a multistate plan. In addition, and in response to comments from many 

states and other stakeholders, the guidelines provide that 

states may design their programs so that they are “ready for 

interstate trading,” that is, that they contain features 

necessary and suitable for their affected EGUs to engage in 

trading with affected EGUs in other “trading ready” states 

without the need for formal arrangements between individual 

states. 

We have been mindful of the concerns raised by stakeholders 

about reliability. The final BSER, especially the changes in the 

timing of the interim period, substantially address these 

concerns. The flexibilities provided for the design of state 

plans, including the ability to use trading programs, further 

enhance system reliability. We have included, as an additional 

assurance, a reliability safety valve for use where the built-in 
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flexibilities are not sufficient to address an immediate, 

unexpected reliability situation. 

The EPA believes that all the flexibilities provided in the 

final rule are not only appropriate, but will enhance the 

success of the program. CO2 is a global pollutant, and where and 

when the reductions occur is not as significant to the 

environmental outcome as compared to many other conventional 

pollutants. The flexibilities provided in the final guidelines 

will better reflect the unique interconnectedness of the 

electricity system, and will allow states and EGUs to reduce CO2

emissions while maintaining reliability and affordability for 

all consumers. 

In developing the plan, the state rulemaking process must 

meet the minimum public participation requirements of the 

implementing regulations as applicable to these guidelines, 

including a public hearing and meaningful engagement with all 

members of the public, including affected communities. Within 

the time period specified in the emission guidelines (from as 

early as August 31, 2016, to as late as August 31vulnerable 

communities. In the community and environmental justice 

considerations section, section IX of this preamble, the EPA 

addresses the actions that the agency is taking to help ensure 

that vulnerable communities are not disproportionately impacted 
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by this rule. These actions include conducting a proximity 

analysis, setting expectations for states to engage meaningfully 

with vulnerable communities and requiring that they describe 

their plans for doing so as they develop their state plans, 

providing communities with access to additional resources, 

providing communities with information on federal programs and 

resources available to them, recommending that states take a 

multi-pollutant planning approach that examines the potential 

impacts of co-pollutants on overburdened communities, and 

conducting an assessment to determine if any localized air 

quality impacts need to be further addressed. Additionally, the 

EPA outlines the continued engagement that it will be conducting 

with states and communities throughout the state plan 

development process. 

As discussed in more detail in section VIII.E, commenters, 

particularly states, provided compelling information 

establishing that for some, and perhaps many, states it will 

take longer than the agency initially anticipated to develop and 

submit their required plans. In response to those comments, we 

are finalizing a plan submittal process that provides additional 

time for states that need it to submit a final plan submittal to 

the EPA after September 6, 2016. Within the time period 

specified in the emission guidelines (from as early as September 
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6, 2016, to as late as September 6, 2018, depending on whether 

the state receives an extension), the state must submit its 

final state plan to the EPA. The EPA then must determine whether 

to approve or disapprove the plan. If a state does not submit a 

plan, or if the EPA disapproves a state’s plan, then the EPA has 

the express authority under CAA section 111(d) to establish a 

federal plan for the state.960 During and following 

implementation of its approved state plan, each state must 

demonstrate to the EPA that its affected EGUs are meeting the 

interim and final performance requirements included in this 

final rule through monitoring and reporting requirements. 

In the case of a tribe that has one or more affected EGUs 

located in its area of Indian country, if the tribe either does 

not submit a CAA section 111(d) plan or does not receive EPA 

approval of a submitted plan, the EPA has the responsibility to 

establish a CAA section 111(d) plan for that area if it 

determines that such a plan is necessary or appropriate to 

protect air quality.961 

This section is organized as follows. First, we discuss the 

 

960 A federal plan may be withdrawn if the state submits, and 

the EPA approves, a state plan that meets the requirements of 

this final rule and section 111(d) of the CAA. More details 

regarding the federal plan are addressed in the EPA’s proposed 

federal plan rulemaking. 

961 See 40 CFR 49.1 to 49.11. 
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timeline for state plan performance periodsand provisions to 

encourage early action. Second, we describe the types of plans 

that states can submit. Third, we summarize the components of an 

approvable state plan submittal. Fourth, we address the process 

and timing for submittal of state plans and plan revisions. 

Fifth, we address plan implementation and achievement of CO2

emission performance rates or state CO2 emission goals for 

affected EGUs, and the consequences if they are not met. Sixth, 

we discuss several additionalgeneral considerations for states 

in developing and implementing plans, including: accounting for 

emission reduction measures in state plans; treatment of 

interstate effects; requirements for rate-based emission trading 

approaches; evaluation, measurement, and verification (EM&V) 

criteria for RE and demand-side EE resources used to adjust a CO2

rate; consideration of a facility’s “remaining useful life” and 

“other factors;”” and electric reliability. FinallySeventh, we 

note certain resources that are available to facilitate state 

plan development and implementation. Finally, we discuss 

additional considerations for inclusion of CO2 emission reduction 

measures in state plans, including: accounting for emission 

reduction measures in state plans; requirements for mass-based 

and rate-based emission trading approaches; EM&V requirements 

for RE and demand-side EE resources and other measures used to 
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adjust a CO2 rate; and treatment of interstate effects. 

B. Timeline for State Plan Performance Periodsand Provisions to 

Encourage Early Action 

 This section describes state plan requirements related to 

the timing of achieving the emission reductions required in the 

guidelines and the state plan performance periods. This section 

also describes the Clean Energy Incentive Program the EPA is 

establishing to encourage early investment in certain types of 

RE projects, as well as in demand-side EE projects implemented 

in low income communities. 

1. Timeline for state plan performance 

The final guidelines establish three types of performance 

periods: 1) a final deadline by which and after which affected 

EGUs must be in compliance with the final reduction 

requirements, 2) an interim period, and 3) within that interim 

period, three multi-year interim step periods. As discussed 

below and in section V, these performance periods are consistent 

with our determination of the BSER and are also responsive to 

the key comments we received on this aspect of the state plans. 

A performance period is a period for which the final plan 

submittal must demonstrate that the required CO2 emission 

performance rates or state CO2 emission goal will be met. The EPA 

received significant and diverse comments The final guidelines 
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establish 2030 as the deadline for compliance by affected EGUs 

with the final CO2 emission performance rates or CO2 rate or mass 

emission goal; 2030 is the beginning of the final performance 

period. The interim performance period is 2022 to 2029, and 

there are three interim step periods - 2022-2024, 2025-2027, and 

2028-2029 — where increasingly stringent emission performance 

rates or state emission goals must be met. The state may submit 

a plan that incorporates alternative interim step emission 

performance rates or state emission goals to those provided by 

EPA, as long as on average or cumulatively, as appropriate, they 

result in the equivalent of the interim emission performance 

rates or state emission goals in the emission guidelines. These 

timelines are based on careful consideration of the substantial 

comments we received on both the start datetiming of the interim 

period and the trajectory of compliance by affected EGUs over 

the interim period. After careful consideration of those 

comments, we are finalizing a start date of January 1, 2022 for 

the interim period, and three interim step periods. and our 

determination of the BSER, discussed in section V above. The 

modifications we have made to the timelines included in the 

proposal respond to these comments and to concerns about, among 

other things, reliability, feasibility, and cost. 

As previously discussed, the EPA has determined that the 
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BSER includes implementation of reduction measures over the 

period of 2022 through 2029, with final compliance by affected 

EGUs in 2030. Therefore, the final rule requires that interim CO2

emission performance rates or state CO2 emission goals be met for 

the interim period of 2022-2029, and for the three interim step 

periods (2022-2024, 2025-2027, 2028-2029). The . Many commenters 

expressed a desire that the EPA designate steps during the 

interim period to create an interim goal that offered states and 

utilities greater flexibility and choice in determining their 

own emission reduction trajectories over the course of the 

interim period. Since our intent at proposal was to provide such 

flexibility and choice, and since it remains our intent to do so 

in this final rule, we are addressing these comments by 

including in the 2022-2029 interim period three interim step 

periods (2022-2024, 2025-2027, 2028-2029), which correspond 

roughly to the phasing in of the BSER. We note, however, that 

the final rule also allows states that choose to meet a state CO2

emission goal the flexibility to define an alternate trajectory 

of emission performance between 2022 and 2029 to the steps 

specified in the rule. States have the option of meeting goals 

of the state’s choosing for the interim step periods instead of 

meeting the interim step goals provided in the emission 

guidelines, as long as meeting the state-determined , provided 
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that 1) the state plan specifies its own interim step CO2

emission performance rates or state CO2 emission goals, 2) 

meeting the alternative interim step CO2 emission performance 

rates or state CO2 emission goals will still result in the 

interim emission performance rates or state CO2 emission goal 

being met on an 8-year average or cumulative basis, and, 3) the 

2030final CO2 emission performance rates or state CO2 emission 

goal is achieved. To be approvable, a state plan submittal must 

demonstrate that the emission performance of affected EGUs will 

meet the interim step CO2 emission performance rates or interim 

step state CO2 emission interim step goals on average over the 

2022-2024, 2025-2027, and 2028-2029 periods and the final CO2

emission performance rates or state CO2 emission goal no later 

than 2030.962 

This relatively long period – first for planning and, then 

for implementation periodand achievement of the interim and 

final CO2 emission performance rates or state CO2 emission goals 

– provides states and utilities with substantial flexibility 

 

962 States are free to establish different interim step 

performance rates or interim step state goals than those the EPA 

has specified in this final rule. If states choose to determine 

their own interim step performance rates or state goals, the 

state must demonstrate that the plan will still meet the interim 

performance rates or state goal for 2022-2029 finalized in this 

action. 
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regarding methods and timing of achieving emission reductions. 

States may wish to make adjustments to their implementation 

approaches along the way, or as conditions change, may need to 

make adjustments to ensure that their plans achieve the CO2

emission performance rates or state CO2 emission goals as 

intended. As a result, the agency envisions that the EPA, states 

and affected EGUs will have an ongoing relationship in the 

course of implementing this program. from affected EGUs. The 

EPA believes that timing flexibility in implementing measures 

provides significant benefits that allow states to develop plans 

that will help achieve a number of goals, including, but not 

limited to: reducing cost, addressing reliability concerns and 

addressing concerns about stranded assets. , addressing concerns 

about stranded assets, and facilitating the integration of 

meeting the emission guidelines and compliance by affected EGUs 

with other air quality and pollution control obligations on the 

part of both states and affected EGUs. Moreover, we note that 

over the course of time between submittal of final plans and 

2030, circumstances may change such that states may need or wish 

to modify their plans. The relatively lengthy performance 

periods provided in the final rule should help keep those 

situations to a minimum but will also accommodate them if 
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necessary.963 The EPA envisions that the agency, states and 

affected EGUs will have an ongoing relationship in the course of 

implementing this program. Since the record also indicates a 

high degree of interest on the part of states and stakeholders 

in pursuing banking and trading programs, the timing and level 

of stringency of the interim CO2 performance rates or state CO2

emission goals we are finalizing should provide states and 

affected EGUs with ample capacity to accommodate such changes 

without necessitating changes in state plans in many instances.

 The EPA received The timelines established in the final 

rule respond to the issues raised in numerous comments regarding 

the concept of the interim compliance period, including comments 

supporting the flexibility afforded states in developing their 

plans and the timing necessary to meet the 2030 emission 

requirements. Some commenters supported beginning the interim 

goal programplan period at 2020. Others stated that the 

investments necessary to meet the proposed 2020 reduction 

goalsinterim emission performance goals beginning in 2020 are 

unachievable in that timeframe or would place too great a burden 

on affected EGUs and, states, and ratepayers. Some suggested 

that the 2020 interim goal step should be eliminated in favor of 

 

963 Modifications to state plans are addressed more specifically 

in section VIII.E.7 below. 
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later start dates, including 2022, 2025, or other years. 

OtherSome commenters urged the EPA to establish phased interim 

steps creating a steady downward trajectory that allowed several 

years for each step, compatible with the “chunkiness” of utility 

planning processes. Yet other commenters provided input 

suggesting that states be allowed to establish their own set of 

interim guidelines emission performance steps during the interim 

plan performance period and thereby control their own emission 

reduction trajectory or “glide path toward the 2030 goal.” for 

achievement of the interim goal and the 2030 goal, or that the 

EPA not establish any interim standards at all. Commenters also 

noted that for some states, there was not a significant 

difference between the interim and final goal, and, therefore, 

no glide path for those states. As discussed in previous 

sections, based on comments receivedthis input and our final 

determination of the BSER, the EPA has adjusted the start date 

for the interim period to include 2022-2029, is establishing 

three interim performance periods creating a reasonable 

trajectory from 2022 to 2030, and is also retaining the 

flexibility for states to establish their own emissionsemission 

reduction trajectory during the interim period. Because 

 As noted, the EPA has determined that the period for 

mandated reductions should begin in 2022, instead of the 2020 as 
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we proposed, because of the substantial amount of comment and 

data we received indicating that states and utilities reasonably 

needed that additional time provided before the beginning of the 

interim plan performance period, the EPA has determined that 

additional assuranceto take the steps necessary to start 

achieving reductions. In order to assure the EPA and the public

that states are making progress in implementing the plan between 

the time of the state plan submittal and the beginning of the 

interim period is appropriate. As, and as discussed in further

detail in section VIII.D, the final rule requires that the state 

plan submittal include a timeline with all the programmatic 

milestone steps the state will take between the time of the 

state plan submittal and 2022 to ensure the plan is effective as 

of 2022. States must submit a report to the EPA in 2021 that 

demonstrates that the state has met the programmatic milestone 

steps that the state indicated it would take from the submittal 

of the final plan through the end of 2020, and that the state is 

on track to implement the approved state plan as of January 1, 

2022. If the EPA approves a state plan that includes the 

required obligation on the state to submit this report, and the 

state either does not submit the requisite report by July 1, 

2021, or the state submits a report demonstrating it has not met 

the programmatic milestones, the EPA’s approval of the state 
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plan will convert to a disapproval. Per the requirements of CAA 

section 111(d), the EPA will develop and implement a federal 

plan in the instance of such disapproval. 

2. Provisions to encourage early action 

 Many commenters supported providing incentives for states 

to deploy CO2-reducing investments, such as RE and demand-side EE 

measures, as early as possible. The EPA recognizes the value of 

such early actions, and in this final rule is providing states 

with discretion to credit reductions from the activities, 

implemented from 2013 onward, in the context of both mass-based 

and rate-based plans. If a state demonstrates, in its July 1, 

2021 report, that it has implemented such early action measures, 

the EPA will consider its report to be presumptively approvable. 

See sections VIII.C. and VIII.G for a discussion of state plan 

requirements related to incentivizing early action under massbased and rate-based plans, respectively. and utilities to 

deploy CO2-reducing investments, such as RE and demand-side EE 

measures, as early as possible. In the proposal, the EPA 

requested comment on an approach that would recognize emission 

reductions that existing programs provide prior to the initial 

plan performance period starting from a specified date. We also 

requested comment on options for that specified date and on 

conditions that should apply to counting those pre-compliance 
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emission reductions toward a state goal. The EPA received many 

comments requesting that the agency recognize early actions for 

the emission reductions they provide prior to the performance 

period, that the EPA allow those pre-compliance impacts to be 

counted toward meeting requirements under the rule, and that 

certain conditions should be applied to recognition of early 

reductions so as to ensure the emission reductions required in 

the rule. We also received comments from stakeholders regarding 

the disproportionate burdens that some communities already bear, 

and stating that all communities should have equal access to the 

benefits of clean and affordable energy. The EPA recognizes the 

validity and importance of these perspectives, and as a result 

has determined to provide a program – called the Clean Energy 

Incentive Program (CEIP) – in which states may choose to 

participate. This section describes this program.

The EPA has based its determination of the BSER on 

reductions that are achievable beginning in 2022. For that 

reason, these guidelines require no reductions to be made by 

affected EGUs prior to 2022 or by other entities in those states 

that adopt a state measures plan. At the same time, the EPA has 

concluded that it is essential to the achievement in a timely 

and cost-effective way of the emissions reductions required to 

meet the CO2 emission performance rates or, in the alternative, 
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the state goals, that the states and EGUs are rewarded for 

undertaking investments that yield reductions in the years prior 

to 2022. Accordingly, state plans must include a mechanism to 

ensure this outcome. 

For purposes of meeting this requirement, a state plan 

would be presumptively approvable if it included provisions 

comprising one of the following elements: 

 A commitment to demonstrating plan performance on the basis 

of averaging its emissions over a 10-year period beginning 

with emissions from its affected EGUs in 2020, factoring in 

the state’s projected business as usual emissions (rates) 

in 2020 and 2021. 

 A mechanism for awarding to affected EGUs allowances or 

credits for reductions that would contribute to the state’s 

achievement of reductions in 2020 and 2021 that are below 

its business as usual projected emissions for each of those 

years, and provided that the state’s emission in 2020 and 

2021 not exceed the state’s projected business as usual 

level. 

Nothing in these provisions would have the effect of 

requiring any particular affected EGU to achieve reductions 

prior to 2022. In addition, states would have the option for 

including in their state plans mechanisms as alternatives to 
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those described above for meeting the overall emissions 

reduction requirements for 2020 and 2021, provided that any 

state submitting a plan that included a mechanism as an 

alternative to the presumptively approvable mechanism(s) 

described above could demonstrate that the alternative would 

achieve the same outcome as the mechanism(s) described above. 

 The EPA is including this state plan requirement The CEIP 

is designed to incentivize investment in certain RE and demandside EE projects that commence construction in the case of RE, 

or commence operation in the case of EE, following the 

submission of a final state plan to the EPA, or after September 

6, 2018, for states that choose not to submit a final state plan 

by that date, and that generate MWh (RE) or reduce end-use 

energy demand (EE) during 2020 and/or 2021. State participation 

in the program is optional; the EPA is establishing this program 

as an additional flexibility to facilitate achievement of the CO2

emission reductions required by this final rule, regardless of 

the type of state plan a state chooses to implement. 

Under the CEIP, a state may set aside allowances from the 

CO2 emission budget it establishes for the interim plan 

performance period or may generate early action ERCs (ERCs are 

discussed in more detail in section VIII.K.2), and allocate 

these allowances or ERCs to eligible projects for the MWh those 
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projects generate or the end-use energy savings they achieve in 

2020 and/or 2021. A state implementing a mass-based plan 

approach, as described in section VIII.C, may issue early action 

allowances; a state implementing a rate-based plan approach, 

also described in section VIII.C, may issue early action ERCs. 

For each early action allowance or ERC a state allocates to such 

projects, the EPA will provide the state with an appropriate 

number of matching allowances or ERCs, as outlined below, for 

the state to allocate to the project. The EPA will match stateissued early action ERCs and allowances up to an amount that 

represents the equivalent of 300 million short tons of CO2

emissions. The EPA intends that a portion of this pool will be 

reserved for eligible wind and solar projects, and a portion 

will be reserved for low-income EE projects. In the proposed 

federal plan, the EPA is taking comment on the size of each 

reserve, and is proposing provisions to provide that any 

unallocated amounts would be redistributed among participating 

states. 

The EPA has determined that the size of this 300 million 

short ton CO2-equivalent matching pool is an appropriate 

reflection of the CO2 emission reductions that could be achieved 

by the additional early investment in RE and demand-side EE the 

agency expects will be incentivized by the CEIP. For example, in 
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2012, 13 GW of utility scale wind were deployed,964 and, in 2014, 

3.4 GW of utility-scale solar965 plus 2-3 GW of distributed solar 

were deployed,966 according to industry estimates. Assuming 19 GW 

per year of RE from 2017-2020 based on these historic maximums 

yields an installed base of 76 GW of RE potentially eligible for 

CEIP incentives in 2020 and/or 2021. Assuming an average 

capacity factor of 30 percent, this would translate into 

approximately 200 TWh/year of generation, which would be 

eligible for approximately 300 million short tons of matching 

allowances over the 2-year period, if the RE MWh were converted 

to allowances based on the 2012 carbon intensity of 0.8 short 

tons per MWh. This would leave the remaining half of the pool of 

matching federal allowances available for EE projects 

implemented in low-income communities, and additional growth in 

RE deployment beyond these historic maximums as potentially 

enabled by reductions in cost and improvements in performance. 

 For a state to be eligible for a matching award of 

 

964 U.S. Energy Information Administration Electric Power Annual 

2013. http://www.eia.gov/electricity/annual. Table 4.6: Capacity 

additions, retirements and changes by energy source. March 2015. 

965 U.S. Energy Information Administration Electric Power 

Monthly. http://www.eia.gov/electricity/monthly. Table 6.3: New 

Utility Scale Generating Units by Operating Company, Plant, 

Month, and Year. 

966 GTM Research/Solar Energy Industries Association: U.S. Solar 

Market Insight Q1 2015. 
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allowances or ERCs from the EPA, it must demonstrate that it 

will award allowances or ERCs only to eligible projects. These 

are projects that: 

 Are located in or benefit a state that has submitted a 

final state plan that includes requirements establishing 

its participation in the CEIP; 

 Are implemented following the submission of a final state 

plan to the EPA, or after September 6, 2018, for a state 

that chooses not to submit a complete state plan by that 

date; 

 For RE: Generate metered MWh from any type of wind or solar 

resources; 

 For EE: Result in quantified and verified electricity 

savings (MWh) through demand-side EE implemented in lowincome communities; and 

 Generate or save MWh in 2020 and/or 2021. 

 The following provisions outline how a state may award 

early action ERCs or allowances to eligible projects, and how 

the EPA will provide matching ERCs or allowances to states. 

 For RE projects that generate metered MWh from any type of 

wind or solar resources: for every two MWh generated, the 

project will receive one early action ERC (or the 
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equivalent number of allowances) from the state, and the 

EPA will provide one matching ERC (or the equivalent number 

of allowances) to the state to award to the project. 

 For EE projects implemented in low-income communities: for 

every two MWh in end-use demand savings achieved, the 

project will receive two early action ERCs (or the 

equivalent number of allowances) from the state, and the 

EPA will provide two matching ERCs (or the equivalent 

number of allowances) to the state to award to the project. 

 Early action allowances or ERCs awarded by the state, and 

matching allowances or ERCs awarded by the EPA pursuant to the 

CEIP, may be used for compliance by an affected EGU with its 

emission standards and are fully transferrable prior to such 

use. 

 The EPA discusses the CEIP in the proposed federal plan 

rule, and will address design and implementation details of the 

CEIP, including the appropriate factor for determining 

equivalence between allowances and MWh and the definition of a 

low-income community for project eligibility purposes, in a 

subsequent action. Before doing so, the EPA will engage states 

and stakeholders to gather additional information concerning 

implementation topics, and to solicit information about the 

concerns, interests and priorities of states, stakeholders and 
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the public. 

 In order for a state that chooses to participate in the 

CEIP to be eligible for a future award of allowances or ERCs 

from the EPA, a state must include in its initial submittal a 

non-binding statement of intent to participate in the program. 

In the case of a state submitting a final plan by September 6, 

2016, the state plan would either include requirements 

establishing the necessary infrastructure to implement such a 

program and authorizing its affected EGUs to use early action 

allowances or ERCs as appropriate, or would include a nonbinding statement of intent as part of its supporting 

documentation and revise its plan to include those requirements 

at a later date. 

 Following approval of a final state plan that includes 

requirements for implementing the CEIP, the agency will create 

an account of matching allowances or ERCs for the state that 

reflects the pro rata share – based on the amount of the 

reductions from 2012 levels the affected EGUs in the state are 

required to achieve relative to those in the other participating 

states – of the 300 million short ton CO2 emissions-equivalent 

matching pool that the state is eligible to receive. Thus, 

states whose EGUs have greater reduction obligations will be 

eligible to secure a larger proportion of the federal matching 
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pool upon demonstration of quantified and verified MWh of RE 

generation or demand side-EE savings from eligible projects 

realized in 2020 and/or 2021. 

 Any matching allowances or ERCs that remain undistributed 

after September 6, 2018,967 will be distributed to those states 

with approved state plans that include requirements for CEIP 

participation. These ERCs and allowances will be distributed 

according to the pro rata method outlined above. Unused matching 

allowances or ERCs that remain in the accounts of states 

participating in the CEIP on January 1, 2023, will be retired by 

the EPA. 

 For purposes of establishing a state plan program eligible 

for an award of matching allowances or ERCs from the EPA, such a 

program must include a mechanism for awarding early action 

emission allowances or ERCs for eligible actions that reduce or 

avoid CO2 emissions in 2020 and/or 2021, and that is implemented 

in a way such that the early action allowances or ERCs allocated 

by the state would maintain the stringency of the state’s goal 

for emission performance from affected EGUs in the performance 

periods established in this rule. Specifically, the state must 

demonstrate in its plan that it has a mechanism in place that 

 

967 This may occur because not all states may elect to include 

requirements for CEIP participation in their state plans. 
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enables issuance of ERCs or allowances from the state to parties 

effectuating reductions in 2020 and/or 2021 in a manner that 

would have no impact on the aggregate emission performance of 

affected EGUs required to meet rate-based or mass-based CO2

emission standards during the compliance periods.968 This 

demonstration is not required to account for matching ERCs or 

allowances that may be issued to the state by the EPA. 

Participation in this program is entirely voluntary, and nothing 

in these provisions would have the effect of requiring any 

particular affected EGU to achieve reductions prior to 2022, or 

requiring states to offer incentives for emission reductions 

 

968 For example, under a mass-based implementation, the state 

plan could include a set-aside of early action allowances from 

an emissions budget that itself reflects the state goals. 

Allocation of those early action allowances to parties 

effectuating reductions in 2020 and 2021 would have no impact on 

the total emissions budget, which sets the total allowable 

emissions in the compliance periods. Alternatively, under a 

rate-based implementation, the state plan could require that 

early action ERCs issued to parties effectuating reductions in 

2020 and 2021 would be “borrowed” from a pool of ERCs created by 

the state during the interim plan performance period. States 

could limit the size of the “borrowed” pool of ERCs to be 

equivalent to the size of the federal matching pool, or could 

take into consideration the potential for each state’s federal 

matching pool to expand after a redistribution of unused 

credits. For every early action ERC awarded for actions in 2020 

and 2021, the state would retire one ERC from the pool of ERCs 

created as a result of reductions achieved from 2022 onward. 
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achieved prior to 2022.969 These and other details will be 

developed in the subsequent action. 

 The EPA is providing the CEIP as an option for states 

implementing plans – and is including a similar program for the 

federal plan proposal being issued concurrently – for several 

reasons. Chief among them are thoseis that offered by commenters 

to the effect that the overall cost of achievement of the

emission performance rates or state goals could be reduced by an 

approach that granted some form of beneficial recognition to 

emissions reduction investments that both occur and yield 

reductions prior to the first date on which the program mandates 

reductions or imposes emissions limitations.of the interim plan 

performance period. Other commenters pointed out that to the 

extent that states and utilities would benefit from the 

availability of low-cost RE and other zero-emitting generation 

options during the interim and final plan performance periods, 

the EPA should include in the final emission guidelines 

provisions that accelerate deployment of RE resources, since in 

so doing the programfinal emission guidelines would speed 

 

969 In addition to the CEIP, states may also offer credit for 

early investments in RE and demand-side EE according to the 

provisions of section VIII.K.1 of this final rule: a state may 

award ERCs to qualified providers that implement projects from 

2013 onward that realize quantified and verified MWh results in 

2022 and subsequent years.
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achievement of expected reductions in the cost of those 

technologies commensurate with their accelerated deployment. In 

addition, the incentives and market signal generated by the CEIP 

can help sustain the momentum toward greater RE investment in 

the period between now and 2022 so as to offset any dampening 

effects that might be created by setting the start date 2 years 

later than at proposal. 

 The specific criteria the EPA is establishing for eligible 

RE projects reflect a variety of considerations. First, the EPA 

seeks to preserve the incentive for project developers to 

execute on planned investments in all types of solar and wind 

technologies. Commenters raised concerns that the fast pace of 

reductions underlying the emission targets in the proposed rule 

could potentially shift investment from RE to natural gas, thus 

dampening the incentive to develop wind and solar projects, in 

particular. Second, the EPA, consistent with the CAA’s directive 

to incentivize technology and to accelerate the decline in the 

costs of technology, seeks to drive the widespread development 

and deployment of wind and solar, as these broad categories of 

renewable technology are essential to longer term climate 

strategies. Finally, in contrast to other CO2-reducing 

technologies – including other zero-emitting or RE technologies 

– solar and wind projects often require lead times of shorter 
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duration, which would allow them to generate MWh beginning in 

2020. 

 The specific criterion the EPA is establishing for eligible 

EE projects – namely that these projects be implemented in lowincome communities - is also consistent with the technologyforcing and development purposes of section 111. The EPA 

believes it is appropriate to offer an additional incentive to 

remove current barriers to implementing demand-side EE programs 

in low-income communities. While the EPA acknowledges that a 

number of states have demand-side EE programs focused on these 

communities,970 the agency also recognizes that there have been 

historic economic, logistical, and information barriers to 

implementing programs in these communities. As a result, the 

costs of implementing demand-side EE programs in these 

communities are typically higher than in other communities and 

stand as barrier to harvesting potentially cost effective 

reductions and advancing these technologies. The EPA intends for 

the CEIP to help incentivize increased deployment of projects 

that will deliver demand-side EE benefits to these communities, 

which will in turn lower the costs of these approaches. These 

 

970 Several of these programs are discussed in section IX of this 

preamble, including, for example, Maryland’s EmPOWER Low Income 

Energy Efficiency Program (LIEEP) and New York’s EmPower New 

York program. 
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lower costs will help new technologies and delivery mechanisms 

penetrate in the future, thus improving the cost of 

implementation of the emission guidelines overall, consistent 

with Congress’ goals in the New Source Performance Standard 

provisions of the CAA. Further, reducing barriers to demand-side 

EE in low-income communities will help ensure that the benefits 

of the final rule are shared broadly across society and that 

potential adverse impacts on low-income ratepayers are avoided. 

It complements other steps the federal government is taking to 

bring clean energy technologies to these communities, as we 

discuss in section IX of this preamble. 

 More broadly, the CEIP responds to the urgency of meeting 

the challenge of climate change in two key ways. First, of 

course, it fosters reductions before 2022. Second, in targeting 

investments in wind, solar and low-income EE, it focuses on the 

kinds of measures and technologies that are the essential 

foundation of longer-term climate strategies, strategies that 

inevitably depend on the further development and widespread 

deployment of highly adaptable zero-emitting technologies. 

 We are not requiring that projects demonstrate to states 

that they are “additional” or surplus relative to a business-asusual or state goal-related baseline in order to be eligible. At 

the same time, we believe that including an incentive to develop 
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projects that benefit low-income communities will increase the 

likelihood of investments being made that would not have been 

made otherwise. 

 In order to be awarded matching ERCs or allowances by the 

EPA for projects that meet the eligibility criteria, a final 

state plan must have requirements establishing the appropriate 

infrastructure to issue early action ERCs or allowances to 

eligible project providers by 2020. The state must require that 

the state or its agent will, in accordance with state plan 

requirements approved as meeting the ERC issuance and EM&V 

requirements included in section VIII.K: (1) evaluate project 

proposals from eligible RE and demand-side EE project providers, 

including the EM&V plans that must accompany such proposals; (2) 

evaluate monitoring and verification reports submitted by 

eligible providers following project implementation, which 

contain the quantified and verified MWh of RE generation or 

energy savings achieved by the project in 2020 and/or 2021; (3) 

issue ERCs or allowances to eligible providers for these MWh 

results; (4) ensure that no MWh of renewable generation or 

energy savings receives early action or matching ERCs or 
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allowances more than once.971 

 The CEIP will provide a number of benefits. First, the 

program will provide incentives designed to reduce energy bills 

early in the implementation of the guidelines through earlier 

and broader application of energy saving technologies, and help 

ensure that these benefits are fully shared by low-income 

communities. Second, the EPA believes that stimulating or 

supporting early investment in RE generation technologies could 

accelerate the rate at which the costs of these technologies 

fall over the course of the interim performance period. Third, 

the CEIP will provide affected EGUs and states with additional 

emission reduction resources to help them achieve their state 

plan obligations. Finally, the program will improve the 

liquidity, in the early years of the program, of the ERC and 

allowance markets we expect to emerge for compliance with the 

 

971 For a state plan incorporating the use of ERCs or allowances 

to be approvable by the EPA, such a plan must use an EPAapproved or EPA-administered tracking system for ERCs or 

allowances. The EPA received a number of comments from states 

and stakeholders about the value of the EPA’s support in 

developing and/or administering tracking systems to support 

state administration of rate-based emission trading programs. 

The EPA is exploring options for providing such support and is 

conducting an initial scoping assessment of tracking system 

support needs and functionality. 
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requirements of these guidelines.972 

 The EPA is establishing this program as an option for 

states that wish to drive investments in RE and low-income EE 

that will result in actual, early reductions in CO2 emissions 

from affected EGUs. States are also authorized to set their own 

glide path, or interim step performance rates or goals, so long 

as the interim and final performance rates or goals are met, and 

could do so in a way that takes into account the availability of 

the CEIP to assist affected EGUs in meeting the applicable glide 

path and performance rates or goals. While the EPA is not 

requiring states to take advantage of this program, its 

availability simply enhances these already-existing 

implementation and compliance flexibilities while at the same 

time delivering meaningful benefits, particularly for low-income 

communities. The EPA looks forward to an upcoming public 

dialogue about the implementation details of the CEIP. 

C. State Plan Approaches 

1. Overview

 

972 The CEIP is expected to provide states and affected EGUs 

additional flexibility in meeting the guidelines, and bears 

similarity in both design and purpose to the Compliance 

Supplement Pool, which the agency established as a part of the 

NOx SIP Call. See 63 FR 57356, 57428-30 (Oct. 27, 1998). Certain 

aspects of the Compliance Supplement Pool were challenged in 

litigation and upheld by the D.C. Circuit Court of Appeals. See 

Michigan v. EPA, 213 F.3d 663, 694 (D.C. Cir. 2000). 
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 Under the final emission guidelines, states may adopt and 

submit either of two different types of state plans. The first 

would apply all requirements for meeting the emission guidelines 

to affected EGUs in the form of federally enforceable emission 

standards,.973 which weWe refer to this as an “emission 

 

973 40 CFR 60.21(f) defines “emission standard” as “a legally 

enforceable regulation setting forth an allowable rate of 

emissions into the atmosphere, establishing an allowance system, 

or prescribing equipment specifications for control of air 

pollution emissions.” 40 CFR 60.21(f) defines “emission 

standard” as “a legally enforceable regulation setting forth an 

allowable rate of emissions into the atmosphere, establishing an 

allowance system, or prescribing equipment specifications for 

control of air pollution emissions.” This definition is 

promulgated and effective, and we note that it authorizes the 

use of allowance systems as a form of emission standard. To 

resolve any doubt that allowance systems are an acceptable form 

of emission standard in the final rule, we are including 

regulatory text in the final subpart UUUU regulations 

authorizing the use of allowance systems as a form of emission 

standard under section 111(d). Section 60.21(f) was originally 

amended in 2005 to include recognition of allowance systems as a 

form of emission standard in the Clean Air Mercury Rule (CAMR) 

(70 FR 28606, 28649; May 18, 2005). CAMR was vacated in its 

entirety in New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008). 

However, the reason for vacatur was wholly unrelated to the 

question of whether an allowance system could be a form of 

emission standard. In response to the New Jersey decision, the 

agency removed CAMR provisions from the Code of Federal 

Regulations. The agency chose to retain the language of 60.21(f) 

and 60.24(b)(1) generally recognizing allowance systems. This 

language is broader than CAMR and unrelated to the reasons for 

its vacatur. The EPA re-promulgated these provisions in February 

of 2012 (77 FR 9304, 9447; Feb. 16, 2012). Even if this were not 

the case, the agency would not concede that simply because 

“allowance systems” were not provided for in the framework 

regulations of subpart B, they could not be relied upon in 
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standards” state plan type. The second, which we refer to as a 

“state measures” plan type, would allow the CO2 emission 

performance rates or state mass CO2 emission goals to be achieved

by affected EGUs in part, or entirely, through state measures974

that apply to affected EGUs, other entities, or some combination 

thereof. The state measures plan type also includes a mandatory 

contingent backstop of federally enforceable emission standards 

for affected EGUs that would apply in the event the plan does 

not achieve its anticipated level of emission performance as 

specified in the state plan during the period that the state is 

relying on state measures. The inclusion of a backstop of 

federally enforceable emission standards in a state measures

plan type is legally necessary for a state plan to meet the 

requirementsterms of 111(d), which specifically requiresrequire

a state to submit standards of performance, if the state chooses 

to adopt the state measures plan type. 

 

specific emission guidelines, such as these for CO2. The 

implementing regulations generally serve a gap-filling role 

where there are not more specific provisions laid out in the 

relevant emission guidelines. In order to resolve any question 

whether allowance systems are authorized under the final rule, 

we are including regulatory text in subpart UUUU to make this 

authorization explicit. 

974 “State measures” refer to measures that the state adopts and 

implements as a matter of state law. Such measures are 

enforceable only per state law, and are not included in and 

codified as part of the federally enforceable state plan. 
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 These two types of state plans and their respective 

approaches, either of which could be implemented on a singlestate or multi-state basis, allow states to meet the statutory 

requirements of CAA section 111(d) while accommodating the wide 

range of regulatory requirements and other programs that states 

have deployed or will deploy in the electricity sector that 

reduce CO2 emissions from affected EGUs. Further, as described in 

detail below, both types of plans are responsive to comments we 

received from states and other stakeholders. In addition to 

providing states the option of developing an emission standards 

or state measures type plan, the final rule makes clear that 

states that choose an emission standards plan can adopt either a 

rate-based or mass-based CO2 emission goal. 

As described below, the EPA believes that each state is 

able to satisfy the requirements of the Under these two basic 

plan types, the final emission guidelines by provide states with 

a number of potential plan pathways for meeting the emission 

guidelines. A plan pathway represents a specific plan design 

approach used to meet the emission guidelines. These plan 

pathways are discussed in section VIII.C.2 through C.5 below, 

and further elaborated in sections VIII.J (for mass-based 

emission standards) and VIII.K (for rate-based emission 

standards). 
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 The final emission guidelines provide four streamlined plan 

pathways. These streamlined plan pathways represent 

straightforward plan approaches for meeting the emission 

guidelines, and avoid the need to meet additional plan 

requirements and include additional elements in a plan 

submittal. The streamlined plan pathways include the following: 

 Establishing federally enforceable, mass-based CO2 emission 

standards for affected EGUs, complemented by stateenforceable mass-based CO2 emission standards for new fossil 

fuel-fired EGUs.975 This approach could involve an emission 

budget trading program that includes affected EGUs as well 

as new fossil fuel-fired EGUs. This approach facilitates 

interstate emission trading, through either a single-state 

“ready-for-interstate-trading” plan approach or through a 

multi-state plan. Under a “ready-for-interstate-trading” 

plan, interstate emission trading may occur without the 

need for a multi-state plan.976 

 

975 New source CO2 emission complements are discussed in section 

VIII.J.2.b, which also provides EPA-derived new source CO2

emission complements for states.

976 Mass-based trading-ready plans are addressed in section 

VIII.J.3. Multi-state plans, where a group of states are meeting 

a joint CO2 goal for affected EGUs, are addressed in section 

VIII.C.5. 
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 Establishing federally enforceable, mass-based CO2 emission 

standards for affected EGUs.977 This approach facilitates 

interstate emission trading, through either a single-state 

“ready-for-interstate-trading” plan approach or through a 

multi-state plan. In a separate concurrent action, the EPA 

is proposing a model rule for states that could be used in 

a plan implementing a plan this approach.978

 Establishing federally enforceable, subcategory-specific 

rate-based CO2 emission standards for affected EGUs, 

consistent with the CO2 emission performance rates in the 

emission guidelines. This approach provides for interstate 

emission trading, through either a single-state “ready-forinterstate-trading” plan approach or through a multi-state 

plan.979 In a separate concurrent action, the EPA is 

proposing a model rule for states that could be used in a 

plan implementing this approach. 

 

977 This plan approach would meet a state mass-based CO2 goal for 

affected EGUs, or a joint multi-state mass-based CO2 goal for 

affected EGUs. These plan approaches are discussed in sections 

VIII.J.2 and VIII.C.5, respectively. 

978 Submission of a state plan based on the EPA’s finalized model 

rule for a mass-based emission trading program could be 

considered presumptively approvable. The EPA would evaluate the 

approvability of such submission through an independent notice 

and comment rulemaking. 

979 Rate-based trading-ready plans are addressed in section 

VIII.K.4.
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 Establishing federally enforceable rate-based CO2 emission 

standards at a single level that applies for all affected 

EGUs, consistent with the state rate-based CO2 goal for 

affected EGUs in the emission guidelines.980 This approach 

provides for interstate emission trading, through a multistate plan that meets a single weighted average multi-state 

rate-based CO2 goal.981

 The final emission guidelines also provide for a range of 

additional custom plan approaches that a state may pursue, if it 

chooses, to address specific circumstances or policy objectives 

in a state. The custom plan pathways, while viable options for 

meeting the emission guidelines, come with additional plan 

requirements to theand plan submittal elements. These additional 

plan requirements and plan submittal elements are necessary to 

ensure that the emission guidelines are met and that the 

necessary level of CO2 emission performance is achieved by 

affected EGUs. 

Based on this overall approach, the final emission 

guidelines provide for a range of state options – both easily 

implementable approaches that can be used to meet the emission 

 

980 This plan approach is addressed in section VIII.C.2.a. 981 This multi-state plan approach is addressed in section 

VIII.C.5. 
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guidelines, and more customizable approaches that can be used, 

if a state chooses, to address special circumstances or state 

policy objectives. 

2. “Emission standards” state plan type 

The emission standards type of state plan imposes 

requirements solely on affected EGUs in the form of federally 

enforceable emission standards that . This type of state plan, 

as described below, may consist of rate-based emission standards 

for affected EGUs or mass-based emission standards for affected 

EGUs. 

The state plan submittal for an emission standards type 

plan must demonstrate that these federally enforceable emission 

standards for affected EGUs will achieve the CO2 emission 

performance rates or the applicable state rate-based or massbased CO2 emission goal. Under the emission standards state plan 

type, the EPA is finalizing three approaches for state 

plans:affected EGUs. 

 Both rate-based emission standards for affected EGUs, which 

may include use of emission trading; 

and mass-based emission standards included in a state plan 

must be quantifiable, verifiable, enforceable, non-duplicative 

and permanent. These requirements are described in more detail 

at section VIII.D.2. 
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 for affected EGUs, which may include use of emission 

trading; and 

other emission standards for affected EGUsRate-based and 

mass-based emission standards may incorporate the use of 

emission trading, as described below. The EPA anticipates the 

use of emission trading in state plans, given the advantages of 

this approach and comments suggesting a high degree of interest 

on the part of states, utilities, and independent power 

producers in the inclusion of emission trading in state plans.982

 The EPA notes it is proposing model rules for both massbased and rate-based emission trading programs. States could 

adopt and submit the finalized model rules for either emission 

trading program to meet the requirements of CAA section 111(d) 

and these emission guidelines. The EPA will evaluate the 

approvability of such submission, as with any state plan 

submission, through independent notice-and-comment rulemaking. 

The EPA notes that state plan submittals that adopt the 

finalized model rule may be administratively and technically 

more straightforward for the EPA in evaluating approvability, as 

the EPA will have determined that the model rule meets the 

applicable requirements of the emission guidelines through the 

 

982 The legal basis for authorizing trading in emission standards 

is discussed in section VIII.C.6. 
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process of finalization of such rule. 

a. Rate-based approach. The first type of “emission standards” 

plan approach a state may choose is one that uses rate-based 

emission standards. Under this plan approach, the plan would 

include federally enforceable emission standards for affected 

EGUs, in the form of lb CO2/MWh emission standards. 

A rate-based “emission standards” plan may be designed to 

either meet the CO2 emission performance rates for affected EGUs 

or achieve the state’s rate-based CO2 emission goal for affected 

EGUs. A plan could be designed such that compliance by affected 

EGUs would assure achievement of either the CO2 emission 

performance rates for affected EGUs or the state rate-based CO2

emission goal. To meet the CO2 emission performance rates for 

affected EGUs, a plan would establish separate rate-based 

emission standards for affected fossil fuel-fired electric 

utility steam generating units and stationary combustion 

turbines (in lb CO2/MWh) that are equal to or lower than the CO2

emission performance rates in the emission guidelines. To meet a 

state rate-based CO2 goal, a plan would establish a uniform ratebased emission standard (in lb CO2/MWh) that applies to all 

affected EGUs in the state. This uniform emission rate would be 

equal to or lower than the applicable state rate-based CO2 goal 

specified in the final emission guidelines. 
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 Under these two approaches, compliance by affected EGUs 

with the rate-based emission standards in a plan would ensure 

that affected EGUs meet the CO2 emission performance rates in the 

emission guidelines or the state rate-based CO2 goal for affected 

EGUs. No further demonstration would be necessary by the state 

to demonstrate that its plan would achieve the CO2 emission 

performance rates or the state’s rate-based CO2 goal. 

Alternatively, if a state chooses, it could apply ratebased emission standards to individual affected EGUs, or to 

categories of affected EGUs, at a lb CO2/MWh rate that differs 

from the CO2 emission performance rates or the state’s rate-based 

CO2 goal. In this case, compliance by affected EGUs with their 

emission standards would not necessarily ensure that the 

collective, weighted average CO2 emission rate for these affected 

EGUs meets the CO2 emission performance rates or the state’s 

rate-based CO2 goal.983 

 

983 The weighted average CO2 emission rate that will be achieved 

by the fleet of affected EGUs in a state that applies different 

rate-based emission standards to individual affected EGUs or 

groups of affected EGUs will depend upon the mix of electric 

generation from affected EGUs subject to different emission 

standards. For example, if a state applies higher emission 

standards for affected steam generating units and lower emission 

standards for affected NGCC units, the greater the projected 

amount of electric generation from steam generating units, the 

higher the projected weighted average emission rate that will be 

achieved for all affected EGUs. 
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Under this type of approach, therefore, the state would be 

required to include a demonstration,984 in the state plan 

submittal, that its plan would achieve the CO2 emission 

performance rates or applicable state rate-based CO2 goal. This 

demonstration would include a projection of the collective, 

weighted average CO2 emission rate the fleet of affected EGUs 

would achieve as a result of compliance with the emission 

standards in the plan. Once the plan is implemented, if the CO2

emission performance rates or applicable state rate-based CO2

goal are not achieved, corrective measures would need to be 

implemented, as described in section VIII.F.3. 

Under a rate-based approach, a state may include in its 

plan a number of provisions to facilitate affected EGU 

compliance with the emission standards. First, a state may 

encourage (or require) EGUs to undertake actions to reduce CO2

emissions at the affected EGU level, such as heat rate 

improvements or fuel switching. These measures are discussed in 

section VIII.I. Second, a state may implement a market-based 

emission trading program, which enables EGUs to generate and 

procure ERCs, a tradable compliance unit representing one MWh of 

 

984 A demonstration of how a plan will achieve a state’s ratebased or mass-based CO2 emission goal is one of the required plan 

components, as described in section VIII.D.2. 
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electric generation (or reduced electricity use) with zero 

associated CO2 emissions. Considerations and requirements for 

rate-based trading programs are discussed in section VIII.K. 

ERCs would be issued by the administering state regulatory 

body. a rate or mass standard that results from applicationThe 

state may issue ERCs to affected EGUs that emit below a 

specified CO2 emission rate, as well as for measures that provide 

substitute generation for affected EGUs or avoid the need for 

generation from affected EGUs. These ERCs may then be used to 

adjust the reported CO2 emission rate of an affected EGU when 

demonstrating compliance with a rate-based emission standard. 

For each submitted ERC, one MWh is added to the denominator of 

the reported CO2 emission rate, resulting in a lower adjusted CO2

emission rate. 

Eligible measures that may generate ERCs, as well as the 

accounting method for adjusting a CO2 emission rate, are 

discussed in section VIII.K.1. Requirements for rate-based 

emission trading approaches are discussed in section VIII.K.2. 

Quantification and verification requirements for measures 

eligible to generate ERCs are discussed in section VIII.K.3. 

 (1) Rate-based emission standards based on operational or 

other standards. As discussed in further detail in section 

VIII.D.2.d.3, regarding the legal considerations and 
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statutory language of CAA section 111(h), the EPA is 

finalizing that design, equipment, work practice, and 

operational standards cannot be considered to be “standards 

of performance” for this final rule. However, a state may 

elect to use emission standards for affected EGUs that 

result in a reduced CO2 lb/MWh emission rate for affected 

EGUs because of operational or other standards, such as a 

limit on total operating hours of an affected EGU over a 

specified period or the retirement of an affected EGU.985 

While the EPA believes that the CO2 emission performance rates 

can be met, or states can achieve their CO2 emission goals, 

through this first type of . The state would include in its 

state plan, which applies federally enforceable an emission 

standards to affected EGUs,standard that is the agency also 

recognizesrate standard that many states have existing or 

planned programs that limit CO2 emissions from affected EGUs or 

results from the applicable operational or other standard. For 

example, a state might choose to recognize that an individual 

affected EGU has plans to retire, and those plans could be 

codified in the state plan by adopting an emission standard of 0 

 

985 Both rate-based and mass-based emission standards could be 

implemented by states in different ways, including limits that 

apply to specific affected EGUs and market-based emission 

trading programs. These variants are outlined below. 
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CO2 lb/MWh as of a certain date. The state would thus include in 

the state plan an emission standard of 0 CO2 lb/MWh for that 

affected EGU that applies after a specified date. 

 An approvable plan could apply such emission standards to a 

subset of affected EGUs or all affected EGUs. As with any ratebased plan, the state would need to demonstrate that the plan 

would achieve the required level of emission performance for 

affected EGUs, in CO2 lb/MWh. A plan could also apply such 

emission standards to a subset of affected EGUs in the state 

while applying other rate-based emission standards to the 

remainder of affected EGUs in the state. For example, a plan 

might include an emission standard of 0 CO2 lb/MWh reflecting a 

retirement mandate for one or more affected EGUs in a state and 

apply a rate-based emission standard equal to the CO2 emission 

performance rates or a state’s rate-based CO2 emission goal to 

the remainder of affected EGUs. 

As with all emission standards, emission standards based on 

design, equipment, work practice, and operational standards must 

be quantifiable, verifiable, enforceable, non-duplicative and 

permanent. These requirements are described in more detail at 

section VIII.D.2. 

replace or avoid (2) Additional considerations for rate-based 

approach. Additional considerations and requirements for rate-
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based emission standards state plans are addressed in section 

VIII.K. This includes the basic accounting method for adjusting 

the reported CO2 emission rate of an affected EGU, as well as 

requirements for the use of measures to adjust a CO2 emission 

rate, both of which are discussed in sections VIII.K.1 through 

3. Such requirements include eligibility, accounting, and 

quantification and verification requirements (EM&V) for the use 

of CO2 emission reduction measures that provide substitute 

generation for affected EGUs or avoid the need for generation 

from affected EGUs and result in CO2 emission reductions. This 

includes market-based emission budgetin rate-based state plans. 

Section VIII.K.4 addresses multi-state coordination among ratebased emission trading programs. 

b. Mass-based approach. The second “emission standards” approach 

a state may elect to use is mass-based emission standards 

applied to affected EGUs. Under this approach, the plan would 

include federally enforceable emission standards for mass CO2

emissions from affected EGUs. The plan would be designed to 

achieve the mass-based CO2 goal for a state’s affected EGUs (see 

section VII) or a level of CO2 emissions equal to or less than 

the mass-based CO2 goal plus the new source complement CO2
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emissions (see section VIII.J.2.b, Table 14).986 

 Under a mass-based approach, a state could require that 

individual affected EGUs meet a specified mass emission 

standard. Alternatively, a state could choose to implement a 

market-based emission budget trading program. The EPA envisions 

that the latter option is most likely to be exercised by states 

seeking to implement a mass-based emission standard approach, as 

it would maximize compliance flexibility for affected EGUs and 

enable the state to meet its mass goal in the most economically 

efficient manner possible. 

(1) Mass-based emission standard applied to individual 

affected EGUs. 

One pathway a state could take to achieve its mass-based CO2

goal would be to apply mass-based emission standards to 

individual affected EGUs, in the form of a limit on total 

allowable CO2 emissions. These emission standards would be 

designed such that total allowable CO2 emissions from all 

affected EGUs in a state are equal to or less than the state’s 

 

986 For example, a state plan designed to meet a state mass-based 

CO2 goal for affected EGUs plus a new source complement could 

include a mass-based emission budget trading program that 

applies to both affected EGUs, as well as new fossil fuel-fired 

EGUs. The program requirements for affected EGUs would be 

federally enforceable, while the program requirements for other 

fossil fuel-fired EGUs would be state-enforceable. This approach 

is described further in section VIII.J.2. 
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mass-based CO2 goal, or a state’s mass-based CO2 goal plus the 

new source complement CO2 emissions specified in section 

VIII.J.2.b, Table 14. The individual affected EGUs would be 

required to emit at or below their mass-based standard to 

demonstrate compliance. Under this approach, individual affected 

EGUs would be required to undertake source-specific measures to 

assure their CO2 emissions do not exceed their assigned emission 

standard. Affected EGU compliance with the emission standards 

prescribed under this type of mass-based approach would ensure 

that the affected EGUs in a state achieve the state’s mass-based 

CO2 goal, or mass-based CO2 goal plus new source complement. 

(2) Mass-based emission standard with a market-based 

emission budget trading program. 

A second pathway a state could take to achieve its massbased CO2 goal would be to implement a market-based emission 

budget trading program. This type of program provides maximum 

compliance flexibility to affected EGUs, and as a result, may be 

attractive to states that choose to implement a mass-based 

approach in their state plan. 

An emission budget trading program establishes a combined 

emission standard for a group of emission sources in the form of 

an emission budget. Emission allowances are issued in an amount 
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up to the established emission budget.987 Allowances may be 

distributed to affected emission sources that apply to affected 

EGUs, such as the (as well as to other parties) through a number 

of different methods, including direct allocation to affected 

sources or auction. These allowances can be traded among 

affected sources and other parties. The emission standard 

applied to individual emission sources is a requirement to 

surrender emission allowances equal to reported emissions, with 

each allowance representing one ton of CO2. 

The EPA views an emission budget trading program as a 

highly efficient, market-based approach for reducing CO2

emissions from affected EGUs. Such programs include a limit on 

mass CO2 emissions while providing both short-term and long-term 

price signals that encourage the owners or operators of affected 

EGUs, as well as other entities, to determine the most efficient 

means of achieving the mass emission standard. Notably, such an 

approach incentivizes actions taken at affected EGUs to reduce 

CO2 emissions, as well as the use of strategies such as RE and 

demand-side EE as complementary measures that reduce CO2

emissions. However, unlike under a rate-based approach, for this 

 

987 An emission allowance represents a limited authorization to 

emit, typically denominated in one short ton or metric ton of 

emissions. 
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latter set of measures there is no need to address and describe 

these state measures in a state plan submission or quantify and 

verify the RE and EE MWh of generation and savings. As a result, 

a mass-based emission budget trading program incentivizes and 

recognizes a wide range of emission reduction actions while 

being relatively simple for a state to implement and administer. 

Furthermore, the EPA notes that such an approach still allows 

for a state to address electricity load growth, as load growth 

can be met through low- and zero-emitting generating resources, 

as well as avoided through demand-side EE and demand-side 

management (DSM) measures. 

Additional considerations and requirements for mass-based 

emission standards state plans are addressed in section VIII.J. 

This includes use of emission budget trading programs in a state 

plan, including provisions required for such programs (section 

VIII.J.2.a) and the design of such programs in the context of a 

state plan. Section VIII.J addresses program design approaches 

that ensure achievement of a state mass-based CO2 emission goal 

(section VIII.J.2.c), as well as how states can use emission 

budget trading programs with broader source coverage and other 

flexibility features in a state plan, such as the programs 

currently implemented by California and the RGGI participating 

states (section VIII.J.2.d). Section VIII.J.2.e addresses other 
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considerations for the design of emission budget trading 

programs that states may want to consider, such as allowance 

allocation approaches. Section VIII.J.3 addresses multi-state 

coordination among emission budget trading programs used in 

states that retain their individual state mass-based CO2 goals. 

(3) Mass-based emission standards based on operational or 

other standards. 

As discussed in section VIII.C.2.a.(1) above, a state may 

elect to use mass-based emission standards for affected EGUs 

that result in a reduced total tonnage of CO2 emissions from 

affected EGUs because of operational or other standards. The 

state would include in its state plan an emission standard that 

is the mass standard that results from the applicable 

operational or other standard. For example, a state might choose 

to recognize that an individual affected EGU has plans to 

retire, and those plans could be codified in the state plan by 

adopting an emission standard of 0 total tons of CO2, as of a 

certain date. The state would thus include in the state plan an 

emission standard of 0 total tons of CO2 for that affected EGU 

that applies after a specified date. Under a mass-based 

approach, the state could also include an emission standard 

(e.g., a mass limit) that reflects the result of a limit on an 

affected EGU’s total operating hours over a specified period. 
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Such an emission standard would be based on an affected EGU’s 

potential to emit given a specified number of operating hours. 

 An approvable plan could apply such emission standards to a 

subset of affected EGUs or all affected EGUs. As with any massbased plan, the state would need to demonstrate that the plan 

would achieve the required level of emission performance for 

affected EGUs, in total tons of CO2. A plan could also apply such 

emission standards to a subset of affected EGUs in the state 

while applying other emission standards to the remainder of 

affected EGUs in the state. For example, a plan might include an 

emission standard of 0 tons of CO2 for one or more affected EGUs, 

reflecting a retirement mandate for one or more affected EGUs in 

a state, and include the remainder of affected EGUs in an 

emission budget trading program. 

3. “State measures” state plan type 

 The second type of state plan is what we refer to as a 

“state measures” plan. As previously discussed, the EPA believes 

states will be able to submit state plans under the emission 

standards plan type, and its respective approaches, and achieve 

the CO2 emission performance rates or state rate-based or massbased CO2 goals by imposing federally enforceable requirements on 

affected EGUs. Upon further consideration of the requirements of 

CAA section 111(d), in consideration of the comments we received 
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on the proposed portfolio approach and the state commitments 

approach, and in order to provide flexibility and choice to 

states that may wish to adopt a plan that does not place all the 

obligations on affected EGUs, the EPA is finalizing the state 

measures plan type in addition to the emission standards plan 

type. The EPA believes the state measures plan type will provide 

states with additional latitude in accommodating existing or 

planned programs that involve measures implemented by the state, 

or by entities other than affected EGUs, that result in avoided 

generation and CO2 emission reductions at affected EGUs. This 

includes market-based emission budget trading programs that 

apply, in part, to affected EGUs, such as the programs 

implemented by California and the RGGI participating states in 

the Northeast and Mid-Atlantic, as well as RE and demand-side EE 

requirements and programs, such as renewable portfolio standards 

(RPS), energy efficiency resource standards (EERS), and utilityand state-administered incentive programs for the deployment of 

RE and demand-side EE technologies and practices. The EPA is 

providing additionalbelieves this second state plan type will 

afford states with appropriate flexibility to states to 

accommodate suchwhile meeting the statutory requirements and 
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programs through a “state measures” plan.988of CAA section 

111(d). 

Measures implemented under the state measures plan type 

could include RE and demand-side EE requirements and deployment 

programs. This type of plan could align with existing state 

resource planning in the electricity sector, including RE and 

demand-side EE investments by state-regulated electric 

utilities. The state measures plan type is composed of measures 

also can accommodate emission budget trading programs that 

address a broader set of emission sources than just affected 

EGUs subject to CAA section 111(d), such as the programs 

currently implemented by California and the RGGI participating 

states. The EPA also notes that the state measures plan type 

could accommodate imposition by a state of a fee for CO2

emissions from affected EGUs, an approach suggested by a number 

of commenters. 

 This plan type would allow the state to implement a suite 

of state measures that are adopted and implemented by the state 

that, at least in part, are not , implemented, and enforceable 

 

988 Note that emission budget trading programs that meet certain 

basic design criteria may also be included in an “emission 

standards” plan, as described below. 
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only under state law, and rely upon such measures989 in achieving 

the required level of CO2 emission performance from affected 

EGUs. The state measures under this plan type could be measures 

involving entities other than affected EGUs, or a combination of 

such measures with emission standards for affected EGUs, so long 

as the state demonstrates that such measures will result in 

achievement of a state’s mass-based CO2 goal (or mass-based CO2

goal plus new source complement), as discussed below. The EPA 

notes that under this plan type, a state could also choose to 

include any emission standards for affected EGUs, which are 

required to be included in the plan as federally enforceable 

components of the plan, but result in achievement of the CO2

emission performance rates or the applicable state rate-based or 

mass-based CO2 emission goal. These state measures could apply to 

affected EGUs and/measures, to be implemented alongside or other 

entities. Inin conjunction with state measures the state would 

implement and enforce. 

 For a state measures plan, the state to be approvable, it 

must demonstrate include a demonstration of how itsthe measures, 

whether state measures (alone or state measures in conjunction 

 

989 “State measures” refer to measures that the state adopts and 

implements as a matter of state law. Such measures are 

enforceable only per applicable state law, and are not included 

in the federally enforceable state plan. 
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with any federally enforceable emission standards for affected 

EGUs, will achieve the state mass-based CO2 emission goal for 

affected EGUs (or mass-based CO2 goal plus new source 

complement). However, because the state measures would not be 

federally enforceable emission standards, the plan must also 

include a backstop of federally enforceable emission standards 

for all affected EGUs, in order for the state measures plan type 

to satisfy the requirement of CAA section 111(d) that a state 

establish standards of performance for affected EGUs. This 

backstop would impose federally enforceable emission standards 

on the state’s affected EGUs in the case that the state measures 

fail to achieve the state mass-based CO2 goal. The backstop, 

discussed further below, would assure that the state CO2 emission 

goal or CO2 emission performance rates are fully achieved by 

affected EGUs in the form of federally enforceable emission 

standards. 

a. Requirements for state measures under a state measures type 

plan. Under the state measures plan type, state measures must be 

satisfactorily described in the supporting material for a state 

plan submittal. The supporting material would need to 

demonstrate that the state measures meet the same integrity 

elements that would apply to federally enforceable emission 

standards. Specifically, the state plan submittal must 
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demonstrate that the state measures are quantifiable, 

verifiable, enforceable, non-duplicative and permanent. These 

requirements are described in more detail at section VIII.D.2. 

Under the state measures plan, if a state chooses to impose 

emission standards on affected EGUs, such emission standards 

must be included in the federally enforceable plan as they would 

be under an emission standards plan. 

 The EPA would assess the overall approvability of a state 

measures plan based, in part, on the state’s satisfactory 

demonstration that the state measures, in conjunction with any 

federally enforceable emission standards on the affected EGUs 

that might be included in the plan, would result in the state 

plan’s achievement of the mass-based CO2 goal for the state’s 

affected EGUs (or mass-based CO2 goal plus new source 

complement). This includes a demonstration of adequate legal 

authority and funding to implement the state plan and any 

associated measures. The EPA’s determination that such a plan is 

satisfactory would be based in part on whether the state 

measures are adequately described in the supporting 

documentation and the plan submittal demonstrates that the state 

measures are quantifiable, verifiable, enforceable, nonduplicative and permanent as described above. This is necessary 

for the EPA to ensure that the results achieved through the plan 
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are quantifiable and verifiable, and to assess whether the state 

measures are anticipated to achieve the that the state chooses 

to include as partmass-based CO2 goal for affected EGUs (or massbased CO2 goal plus new source complement). 

 The EPA’s evaluation of the approvability of a state 

measures plan) will either would also include an assessment of 

whether the backstop consisting of federally enforceable 

emission standards for the state’s affected EGUs would ensure 

that the required emission performance level is fully achieved 

by affected EGUs, in the case that the state measures fail to 

achieve the state mass-based CO2 goal (or mass-based CO2 goal 

plus new source complement), or the state does not meet

programmatic milestones during the interim period. The trigger 

for the backstop must also satisfactorily provide for the 

implementation of the backstop emission standards. 

b. Considerations for the backstop included in a state measures 

type plan. As further discussed in section VIII.C.6.c, the EPA 

believes a backstop, composed of federally enforceable emission 

standards for the affected EGUs that are sufficient to achieve 

the state CO2 emission goal or the CO2 emission performance rates 

or achievein the event that state measures do not result in the 

required CO2 emission goalperformance, is necessary for affected 

EGUs. Additionally, the state must include in itsmeasures plan 
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type to meet the requirements of CAA section 111(d). The state 

plan a “must specify the backstop” that willwould apply 

federally enforceable emission standards to affected EGUs 

sufficient to meet the affected EGUs if the state measures plan 

does not achieve the anticipated level of CO2 emission 

performance by affected EGUs, or a state does not meet 

programmatic milestones during the interim period. The state 

plan must include promulgated regulations (or other 

requirements) that fully specify these emission standard 

requirements, which must be quantifiable, verifiable, 

enforceable, non-duplicative and permanent. These requirements 

are described in more detail at section VIII.D.2. 

 These federally enforceable emission standards must be 

designed such that compliance by affected EGUs with the emission 

standards would achieve the state’s mass-based interim and final 

goals for affected EGUs. The backstop emission standards must 

specify CO2 emission performance levels (in mass) that would 

apply for the interim plan performance period (including 

specifying levels for each of the interim step 1 through step 3 

periods) and the final two-year plan performance periods.990 If a 

 

990 This includes the level of emission performance during the 

interim plan periods 2022-2024, 2025-2027 and 2028-2029, as well 

as the performance level that would be achieved during every 
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state chose, these backstop emission standards could be based on 

a model rule or federal plan promulgated by the EPA. 

 The state measures plan must specify the trigger and 

conditions under which the backstop federally enforceable 

emission standards would apply that is consistent with the 

requirements in the emission guidelines. The trigger and 

attendant conditions for deployment of the backstop would 

address the CAA section 111(d) requirement that states submit a 

program that provides for the implementation of standards of 

performance. The state measures plan must specify the level of 

emission performance that will be achieved by affected EGUs as a 

result of implementation of the state measures plan during the 

interim and final plan performance periods. This includes the 

level of emission performance during the interim plan periods 

2022-2024, 2025-2027 and 2028-2029, as well as the performance 

level that would be achieved during every subsequent 2-year 

final plan performance period (2030-2031, and subsequent 2-year 

periods). If actual CO2 emission performance by affected EGUs 

fails to meet the level of emission performance specified in the 

plan over the 8-year interim performance period (2022-2029) or 

for any 2-year final goal performance period, the state measures 

 

subsequent 2-year final plan performance period (2030-2031, and 

subsequent 2-year periods). 
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plan must require that the backstop federally enforceable 

emission standards would take effect and be applied to affected 

EGUs. Similarly, the plan must require that the backstop 

standards take effect if actual emission performance is 

deficient by 10 percent or more relative to the performance 

levels that the state has chosen to specify in the plan for the 

interim step 1 period (2022-2024) or the interim step 2 period 

(2025-2027). The backstop standards are also triggered if, at 

the time of the state’s annual reports to the EPA during the 

interim period, the state has not met the programmatic 

milestones for the reporting period. The state measures plan 

must provide that, in the event the backstop is triggered, such 

emission standards would be effective within 18 months of the 

deadline for the state’s submission of its periodic report to 

the EPA on state plan implementation and performance, as 

described in section VIII.D.2.c.991,992 

 The backstop emission standards must make up for the 

 

991 States may choose to establish an effective date for backstop 

emission standards that is sooner than 18 months. 

992 In the event a state does not implement the backstop as 

required if actual emission performance triggers the backstop, 

the EPA will take appropriate action. The EPA notes that as part 

of the proposed federal plan rulemaking, it is proposing a 

regulatory mechanism to call plans in the instances of 

substantial inadequacy to meet applicable requirements or 

failure to implement an approved plan. 
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shortfall in CO2 emission performance. The shortfall must be made 

up as expeditiously as practicable. The state may address the 

requirement to make up for the shortfall in CO2 emission 

performance by submitting, as part of the final plan, backstop 

emission standards that assure affected EGUs would achieve the 

state’s interim and final CO2 emission goals or the CO2 emission 

performance rates or for affected EGUs, and then later submit 

appropriate revisions to the backstop emission standards 

adjusting for the shortfall through the state CO2 emission goal, 

if when being implemented the plan fails to achieve the required 

level of CO2revision process. The state may alternately 

effectuate this by submitting, along with the backstop emission 

standards, provisions to adjust the emission standards to 

account for any prior emission performance during specified plan 

performance periods. These backstop federally enforceable 

emission standards will assureshortfall, such that affected EGUs 

achieve the CO2 emission performance rates or state CO2 no 

modification of the emission goal per the requirements of CAA 

section 111(d) if the state measures fail to resultstandards is 

necessary in order to address the expected level of emission 

performance. shortfall. 

For example, assume a state measures plan identified a 

mass-based CO2 standard for affected EGUs of 100 million tons 
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during the interim step 1 performance period (2022-2024), 90 

million tons during the interim step 2 performance period (2025-

2027), and 80 million tons during the interim step 3 performance 

period (2028-2029). Over the entire interim plan performance 

period (2022-2029), the interim mass-based CO2 goal is cumulative 

emissions of 270 million tons. Assume that CO2 emissions from 

affected EGUs in the interim step 1 period were actually 115 

million tons, triggering implementation of the backstop. In this 

instance, the mass-based standard for affected EGUs implemented 

as part of the backstop during subsequent plan performance 

periods would need to ensure that cumulative CO2 emissions during 

the 2022-2029 interim period do not exceed 270 million tons. 

This could be achieved, for example, by implementing a mass 

standard of 75 million tons during the interim step 2 

performance period (rather than the 90 million tons originally 

specified in the plan), or some other combination during the 

remaining interim step 2 and 3 performance periods.993 The 

emission standards included In addition to providing states the 

option of developing an emission standards or state measures 

 

993 In this example, states could elect to implement different 

combinations of mass-based standards during the remaining 

interim step 2 and 3 plan performance periods, provided that 

cumulative CO2 emissions during the full interim plan performance 

period (2022-2029) do not exceed 270 million tons. 
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type plan, the final rule makes clear that states can adopt 

either a rate-based or mass-based CO2 emission goal. Further, the 

EPA notes that for either an emission standards plan or a state 

measures plan, if a state chooses the option of meeting a state 

rate or mass CO2 emission goal, the metric chosen for the goal is 

independent from the measures that implementing authorities may 

adopt to achieve them. For example, a state could potentially 

adopt mass-based emission standards and/or other measures and 

demonstrate that its plan will achieve a rate-based CO2 goal. 

Likewise, a state could adopt rate-based emission standards 

and/or other measures and demonstrate that its plan will meet a 

mass-based CO2 goal. 

2as the backstop in the plan must specify calculations for 

how such adjustments will be made. 

4. Summary of comments on state plan approaches 

The EPA received a wide range of comments on the basic plan 

approaches in the proposal. Numerous commenters supported 

providing states with the option of implementing a rate-based or 

mass-based approach. Some commenters expressed concern that a 

rate-based approach would not reduce overall emissions, and 

could actually lead to increased emissions. The EPA does not 

agree with this latter comment, because both approaches would 

result in adequate and appropriate constraints on CO2 emissions. 
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As documented in the RIA, a rate-based approach would result in 

a substantial reduction in CO2 emissions relative to emissions 

under a business-as-usual case. 

 Numerous commenters supported allowing states to implement 

a rate-based emission standard approach applied to affected 

EGUs. There was also broad support in comments for allowing 

states to pursue a mass-based approach in the form of mass 

emission standards on affected EGUs. The EPA is finalizing both 

of these approaches, as described below. 

 The EPA received a mix of comments for and against the 

proposed portfolio approach, in which state requirements and 

other measures that apply to non-EGU entities would be part of a 

state’s federally enforceable state plan. Multiple commenters 

supported the portfolio approach because it would align with 

existing state and utility planning processes in the electric 

power sector, and would maximize state discretion and 

flexibility in developing plans. Commenters mentioned the range 

of state requirements and utility programs overseen by states 

that could be used under a portfolio approach and result in 

achieving the CO2 emission goal for affected EGUs, including 

state RPS, EERS and utility-administered EE programs. Commenters 

noted that the portfolio approach would provide states maximum 

flexibility to take local circumstances, economics and state 
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policy into account when developing their plans. 

 By contrast, multiple commenters opposed the portfolio 

approach. Some commenters questioned how a portfolio approach 

would work, and whether the EPA had provided sufficient detail 

explaining how such a plan approach could be implemented by a 

state. In particular, multiple commenters questioned how 

different state programs, such as utility-administered EE 

programs, could be made federally enforceable in practice under 

CAA section 111(d).994 Multiple commenters expressed concern 

about making state requirements and utility programs for RE and 

demand-side EE enforceable under the CAA. Some of these 

commenters supported the state commitments plan approach that 

the EPA took comment on in the proposal, which was a variant of 

the portfolio approach. Under the state commitment variant, 

measures that applied to entities other than affected EGUs would 

not be federally enforceable under the CAA, but state 

commitments to implement those measures would be federally 

enforceable elements of a state plan under the CAA. 

 After considering these comments, the EPA is not finalizing 

the portfolio approach. or the state commitment variant.

However, the EPA is finalizing the state measures plan type, as 

 

994 Legal concernsconsiderations with the proposed portfolio 

approach are explored in section VIII.C.46.d. 
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described below, thatabove, which would accommodate state 

choices and allow states to rely upon a variety of measures, as 

was envisioned under the portfolio approach, in a way that meets 

the statutory requirements of CAA section 111(d). 

5. Multi-state plans and multi-state coordination 

 The EPA views the ability of a state to implement an 

individual plan or a multi-state plan as a significant 

flexibility that allows a state to tailor implementation of its 

plan to state policy objectives and circumstances. The EPA sees 

particular value in multi-state plans and multi-state 

coordination, which allow states to implement a plan in a 

coordinated fashion with other states. Such approaches can lead 

to more efficient implementation, lower compliance costs for 

affected EGUs and lower impacts on electricity ratepayers. 

Coordinated approaches also will help states identify and 

address any potential electric reliability impacts when 

developing plans. 

 The EPA received broad support in comments for allowing 

states to implement multi-state plan approaches, and has made 

multiple changes in the final rule to address many suggestions 

outlining different approaches states may want to take. These 

changes are intended to provide streamlined approaches for 

multi-state coordination while maintaining transparency and 
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assuring that the CO2 emission performance rates or state CO2

emission goals are achieved. 

 The EPA is finalizing two approaches that allow states to 

coordinate implementation in order to meet the emission 

guidelines.995

 First, states may meet the requirements of the emission 

guidelines and CAA section 111(d) by submitting multi-state 

plans that address the affected EGUs in a group of states. The 

EPA is finalizing the proposed approach by which multiple states 

aggregate their rate or mass CO2 goals and submit a multi-state 

plan that will achieve a joint CO2 emission goal for the fleet of 

affected EGUs located within those states (or a joint mass-based 

CO2 goal plus a joint new source CO2 emission complement).996 

 Second, the EPA is also finalizing another approach, in 

response to comments received on the proposed rule. This 

approach enables states to retain their individual state goals 

 

995 The EPA notes that in addition to these approved approaches, 

other types of multi-state approaches may be acceptable in an 

approvable plan, provided the obligations of each state under 

the multi-state plan are clear and the submitted plan(s) meets 

applicable emission guideline requirements. 

996 The concept of a new source CO2 emission complement is 

addressed in section VIII.J.2.b. Table 14 provides individual 

state new source CO2 emission complements. For a multi-state 

plan, a joint new source CO2 emission complement would be the sum 

of the individual new source CO2 emission complements in Table 14 

for the states participating in the multi-state plan. 
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for affected EGUs and submit individual plans, but to coordinate 

plan implementation with other states through the interstate 

transfer of ERCs or emission allowances.997 This approach 

facilitates interstate emission trading without requiring states 

to submit joint plans.998 The EPA considers these to be 

individual state plans, not multi-state plans. 

 States have the option to implement this second approach in 

different ways, as discussed in section VIII.C.5.c. These 

different implementation options allow states to tailor their 

implementation of linked emission trading programs, based on 

state policy preferences, as well as economic and other 

considerations. These different options provide varying levels 

of state control over emission trading system partners and 

require varying levels of coordination in the course of state 

plan development. 

 In response to comments, the EPA is also further clarifying 

how multi-state plans with a joint goal for affected EGUs may be 

implemented. The EPA is clarifying that states may participate 

in more than one multi-state plan, if necessary, for example, to 

 

997 This approach also applies where a state plan is designed to 

meet a state mass-based CO2 goal plus a state’s new source CO2

emission complement. 

998 States may submit individual plans with such linkages, or if 

they choose, provide a joint submittal. Forms of joint 

submittals are described at section VIII.E. 
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address affected EGUs in states that are served by more than one 

ISO or RTO. The EPA is further clarifying that a subset of 

affected EGUs in a state may participate in a multi-state plan. 

These clarifications are discussed in section VIII.C.5.d. 

a. Summary of comments on multi-state plans. Multiple commenters 

supported the EPA’s proposed approach that would allow states to 

implement a multi-state plan to meet a joint CO2 emission goal. 

However, a number of states commented that states should also be 

allowed to coordinate without aggregating multiple individual 

state goals into a single joint goal. Many states questioned the 

incentives that a state would have to aggregate its goal with 

other states that have different goals, and also noted the 

administrative complexities presented by states seeking to 

formally coordinate state plans with one another. 

 The EPA notes that there are multiple incentives for states 

to collaborate by implementing a multi-state plan to meet an 

aggregated joint goal, regardless of the specific level of their 

individual goals, because states share grid regions and impacts 

from plan implementation will be regional in nature. Further, 

multiple analyses, including those by ISOs and RTOs, indicate 

that regional approaches could achieve state goals at lesser 

cost than individual state plan approaches. However, the EPA 

also recognizes the value in allowing for collaboration where 
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states retain individual goals. These approaches could provide 

some of the benefits of a joint goal while reducing the 

negotiations among states necessary to develop a multi-state 

plan with a joint goal. As a result, the EPA has finalized the 

additional approaches described in section VIII.C.5 to provide 

for coordination while maintaining individual goals. These 

approaches would allow for interstate transfer of ERCs or 

emission allowances while retaining individual state goals. 

 Many commenters suggested that states should be encouraged 

to join or form regional market-based programs. Many commenters 

touted the economic efficiency benefits of such approaches, and 

noted that such programs have features that support electric 

reliability. 

 The EPA agrees with these comments, and notes that it 

encouraged such approaches in the proposal. While the EPA is not 

requiring states to join and/or form regional market-based 

programs, we note that such programs can be helpful for many 

reasons, including features that support reliability. Marketbased programs allow greater flexibility for affected EGUs both 

in the short-term and long-term. Under a market-based program, 

affected EGUs have the ability to obtain sufficient allowances 

or credits to cover their emissions in order to comply with 

their emission standards. Additionally, we continue to encourage 
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states to cooperate regionally. Regional cooperation in planning 

and reliability assessments is an important tool to meeting 

system needs in the most cost-effective, efficient, and reliable 

way. 

b. Multi-state coordination through a joint emission goal. 

Multiple states may submit a multi-state plan that achieves an 

aggregated joint CO2 emission goal for the affected EGUs in the 

participating states (or a joint mass-based CO2 goal plus a joint 

new source CO2 emission complement).999 The joint emission goal 

approach is acceptable for both types of state plans, the 

 

999 As a conceptual and legal matter, the relationship between 

states coordinating to meet a joint CO2 emission goal under this 

rule is similar to the relationship between states coordinating 

SIP submissions to attain the NAAQS in an interstate 

nonattainment area. In both cases, the states coordinate their 

actions in a way that, cumulatively, the measures applicable in 

each state will lead to achievement of a common interstate goal 

(with the EPA evaluating the sufficiency and success of the 

plans on a holistic, interstate basis). Despite the shared goal, 

in both cases, the mere fact of coordination has no effect on 

each state’s sovereign legal authority. For example, the legally 

applicable rules in a given state are adopted by that state 

individually, not by a joint entity or other interstate 

mechanism. Similarly, the fact that the states coordinate their 

rules does not grant them the authority to directly enforce each 

other’s rules, or to take direct legal action against a state 

that is failing to implement its own rules. Although some states 

may jointly submit their coordinated rules to the EPA as a 

matter of administrative convenience, the state rules within 

such a plan are nothing more than reciprocal laws of the sort 

that states routinely enact in voluntary coordination with each 

other. 
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“emission standards” plan type and the “state measures” plan 

type. However, the EPA is requiring that a joint goal may apply 

only to states implementing the same type of plan, either an 

“emission standards” plan or a “state measures” plan.1000 

 Under this approach, a rate-based multi-state plan would 

include a weighted average rate-based emission goal, derived by 

calculating a weighted average CO2 emission rate based on the 

individual rate-based goals for each of the participating states 

and 2012 generation from affected EGUs. A mass-based multi-state 

plan would include an aggregated mass-based CO2 emission goal for 

the participating states, in cumulative tons of CO2, derived by 

summing the individual mass-based CO2 emission goals of the 

participating states.1001 

 Such plans could include emission standards in the form of 

a multi-state rate-based or mass-based emission trading 

 

1000 This is necessary because if the joint goal is not achieved 

during a plan performance period, different remedies would apply 

under an emission standards plan and a state measures plan. 

Under an emission standards plan, corrective measures would 

applybe triggered. Under a state measures plan, the federally 

enforceable backstop emission standards would be triggered. See 

section VIII.F.3. 

1001 Where a multi-state plan is designed to meet a joint massbased CO2 goal plus a joint new source CO2 emission complement, 

the joint new source CO2 emission complement would be the sum of 

the individual new source CO2 emission complements in section 

VIII.J.2.b, Table 14, for the states participating in the multistate plan. 
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program.1002 Alternatively, states could submit a multi-state plan 

using a state measures approach.1003 Both approaches could provide 

for implementation of a multi-state emission trading program. 

c. Multi-state coordination among states retaining individual 

state goals. States that do not wish to pursue a joint CO2

emission goal with other states may pursue a second pathway to 

multi-state collaboration. 3. “Emission standards” state plan 

approach 

The first type of state plan imposes requirements solely on 

affected EGUs in the form of federally enforceable emission 

standards, which we refer to as an “emission standards” plan. 

This type of state plan, as described below, may consist of 

rate-based emission standards for affected EGUs; mass-based 

emission standards for affected EGUs; and other emission 

 

1002 A potential example of this approach is the method by which 

the states participating in RGGI have implemented individual CO2

Budget Trading Program regulations in a linked manner using a 

shared emission and allowance tracking system. Each state’s 

regulations implementing RGGI stand alone on a legal basis, but 

provide for the use of CO2 allowances issued in other 

participating states for compliance under the state regulations. 

These states are not listed by name in state regulations, which 

instead refer to participating states that have established a 

corresponding CO2 Budget Trading Program regulation. More 

information is available at http://www.rggi.org. 

1003 Under this approach, a state measure could include, if a 

state chose, a multi-state emission trading program that is 

enforceable at the state level. 
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standards for affected EGUs in the form of a rate- or mass-based 

emission standard that results from application of an 

operational or other standard. Rate-based and mass-based 

emission standards may incorporate the use of emission trading, 

as described below. The EPA anticipates the use of emission 

trading in state plans, due to the advantages of this 

approach.1004

Under this approach, the state plan submittal must 

demonstrate that these federally enforceable emission standards 

for affected EGUs will achieve the state CO2 emission goal or CO2

emission performance rates or the applicable rate-based or massbased state CO2 emission goal. 

a. Rate-based approach. The first type of “emission standards” 

plan approach a state may choose is one that uses rate-based 

emission standards. Under this plan approach, the plan would 

include federally enforceable emission standards for affected 

EGUs, in the form of lb CO2/MWh emission standards. 

A rate-based “emission standards” planStates may be 

designed to either meet the CO2 emission performance rates for 

affected EGUs or achieve the state’s rate-based CO2 emission goal 

for affected EGUs. 

 

1004 The legal basis for authorizing trading in emission standards 

is discussed in section VIII.C.3.d. 
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A plan could be designed such that compliance by affected EGUs 

would achieve either the CO2 emission performance rates for 

affected EGUs or the state rate-based CO2 emission goal. Tosubmit 

individual plans that will meet the CO2 emission performance 

rates, a plan would establish separate or a state mass CO2 goal 

for affected EGUs (or mass-based CO2 goal plus the new source CO2

emission complement), but include implementation in coordination 

with other state plans by providing for the interstate transfer 

of ERCs or CO2 allowances, depending on whether the state is 

implementing a rate-based or mass-based emission trading 

program. This form of coordinated implementation may occur under 

both an “emission standards” type of plan and a “state measures” 

type of plan, where states are implementing emission trading 

programs.1005 For rate-based plans, this type of coordinated 

approach is limited to state plans with rate-based emission 

standards for affected fossil fuel-fired electric utility steam 

generating units and stationary combustion turbines (in lb 

CO2/MWh) that are equal to or lower than the CO2 emission 

performance rates in the emission guidelines. To meet a state 

rate-based CO2 goal, a plan would establish a uniform rate-based 

 

1005 ERCs may only be transferred among states implementing ratebased emission limits. Likewise, emission allowances may only be 

transferred among states implementing mass-based emission 

limits. 
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emission standard (in lb CO2/MWh) that applies to all affected 

EGUs in the state. This uniform emission rate would be equal to 

or lower than the applicable state rate-based CO2 goal specified 

in the final emission guidelines.

 Under this approach, a state plan could indicate that ERCs 

or CO2 allowances issued by other states with an EPA-approved 

state plan could be used by affected EGUs for compliance with 

the state’s rate-based or mass-based emission standard, 

respectively. Such plans must indicate how ERCs or emission 

allowances will be tracked from issuance through use by affected 

EGUs for compliance,1006 through either a joint tracking system, 

interoperable tracking systems, or an EPA-administered tracking 

system.1007 

 The EPA would assess the approvability of each state’s plan 

individually — the use of ERCs or emission allowances issued in 

another state would not impact the approvability of the 

 

1006 Referred to in different programs as “surrender,” 

“retirement,” or “cancellation.” 

1007 The EPA received a number of comments from states and 

stakeholders about the value of the EPA’s support in developing 

and/or administering tracking systems to support state 

administration of rate-based emission trading programs. The EPA 

is exploring options for providing such support and is 

conducting an initial scoping assessment of tracking system 

support needs and functionality.
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components of the individual state plan.1008 However, the EPA 

would also assess linkages with other state plans, to ensure 

that the joint tracking system or interoperable tracking systems 

used to implement rate-based or mass-based emission trading 

programs across states are properly designed with necessary 

components, systems, and procedures to maintain the integrity of 

the linked emission trading programs. 

 Under these two approaches, compliance by affected EGUs 

with the Coordinated state plan implementation among states 

that retain individual state mass-based CO2 goals (or that 

implement individual state plans with rate-based emission 

standards in a plan would ensure that affected EGUs 

meetconsistent with the CO2 emission performance rates in the 

emission guidelines or the state rate-based CO2 goal for affected 

EGUs. No further demonstration would be necessary by the state 

to demonstrate that its plan would achieve the CO2 emission 

performance rates or the state’s rate-based CO2 goal. 

 

1008 Note that for mass-based plans, the approvability 

requirements for a state plan would differ, depending on the 

structure of the emission budget trading program included in the 

state plan. For example, approvability requirements and basic 

accounting with regard to whether a plan achieves a state’s mass 

CO2 goal would differ for emission budget trading programs that 

cover only affected EGUs subject to CAA section 111(d) vs. 

programs that apply to a broader set of emission sources. These 

considerations are addressed in subsectionsection 

VIII.C.5.c.(2)(c).J. 
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If a state chose, it could instead apply) is discussed in more 

detail in sections VIII.J and K. Section VIII.J discusses 

coordinated implementation among states implementing individual 

mass-based emission budget trading programs and section VIII.K 

discusses coordinated implementation among states implementing 

individual rate-based emission standards to individual affected 

EGUs, or to categories of affected EGUs, at a lb CO2/MWh rate 

that differs from the CO2 emission performance rates or the 

state’s rate-based CO2 goal. In this case, compliance by affected 

EGUs with their emission standards would not necessarily ensure 

that the collective, weighted average CO2 emission rate for these 

affected EGUs meets the CO2 emission performance rates or the 

state’s rate-based CO2 goal. trading programs.

d. Multi-state plans that address a subset of EGUs in a state. 

The EPA is clarifying in the final emission guidelines that a 

state may participate in more than one multi-state plan. Under 

this approach, the state would identify in its submittal the 

subset of affected EGUs in the state that are subject to the 

multi-state plan or plans. This could involve a subset of 

affected EGUs that are subject to a multi-state plan, with the 

remainder of affected EGUs subject to a state’s individual plan. 

Alternatively, different affected EGUs in a state may be subject 

to different multi-state plans. In all cases, the state would 
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need to identify in each specific plan which affected EGUs are 

subject to such plan, with each affected EGU subject to only one 

multi-state plan or subject only to the state’s individual plan 

(if relevant). 

 These scenarios may occur where a state chooses to cover 

affected EGUs in different ISOs or RTOs in different multi-state 

plans. This will provide states with flexibility to participate 

in multi-state plans that address the affected EGUs in a 

respective grid region, in the case where state borders cross 

grid regions. 

 These scenarios may also occur where a state is served by 

multiple vertically integrated electric utilities with service 

territories that cross state lines. This will provide states 

with flexibility to participate in multi-state plans that 

address the affected EGUs owned and operated by a utility with a 

multi-state service territory. 

Under this type of approach, the state would be required to 

include a demonstration,1009 in the state plan submittal, of how 

its plan would achieve the CO2 emission performance rates or 

applicable state rate-based CO2 goal. This demonstration would 

 

1009 A demonstration of how a plan will achieve a state’s ratebased or mass-based CO2 emission goal is one of the required plan 

components, as described in section VIII.D.2. 
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include a projection of the collective, weighted average CO2 rate 

it anticipates the fleet of affected EGUs would achieve as a 

result of compliance with the emission standards in the plan. 

Once the plan is implemented, if the CO2 emission performance 

rates or applicable state rate-based CO2 goal are not achieved, 

corrective measures would need to be implemented, as described 

in section VIII.F.3. 

Under a rate-based approach, a state may include in its 

plan a number of provisions to facilitate affected EGU 

compliance with the emission standards. First, a state may 

encourage (or require) EGUs to undertake actions to reduce CO2

emissions at the source level, such as heat rate improvements or 

fuel switching. Second, a state may implement a market-based 

emission trading program, which enables EGUs to generate and 

procure Emission Rate Credits (ERCs), a tradable compliance unit 

representing one MWh of electric generation (or reduced 

electricity use) with zero associated CO2 emissions. These ERCs 

would be issued by the administering state regulatory body. 

The state may issue ERCs to affected EGUs that emit below a 

specified CO2 emission rate, as well as for measures that provide 

substitute generation for affected EGUs or avoid the need for 

generation from affected EGUs. These ERCs may then be used to 

adjust the reported CO2 emission rate of an affected EGU when 
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demonstrating compliance with a rate-based emission standard. 

For each submitted ERC, one MWh is added to the denominator of 

the reported CO2 emission rate, resulting in a lower adjusted CO2

emission rate. 

Eligible measures that may generate ERCs, as well as the 

accounting method for adjusting a CO2 emission rate, are 

discussed in section VIII.G.1. Requirements for rate-based 

emission trading approaches are discussed in section VIII.G.3. 

Quantification and verification requirements for RE and demandside EE programs and projects are discussed in section VIII.G.4. 

ERCs issued in 2022 or a subsequent year may be carried 

forward (or “banked”) and used for demonstrating compliance in a 

future year.1010 For example, an ERC issued for a MWh of RE 

generation that occurs in 2022 may be applied to adjust a CO2

emission rate in 2023 or future years without limitation. ERCs 

may be banked from the interim plan performance period to the 

final plan performance period. 

Banking provides a number of advantages while ensuring that 

the same output-weighted average CO2 emission rates of the 

 

1010 States may also consider issuing ERCs representing MWh 

generation or savings that occur from 2013-2021. Requirements 

for including this type of a provision in a state plan are 

discussed in section VIII.G.1.b.(2). 
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interim and final state CO2 goals are achieved over the course of 

a state plan. Banking provisions have been used extensively in 

rate-based environmental programs and mass-based emission budget 

trading programs.1011 This is because banking reduces the cost of 

attaining the requirements of the regulation. The EPA has 

determined that the same rationale and outcomes apply under a CO2

emission rate approach, in that allowing banking will reduce 

compliance costs. Banking encourages additional emission 

reductions in the near-term if economic to meet a long-term 

emission rate constraint, which is beneficial due to social 

preferences for environmental improvements sooner rather than 

later.1012 Banking also provides long-term economic signals to 

affected emission sources and other market participants where 

actions taken today will have economic value in helping meet 

tighter emission constraints in the future, provided those 

 

1011 Banking under mass-based emission budget trading programs, 

and the rationale for banking provisions, is addressed below in 

section VIII.C.3.b.(J.2)(a)..c.

1012 The absence of banking creates an incentive to defer both 

relatively low-cost and higher-cost CO2 emission reduction 

actions until a later period when emission rate limits become 

more stringent, rather than incentives to undertake the low-cost 

activities sooner in order to further delay the high cost 

actions. Under a rate-based emission trading program, banking 

will encourage ERC providers to generate larger numbers of ERCs 

in early years of a plan performance period, in anticipation of 

rising ERC prices over time, when demand for ERCs is expected to 

increase as rate-based CO2 emission standards become more 

stringent. 
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emission sources expect that the banked emission rate credits or 

emission allowances may be used for compliance in the future. 

Linking short-term and long-term economic incentives, which 

allows owners or operators of affected EGUs and other market 

participants to assess both short-term and long-term incentives 

when making decisions about compliance approaches or emission 

reduction investments, reduces long-term compliance costs for 

affected EGUs and consumer price impacts. In addition, the 

increased temporal flexibility provided by banking would further 

help address potential electric reliability concerns, as banked 

ERCs can be used to meet emission standard requirements for an 

affected EGU. 

Rate-based emission standards included in a state plan must 

be quantifiable, verifiable, enforceable, non-duplicative and 

permanent. These requirements are described in more detail at 

section VIII.D.2. Requirements for rate-based emission trading 

programs that are included in a state plan are discussed in 

detail in section VIII.G.3. This discussion includes 

requirements for the issuance of ERCs. 

b. Mass-based approach. The second “emission standards” approach 

a state may elect to use is mass-based emission standards 

applied to affected EGUs. Under this approach, the plan would 

include federally enforceable emission standards on mass CO2
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emissions from affected EGUs that are designed to achieve the 

mass-based CO2 goal for a state’s affected EGUs (see section 

VII).1013 

 Under a mass-based approach, a state could require that 

individual affected EGUs meet a specified mass emission 

standard. Alternatively, a state could choose to implement a 

market-based emission budget trading program. The EPA envisions 

that the latter option is most likely to be exercised by states 

seeking to implement a mass-based emission standard approach, as 

it would maximize compliance flexibility for affected EGUs and 

enable the state to meet its mass goal in the most economically 

efficient manner possible. 

(1) Mass-based emission standard applied to individual affected 

EGUs. One pathway a state could take to achieve its mass-based 

CO2 goal would be to apply mass-based emission standards to 

individual affected EGUs, in the form of a limit on total 

 

1013 The EPA notes that states could also apply mass emission 

limits on affected EGUs that are designed to achieve a state’s 

rate-based goal. Under this type of approach, the state would be 

required to include a demonstration, the state plan submittal, 

of how its plan would achieve the goal. This demonstration would 

include a projection of the collective, weighted average CO2 rate 

it anticipates the fleet of affected EGUs would achieve as a 

result of the mass emission limits placed on affected EGUs. Once 

the plan is implemented, if the rate goal is not achieved for 

the fleet of affected EGUs as a whole, corrective measures would 

need to be implemented, as described in section VIII.F.3. 
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allowable CO2 emissions. These emission standards would be 

designed such that total allowable CO2 emissions from all 

affected EGUs in a state are equal to or less than the state’s 

mass-based CO2 goal. The individual affected EGUs would be 

required to emit at or below their mass-based standard to 

demonstrate compliance. Under this approach, individual affected 

EGUs would be required to undertake source-specific measures to 

assure their CO2 emissions do not exceed their assigned emission 

limit. Affected EGU compliance with the emission standards 

prescribed under this type of mass-based approach would ensure 

that the affected EGUs in a state achieve the state’s mass-based 

CO2 goal. 

 Mass-based emission standards included in a state plan 

must be quantifiable, verifiable, enforceable, non-duplicative 

and permanent. These requirements are described in more detail 

at section VIII.D.2. 

(2) Mass-based emission standard with a market-based 

emission budget trading program. A second pathway a state could 

take to achieve its mass-based CO2 goal would be to implement a 

market-based emission budget trading program. This type of 

program provides maximum compliance flexibility to affected 

EGUs, and as a result, may be attractive to states who choose to 

implement a mass-based approach in their state plan. 
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An emission budget trading program establishes a combined 

emission standard for a group of emission sources in the form of 

an emission budget. Emission allowances are issued in an amount 

up to the established emission budget.1014 Allowances may be 

distributed to affected emission sources through a number of 

different methods, including direct allocation to affected 

sources or auction. These allowances can be traded among 

affected sources and other parties. The emission standard 

applied to individual emission sources is a requirement to 

surrender emission allowances equal to reported emissions, with 

each allowance representing one ton of CO2. 

(a) Emission budget trading programs that ensure achievement of 

a state CO2 goal. Under the emission standards plan type, a massbased emission budget trading program must be designed such that 

compliance by affected EGUs would achieve the state mass-based 

CO2 goal. Under this approach, a state plan would establish 

emission budgets for affected EGUs during the interim and final 

plan performance periods that are equal to or lower than the 

applicable state mass-based CO2 goals specified in section VII. 

Compliance periods for affected EGUs would also be aligned with 

 

1014 An emission allowance represents a limited authorization to 

emit, typically denominated in one short ton or metric ton of 

emissions. 
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the interim and final plan performance periods. This approach 

would limit total CO2 emissions from affected EGUs during the 

interim and final plan performance periods to an amount equal to 

or less than the state’s mass-based CO2 goal. 

 Under this approach, compliance by affected EGUs with the 

mass-based emission standards in a plan would ensure that the 

state achieves its mass-based CO2 goal for affected EGUs. No 

further demonstration would be necessary by the state to 

demonstrate that its plan would achieve the state’s mass-based 

CO2 goal. 

For this type of plan, where the emission budget is equal 

to or less than the state mass CO2 goal,1015 the EPA would assess 

achievement of the state goal based on compliance by affected 

EGUs with the mass-based emission standards, rather than 

reported CO2 emissions by affected EGUs during the interim plan 

performance periods and final plan performance periods. This 

approach would allow for allowance banking between performance 

periods, including the interim and final performance periods 

outlined in this final rule. This is a typical design element 

for emission budget trading programs addressing GHG emissions. 

 

1015 As specified for the interim plan performance period 

(including specified levels in interim steps 1 through 3) and 

the final two-year plan performance periods. 
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Allowing allowance banking across plan performance periods, 

including from the interim period to the final period, provides 

a number of advantages while ensuring that the same cumulative 

emission reductions are achieved over the course of a state 

plan. Emission budget trading programs with unlimited allowance 

banking limit cumulative tonnage emissions over the period in 

which they are applied. As a result, common program design is to 

allow allowance banking without limitation, unless there is an 

environmental reason for not doing so (e.g., for criteria 

pollutants where timing of emissions is important). As discussed 

in section VIII.C.3.a above, addressing banking under rate-based 

emission trading programs, this is because banking reduces the 

cost of attaining the requirements of the program. In addition, 

the increased temporal flexibility provided by allowance banking 

would further help address potential electric reliability 

concerns, as banked allowances can be used to meet emission 

limit requirements for an affected EGU.

(b) Addressing emission budget trading programs with broader 

source coverage and other flexibilities. As described in section 

VIII.C.3.b(2)(a) above, under the emission standards plan type, 

a mass-based emission budget trading program must be designed 

such that compliance by affected EGUs would achieve the state 

mass-based CO2 goal. However, emission budget trading programs, 
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including those currently implemented by California and the RGGI 

participating states, include a number of different design 

elements. If a state chose, it could apply mass-based emission 

standards in the form of an emission budget trading program that 

differs in design from that outlined in section VIII.C.3.b(2)(a) 

above. However, these types of emission budget trading programs 

must be submitted as a state measure, rather than incorporated 

as federally enforceable emission standards, as described below 

in section VIII.C.4.c. 

(c) State plan provisions required for a mass-based emission 

budget trading program approach. For a mass-based emission 

trading program approach, the state plan would include as its 

federally enforceable emission standards requirements that 

specify the emission budget and related compliance requirements 

and mechanisms. These requirements would include: CO2 emission 

monitoring, reporting, and recordkeeping requirements for 

affected EGUs; provisions for state allocation of allowances; 

provisions for tracking of allowances, from issuance through 

submission for compliance; and the process for affected EGUs to 

demonstrate compliance (allowance “true-up” with reported CO2

emissions). Mass-based emission standards that take the form of 

an emission budget trading program must be quantifiable, 

verifiable, enforceable, non-duplicative and permanent. These 
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requirements are described in more detail at section VIII.D.2.

(d) Considerations for mass-based emission budget trading 

programs. The EPA notes that while an emission budget trading 

program included in an emission standards plan must be designed 

to achieve a state mass-based CO2 goal, states have wide 

discretion in the design of such programs, provided the emission 

standards included in the plan are quantifiable, verifiable, 

enforceable, non-duplicative, and permanent. 

 A key example is state discretion in the CO2 allowance 

allocation methods included in the program.1016 This includes the 

methods used to distribute CO2 allowances and the parties to 

which allowances are distributed. For example, if a state chose, 

it could include CO2 allowance allocation provisions that provide 

incentives for certain types of complementary activities, such 

as RE generation, that help achieve the overall CO2 emission 

limit for affected EGUs established under the program. States 

could also use CO2 allowance allocation provisions to provide 

incentives for early action, such as RE generation or demandside EE savings that occur prior to the beginning of the interim 

plan performance period in 2022. For example, a state could 

 

1016 Allowance allocation refers to the methods used to distribute 

CO2 allowances to the owners or operators of affected EGUs and/or 

other market participants. 
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include CO2 allowance allocation provisions where CO2 allowances 

are distributed to RE generators based on MWh of RE generation 

that occurs prior to 2022. Such provisions might be addressed 

through a finite set-aside of CO2 allowances that are available 

for allocation under these provisions. 

c. Other EGU emission standard approaches. As discussed in 

further detail in section VIII.D.d.(3) regarding the legal 

issues and statutory language of CAA section 111(h), the EPA is 

finalizing that design, equipment, work practice, and 

operational standards cannot be considered as “standards of 

performance” for this final rule. However, the third “emission 

standards” approach a state may elect to use is emission 

standards for affected EGUs that result in reduced CO2 lb/MWh or 

total tons of CO2 affected EGUs because of operational or other 

standards. Under this approach, the state would include in its 

state plan an emission standard that is the rate or mass 

standard that results from the applicable operational or other 

standard. For example, a state might choose to recognize that an 

individual affected EGU has plans to retire, and those plans 

could be codified in the state plan by adopting an emission 

standard of 0 CO2 lb/MWh, or 0 total tons, as of a certain date. 

The state would thus include in the state plan an emission 

standard of 0 CO2 lb/MWh or 0 total tons for that affected EGU 
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that applies after a specified date. Under a mass-based 

approach, the state could also include an emission standard 

(e.g., a mass limit) that reflects the result of a limit on an 

affected EGU’s total operating hours over a specified period. 

 An approvable plan could apply such emission standards to a 

subset of affected EGUs or all affected EGUs. As with any plan, 

the state would need to demonstrate that the plan would achieve 

the required level of emission performance for affected EGUs, in 

either CO2 lb/MWh or total tons of CO2. A plan could also apply 

such emission standards to a subset of affected EGUs in the 

state while applying emission standards to the remainder of 

affected EGUs in the state. For example, a plan might include an 

emission standard of 0 CO2 lb/MWh reflecting a retirement mandate 

for one or more affected EGUs in a state and apply a rate-based 

emission standard equal to the CO2 emission performance rate or 

state’s rate-based CO2 emission goal to the remainder of affected 

EGUs. 

As with the other two approaches, emission standards 

under this approach must be quantifiable, verifiable, 

enforceable, non-duplicative and permanent. These requirements 

are described in more detail at section VIII.D.2. 

d6. Legal bases and considerations for state plan types and 

approaches 
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a. Legal basis for emission standards approach. The emission 

standards approach is consistent with the requirements of CAA 

section 111(d). If a state simply adopts the CO2 emission 

performance rates, then the corresponding rate-based emission 

standards in the state plan establish standards of performance 

for affected EGUs as required under section 111(d)(1)(A). 

Similarly, if a state chooses to achieve the rate-based CO2

emission goal through rate-based emission standards applicable 

only to affected EGUs, or to achieve the mass-based CO2 emission 

goal through mass-based emission standards, applicable only to 

affected EGUs (or, alternatively, to achieve the mass CO2 goal 

and a new source CO2 emission complement through federally 

enforceable mass-based emission standards in conjunction with 

state enforceable emission standards on new sources), then the 

set of rate-based emission standards or the set of mass-based 

emission standards in the state plan establishes standards of 

performance for affected EGUs as required under section 

111(d)(1)(A). The EPA has the authority to approve emission 

standards for affected EGUs as part of a state plan under all 

three cases (as long as such emission standards meet the 

requirements of CAA section 111(d) and the final emission 

guidelines), thereby making such emission standards federally 

enforceable upon approval by the EPA. In all three cases, the 
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emission standards must be quantifiable, verifiable, 

enforceable, non-duplicative and permanent; this ensures that 

the plan provides for implementation and enforcement of the 

standards of performance (i.e. the emission standards) as 

required by section 111(d)(1)(B). Finally, as described in 

section VIII.B.7.b below, standards of performance may include 

emission trading. Thus, the credit and allowance trading that is 

allowed under the emission standards approach is consistent with 

the statutory requirement that the plan establish standards of 

performance. 

e We note that the standard the statute provides for the 

EPA’s review of a state plan is whether it is “satisfactory.” We 

interpret a “satisfactory” plan as one that meets all applicable 

requirements of the CAA, including applicable requirements of 

these guidelines. Some commenters suggested that “satisfactory” 

should be taken to mean something less (such as mostly or 

substantially meeting requirements) but the structure of 111(d) 

shows otherwise. When a state plan is unsatisfactory, section 

111(d)(2) gives the EPA the “same” authority to promulgate a 

federal plan as the EPA has under section 110(c). Under section 

110(c), the EPA has authority to promulgate a federal 

implementation plan if a state implementation plan does not 

comply with all CAA requirements (see sections 110(k)(3) and 
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110(l)). 

 For example, if an emission standards type plan includes an 

emission standard that is unenforceable due to defective rule 

language, then the plan is not satisfactory because it does not 

comply with the guideline requirement that emission standards 

must be enforceable. On the other hand, if a state plan complies 

with all applicable requirements of the CAA (including these 

guidelines), then the EPA must approve it as satisfactory. This 

is true even if the emission standards in the state plan are 

more stringent than the minimum requirements of these 

guidelines, or the state plan achieves more emission reductions 

than required by these guidelines. This follows from section 116 

of the CAA as interpreted by the U.S. Supreme Court in Union 

Elec. Co. v. EPA, 427 U.S. 246, 263-64 (1976). 

b. Legal basis for emissions trading in state plans. There are 

three legal issuesconsiderations with respect to emissions 

trading in state plans. First, we explain how the definition of 

“standard of performance” in section 111(a)(1) allows section 

111(d) plans to include standards of performance that authorize 

emissions trading. Second, we explain how the EPA interprets the 

phrase “provides for implementation and enforcement of [the] 

standards of performance” in the context of a rate-based ERC 

trading schemeprogram. Third, we give a similar explanation of 
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the EPA’s interpretation of the same phrase in the context of a 

mass-based allowance trading schemeprogram. 

(1)). In the proposal, the EPA proposed that CAA section 111(d) 

plans may include standards of performance that authorize 

emissions averaging and trading. 79 FR 34830, 34927/1 (June 18, 

2014). We are finalizing that states may include the use of 

emissionsemission trading in this ruleapprovable state plans. 

For purposes of this legal discussion, in the case of an 

emission limitation expressed as an emission rate, trading takes 

the form of buying or selling ERCs that an affected EGU may 

generate if its actual emission rate is lower than its allowed 

emission rate or that an eligible resource may generate. In the 

case of an emission limitation expressed as a mass-based limit, 

trading takes the form of buying or selling allowances. 

To reiterate for convenience, the definition of “standard 

of performance” under CAA section 111(a)(1) is: 

The term ‘standard of performance’ means a standard 

for emissions of air pollutants which reflects the 

degree of emission limitation achievable through the 

application of the best system of emission reduction 

which (taking into account the cost of achieving such 

reduction and any nonair quality health and 

environmental impact and energy requirements) the 
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Administrator determines has been adequately 

demonstrated. 

Both an emission rate that may be met through tradable 

ERCs, and a mass limit requirement to retirethat emissions not 

exceed the number of tradable allowances surrendered by an 

affected source, qualify as a “standard for emissions.” The term 

“standard” is not defined, but its everyday meaning is a rule or 

requirement,1017 which, under eitherthe only (or at least a 

Chevron step 1 or step 2 analysispermissible) reading of the 

provision, would include an emission rate that may be met 

through tradable ERCs and a requirement to retire tradable 

allowances. 

Treating a tradable emission rate or mass limit requirement 

as a “standard of performance” is consistent with past EPA 

practice. In the Clean Air Mercury Rule, promulgated in 2005, 

the EPA established tradable mass limits as the emission 

guidelines for certain air pollutants from fossil fuel-fired 

EGUs, and explained that a tradable mass limit qualifies as a 

 

1017 E.g., “Something that is set up and established by authority 

as a rule for the measure of quantity, weight, value, or 

quality.” Webster’s Third New International Dictionary 2223 

(1993). 1967); see also The American College Dictionary (C.L. 

Barnhart, ed. 1970) (“an authoritative model or measure”). 
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“standard for emissions.”1018 In addition, in the 1995 Municipal 

Solid Waste (MSW) Combustor rule the EPA authorized emission 

trading by sources.1019

It should be noted that CAA section 302(l) includes another 

definition of “standard of performance,” which is “a requirement 

of continuous emission reduction, including any requirement 

relating to the operation or maintenance of a source to assure 

continuous emission reduction.” As described above, section 

111(d) contains its own, more specific definition of “standard 

of performance,” which a tradable emission rate or mass limit 

satisfies. Whether or not section 302(l) applies in light of 

section 111(d)’s more specific definition, a tradable emission 

rate or mass limit also meets section 302(l)’s requirements. A 

tradable emission rate applies continuously in that the source 

is under a continuous obligation to meet its emission rate, and 

that is so regardless of the averaging time, e.g., a rate that 

must be met on an annual basis. Similarly, an allowancea mass 

limit requirement implemented through the use of allowances

applies continuously in that the source is continuously under an 

obligation to assure that at the appropriate time, it will have 

enough allowances to cover its emissions. will not exceed the 

 

1018 70 FR 28606, 28616-17 (May 18, 2005). 1019 60 FR 65387, 6540/2 (Dec. 19, 1995).
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allowances it will surrender. In this respect, a tradable 

emission rate or allowancemass limit requirement is similar to a 

non-tradable emission rate that must be met over a specified 

period, such as one year. In all of these cases, a source is 

continuously subject to its requirement although it may be able 

to emit at different levels at different points in time. It 

should also be noted that a tradable emission rate or allowance 

programmass limit requirement is appropriate for CO2 emissions, 

the air pollutant covered by this rule, because the 

environmental effects of CO2 emissions doare not cause short-term 

health or welfare dangers; rather, their effects occur over a 

longer term.dependent on the location of the emissions. 

(2)). In our final rule, we are prescribing certain specific 

requirements for trading systems for ERCs in a rate-based 

approach. These specific requirements are in addition to the 

generic requirements for any state plan (see section VIII.D.2.d 

below for the legal basis for the generic components for state 

plans) and are intended to ensure the integrity of the ERC 

trading system. The integrity of the trading system is key to 

ensuring that a state plan provides for implementation and 

enforcement of the standards of performance. , as required by 

section 111(d)(1)(B). Requirements relating to ERCs in a ratebased trading system, and allowances in a mass-based system, 
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must also be submitted as federally enforceable components of 

the state plan, as such requirements provide for the 

implementation and enforcement of a tradable emission rate or 

mass limit for an affected EGU.

Here, we explain our interpretation of the phrase “provides 

for implementation and enforcement of [the] standards of 

performance” in the context of the integrity of a trading system 

for ERCs under a rate-based approach. AsHowever, as described 

previouslyin section VIII.C.6.d, the EPA has legal concerns 

regarding whether federally enforceable requirements under a CAA 

section 111(d) state plan can be imposed on entities other than 

affected EGUs. It is important to note that the use of ERCs and 

inclusion of state plan requirements regarding a rate-based 

trading system, and the use of allowances and inclusion of state 

plan requirements regarding a mass-based trading system, does 

not run afoul of these legal concerns, as neither the 

requirements of section 111(d) nor of the federally enforceable 

state plan in either case extend to non-EGU generators or thirdparty verifiers of such compliance units. In the Legal 

Memorandum we also discuss specific legal issues regarding EM&V 

criteria, EM&V plans, and Projection guidance. 

(3)). In our final rule, we are prescribing certain specific 

requirements for trading systems for allowances in a mass-based 
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approach. These specific requirements are in addition to the 

generic requirements for any state plan (see section VIII.D.2.d 

below for the legal basis for the generic requirements for state 

plans) and are intended to ensure the integrity of the allowance 

trading system. The integrity of the trading system is key to 

ensuring that a state plan provides for implementation and 

enforcement of the standards of performance. 

Our interpretation of the phrase “provides for 

implementation and enforcement of [the] standards of 

performance” in the context of the integrity of a trading system 

for allowances under a mass-based approach is further explained 

in the Legal Memorandum. 

4. “State measures” state plan type 

 The second type of state plan is what we refer to as a 

“state measures” plan. As previously discussed, the EPA believes 

states will be able to submit state plans under the emission 

standards plan type, and its respective approaches, and achieve 

the CO2 emission performance rates or rate-based or mass-based 

state CO2 goals by imposing federally enforceable requirements on 

affected EGUs. Upon further consideration of the requirements of 

CAA section 111(d), and in consideration of the comments we 

received on the proposed portfolio approach and the variation of 

the state commitments approach, the EPA is finalizing the state 
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measures plan type in addition to the emission standards plan 

type. The EPA believes the state measures plan type will provide 

states with additional flexibility to accommodate existing or 

planned programs that involve measures implemented by the state, 

or by entities other than affected EGUs, that result in avoided 

generation and CO2 emission reductions at affected EGUs. The EPA 

believes this second state plan type will afford states with 

appropriate flexibility while meeting the statutory requirements 

of CAA section 111(d). 

Measures implemented under the state measures plan type 

could include RE and demand-side EE requirements and deployment 

programs. This type of plan could align with existing state 

resource planning in the electricity sector, including RE and 

demand-side EE investments by state-regulated electric 

utilities. The state measures plan type also can accommodate 

emission budget trading programs that address a broader set of 

emission sources than just affected EGUs subject to CAA section 

111(d), such as the programs currently implemented by California 

and the RGGI participating states in the Northeast and MidAtlantic. 

 This plan type would allow the state to implement a suite 

of state measures that are adopted, implemented, and enforceable 
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only under state law, and rely upon such measures1020 in achieving 

the required level of CO2 emission performance from affected 

EGUs. The state measures under this plan type could be measures 

involving entities other than affected EGUs, or a combination of 

such measures with emission standards for affected EGUs, so long 

as the state demonstrates that such measures will result in 

achievement of the CO2 emission performance rates or applicable 

state CO2 emission goal. The EPA notes that under this plan type, 

a state could also choose to include any emission standards for 

affected EGUs as federally enforceable requirements in the state 

plan to be implemented alongside or in conjunction with state 

measures the state would implement and enforce. 

 For a state measures plan to be approvable, it must include 

a demonstration of how the measures, whether state measures or 

state measures in conjunction with any federally enforceable 

emission standards, will achieve the CO2 emission performance 

rates or state CO2 emission goal for affected EGUs. However, 

because the state measures would not be federally enforceable 

emission standards, the plan must also include a “backstop” of 

federally enforceable emission standards, in order for the state 

 

1020 “State measures” refer to measures that the state adopts and 

implements as a matter of state law. Such measures are 

enforceable only per applicable state law, and are not included 

in the federally enforceable state plan. 
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measures plan type to satisfy the requirement of CAA section 

111(d) that a state submit standards of performance for affected 

EGUs. This backstop would impose federally enforceable emission 

standards on the state’s affected EGUs in the case that the 

state measures fail to achieve the required CO2 emission 

performance rates or CO2 emission goal. The backstop, discussed 

further below, would assure that the CO2 emission performance 

rates or state CO2 emission goals are fully achieved by affected 

EGUs in the form of federally enforceable emission standards. 

a. Requirements for state measures under a state measures plan.

Under the state measures plan type, state measures must be 

satisfactorily described in the supporting material for a state 

plan submittal. The supporting material would need to 

demonstrate that the state measures meet the same integrity 

elements that would apply to federally enforceable emission 

standards. Specifically, the state plan submittal must 

demonstrate that the state measures are quantifiable, 

verifiable, enforceable, non-duplicative and permanent. These 

requirements are described in more detail at section VIII.D.2. 

 The EPA would assess the overall approvability of a plan 

using a state measures plan type based, in part, on the state’s 

satisfactory demonstration that the state measures, in 

conjunction with any federally enforceable emission standards on 
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the affected EGUs that might be included in the plan, would 

result in the state plan’s achievement of either the CO2 emission 

performance rates or the CO2 emission goal for the state’s 

affected EGUs. This includes a demonstration of adequate legal 

authority and funding to implement the state plan and any 

associated measures. The EPA’s determination that such a plan is 

satisfactory would be based in part on whether the state 

measures are adequately described in the supporting 

documentation and the plan submittal demonstrates that the state 

measures are quantifiable, verifiable, enforceable, nonduplicative and permanent as described above. This is necessary 

for the EPA to ensure that the results achieved through the plan 

are quantifiable and verifiable, and to assess whether the state 

measures are anticipated to achieve the CO2 emission performance 

rates or state CO2 emission goal for affected EGUs. 

 EPA’s evaluation of the approvability of a state measures 

plan would also include assessing whether the backstop comprised 

of federally enforceable emission standards for the state’s 

affected EGUs, in the case that the state measures fail to 

achieve the required CO2 emission performance rates or CO2

emission goal, would assure that the CO2 emission performance 

rates or state CO2 emission goals are fully achieved by affected 

EGUs. The trigger for the backstop must also satisfactorily 
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provide for the implementation of the backstop emission 

standards. 

b. Considerations for the state measures plan type backstop. As 

further discussed in section VIII.C.4.c, the EPA believes a 

backstop, composed of federally enforceable emission standards 

for the affected EGUs that are sufficient to achieve the state 

CO2 emission goal or meet the CO2 emission performance rates in 

the event that state measures do not result in the anticipated 

CO2 emission performance, is necessary for the state measures 

plan type to meet the requirements of CAA section 111(d). The 

state plan must specify the backstop that would apply federally 

enforceable emission standards to the affected EGUs if the state 

measures plan does not achieve the anticipated level of CO2

emission performance by affected EGUs. The state plan must 

include promulgated regulations (or other requirements) that 

fully specify these emission standard requirements, which must 

be quantifiable, verifiable, enforceable, non-duplicative and 

permanent. These requirements are described in more detail at 

section VIII.D.2. 

 These federally enforceable emission standards must be 

designed such that compliance by affected EGUs with the emission 

standards would achieve the state’s rate-based or mass-based 

interim and final goals for affected EGUs, or the CO2 emission 
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performance rates. The emission standards must specify CO2

emission performance levels (in rate or mass) that would apply 

for the interim plan performance period (including specifying 

levels for each of the interim step 1 through step 3 periods) 

and the final two-year plan performance periods.1021 

 The backstop emission standards must also make up for any 

shortfall in CO2 emission performance during a prior plan 

performance period that led to triggering of the backstop, which 

is discussed further below. The state may effectuate this by 

submitting, along with the backstop emission standards, 

provisions to adjust the emission standards to account for any 

prior emission performance shortfall, such that no modification 

of the emission standards is necessary in order to address the 

emission performance shortfall. Examples of such provisions are 

discussed below. The state may also address the requirement to 

make up for any shortfall in CO2 emission performance by 

submitting as part of the final plan backstop emission standards 

that assure affected EGUs would achieve the state’s rate-based 

or mass-based interim and final CO2 goals for affected EGUs, or 

 

1021 This includes the level of emission performance during the 

interim plan periods 2022-2024, 2025-2027 and 2028-2029, as well 

as the performance level that would be achieved during every 

subsequent 2-year final plan performance period (2030-2031, and 

subsequent two-year periods). 
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the CO2 emission performance rates, and then later submit 

appropriate revisions to the backstop emission standards 

adjusting for the shortfall through the state plan revision 

process. 

 The federally enforceable backstop emission standards for 

affected EGUs could be designed by the state to take the form of 

rate-based emission standards, mass-based emission standards, or 

other emission standards, as described above for emission 

standards plan types. Alternatively, the backstop emission 

standards could be based on the federal plan, using the federal 

plan regulations as a model rule. 

 The state measures plan must also specify the trigger and 

conditions under which the backstop federally enforceable 

emission standards would apply. The trigger and attendant 

conditions for deployment of the backstop would address the CAA 

section 111(d) requirement that states submit a program for the 

implementation of standards of performance. The state measures 

plan must specify the level of emission performance that will be 

achieved by affected EGUs as a result of implementation of the 

state measures plan during the interim and final plan 

performance periods. This includes the level of emission 

performance during the interim plan periods 2022-2024, 2025-2027 

and 2028-2029, as well as the performance level that would be 
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achieved during every subsequent two-year final plan performance 

period (2030-2031, and subsequent two-year periods). If actual 

CO2 emission performance by affected EGUs exceeds the specified 

level of emission performance by 10 percent or more during a 

specified interim or final plan performance period, the state 

measures plan must require that the backstop federally 

enforceable emission standards would take effect and be applied 

to affected EGUs. In the event of such an exceedance, the state 

measures plan must provide that such emission standards would be 

effective within 18 months of the deadline for the state’s 

submission of its periodic report to the EPA on state plan 

implementation and performance, as described in section 

VIII.D.2.c.1022 While the state is taking any necessary 

administrative and technical actions to implement the backstop 

emission standards regulations that were promulgated as part of 

the state plan, state measures must remain in effect and 

continue to be implemented by the state until such time as the 

backstop emission standards are effective. 

 As described above, the federally enforceable emission 

standards for affected EGUs must be designed to ensure that the 

CO2 emission performance rates or a state’s interim and final CO2

 

1022 States may choose to establish an effective date for backstop 

emission standards that is sooner than 18 months. 
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goals are achieved. This includes specifying CO2 emission 

performance levels (in rate or mass) during the interim and 

final plan performance periods, as well as inclusion of 

provisions to automatically adjust those emission performance 

levels as appropriate to make up for any CO2 emission performance 

shortfall during a prior plan performance period that led to 

triggering of the backstop. 

 For example, assume a plan identified a mass-based CO2 

standard for affected EGUs of 100 million tons during the 

interim step 1 performance period (2022-2024), 90 million tons 

during the interim step 2 performance period (2025-2027), and 80 

million tons during the interim step 3 performance period (2028-

2029. Over the entire interim plan performance period (2022-

2029), the interim mass-based CO2 goal is cumulative emissions of 

270 million tons. Assume that CO2 emissions from affected EGUs in 

the interim step 1 period were actually 115 million tons, 

triggering implementation of the backstop. In this instance, the 

mass-based standard for affected EGUs implemented as part of the 

backstop during subsequent plan performance periods would need 

to ensure that cumulative CO2 emissions during the 2022-2029 

interim period do not exceed 270 million tons. This could be 

achieved, for example, by implementing a mass standard of 75 

million tons during the interim step 2 performance period 
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(rather than the 90 million tons originally specified in the 

plan), or some other combination during the remaining interim 

step 2 and 3 performance periods.1023 The emission standards 

included in the plan must specify calculations for how such 

adjustments will be made. 

 A similar approach could be applied for a rate-based plan. 

For example, assume the identified emission performance level 

during the interim step 1 performance period is 1,000 lb CO2/MWh 

and the emission performance level during the interim step 2 

performance period is 900 lb CO2/MWh. Further assume that 

affected EGUs actually emit at a rate of 1,150 lb CO2 during the 

interim step 1 plan performance period. The backstop could apply 

an emission standard of 750 lb CO2/MWh during the subsequent 

interim step 2 plan performance period (rather than the 900 lb 

CO2/MWh specified in the emission standard) to make up the 

emission performance shortfall that led to triggering of the 

backstop. 

c. Addressing emission budget trading programs under the state 

measures plan type. As described in section VIII.C.3.b(2)(a) 

 

1023 In this example, states could elect to implement different 

combinations of mass-based standards during the remaining 

interim step 2 and 3 plan performance periods, provided that 

cumulative CO2 emissions during the full interim plan performance 

period (2022-2029) do not exceed 270 million tons. 
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above, under the emission standards plan type, a mass-based 

emission budget trading program must be designed such that 

compliance by affected EGUs would achieve the state mass-based 

CO2 goal. However, emission budget trading programs, including 

those currently implemented by California and the RGGI 

participating states, include a number of different design 

elements. If a state chose, it could apply such mass-based 

emission standards, in the form of an emission budget trading 

program that differs in design from that outlined in section 

VIII.C.3.b(2)(a) above. However, these types of emission budget 

trading programs must be submitted as a state measure, rather 

than incorporated as federally enforceable emission standards, 

as described below. 

 Such programs could include a number of different design 

elements. This includes broader program scope, where a program 

includes other emission sources beyond affected EGUs subject to 

CAA section 111(d), such as industrial sources. Programs might 

also include design elements that make allowances available in 

addition to the established emission budget. This includes 

project-based offset allowances or credits from GHG emission 

reduction projects outside the covered sector and cost 

containment reserve provisions that make additional allowances 
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available at specified allowance prices.1024

 In the case where an emission budget trading program 

contains such elements, compliance by affected EGUs with the 

mass-based emission standards would not necessarily ensure that 

CO2 emissions from affected EGUs do not exceed the state’s massbased CO2 goal. 

The EPA has determined that such emission budget trading 

programs, which may include broader scope of covered emission 

sources and the types of provisions described above that 

functionally expand an established emission budget, may be 

implemented as part of a state measures plan. A description of 

the state measures plan type and related requirements is 

provided in section VIII.C.4. 

Under this type of approach, the state would be required to 

include a demonstration,1025 in its state plan submittal, of how 

its plan would achieve the state mass-based CO2 goal. This 

demonstration would include a projection of the total CO2

 

1024 For example, both the California and RGGI programs allow for 

the use of allowances awarded to GHG offset projects to be used 

to meet a specified portion of an affected emission source’s 

compliance obligation. The RGGI program contains a cost 

containment allowance reserve that makes available additional 

allowances up to a certain amount, at specified allowance price 

triggers. 

1025 A demonstration of how a plan will achieve a state’s ratebased or mass-based CO2 goal is one of the required plan 

components, as described in section VIII.D.2. 
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emissions from the fleet of affected EGUs that would occur as a 

result of compliance with the emission standards in the plan. 

Section VIII.D.2 discusses how such demonstrations could address 

design elements of emission budget trading programs with broader 

scope and additional compliance flexibility mechanisms, such as 

those included in the California and RGGI programs. Once the 

plan is implemented, if the mass-based CO2 goal is not achieved 

during a plan performance period, the backstop federally 

enforceable emission standards included in the state plan that 

apply to affected EGUs would be implemented, as described in 

section VIII.C.4.b.1026 

d. Legal basis for state measures plan type. The EPA believes 

the state measures plan type is consistent with CAA section 

111(d). Section 111(d)(1) requires a state to submit a plan that 

“(A) establishes standards of performance for any existing 

source for [certain] air pollutant[s] ... and (B) provides for 

 

1026 Achievement of the state mass-based CO2 goal would be 

determined based solely on stack CO2 emissions from affected 

EGUs. Where a state program includes the ability of an affected 

emission source to use GHG offsets to meet a portion of its 

allowance compliance obligation, no “credit” is applied to 

reported CO2 emissions by the affected EGU. The use of offset 

allowances or credits in such programs merely allows an affected 

EGU to emit a ton of CO2 in the amount of submitted offset 

allowances or credits. In all cases, there is no adjustment 

applied to reported stack emissions of CO2 from an affected EGU 

when determining compliance with its emission limit. 
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the implementation and enforcement of such standards of 

performance.” Section 111(d)(2)(A) indicates that the EPA must 

approve the state plan if it is “satisfactory.” 

Under theFor states that choose to adopt and submit a state 

measures plan, asuch state must submit a state plan that 

includes standards of performance for CO2 emissions from affected 

EGUs in the form of a federally enforceable backstop. in order 

to meet the requirements of section 111(d). Section 111(d) 

unambiguously allowsrequires a state to submit a plan that 

establishes standards of performance for certain sources, but 

does not mandate when such standards of performance must be in 

effect or implemented in order to meet applicable compliance 

deadlines. The EPA believes because the statute does not provide 

such a mandate, Instead, Congress has delegated to the EPA 

therefore has the discretion under section 111(d) to determine 

thedetermination of the appropriate effective date of standards 

of performance submitted under state plans to meet the 

requirements of this rule. Wheresection 111(d). In other words, 

where the statute is silent, the EPA has authority to provide a 

reasonable interpretation, under the U.S. Supreme Court’s 

decision in Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 842–844 

(1984).. The EPA’s interpretation is that for states that submit 

state plans establishing standards of performance under section 
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111(d), the effective date of such standards of performance may 

be later in time, perhaps indefinitely, for a number of reasons 

and under certain conditions. The Legal Memorandum discusses in 

more detail why theA key condition is that the state plan 

provides for the achievement of the required reduction by means 

other than the standards of performance on the timetable 

required by the BSER, with provision for federally enforceable 

standards of performance to be implemented if those other means 

fall short. The EPA believes it is reasonable to defer the 

effective date for standards of performance for affected EGUs as 

long as affected EGU CO2 emissions are projected to achieve, and 

do achieve, the requisite state goal. 

Section 111(d)(2)(B) also requires a state to submit a 

program that provides for the implementation and enforcement of 

the applicable standards of performance.Additionally, under the 

state measures plan type, if a state chooses to impose emission 

standards for the affected EGUs in conjunction with state 

measures that apply to other entities for any period prior to 

the triggering of the backstop, this final rule requires such 

emission standards to be submitted as federally enforceable 

measures included in the state plan. The EPA believes this is 

appropriate to help ensure the performance of a state measures 

plan will meet the requirements of this final rule. Section 
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111(d) clearly authorizes states to impose, and the EPA to 

approve, federally enforceable emission standards for affected 

EGUs. Though federally enforceable emission standards for 

affected EGUs in a state measures plan themselves would not 

necessarily achieve the requisite state goals, the EPA is 

authorized to approve state plans when they satisfactorily meet 

applicable requirements. The EPA can evaluate whether a state 

measures plan is satisfactory by determining whether any 

federally enforceable emission standards for affected EGUs in 

conjunction with state measures on other entities will result in 

the achievement of the requisite emissions performance level. As 

previously explained in this final rule, the performance rates 

and the state goals are the arithmetic expression of BSER as 

applied across affected EGUs in a state as a source category. In 

a state measures plan, the evaluation of whether a state 

measures plan is satisfactory goes to evaluating both the state 

measures and any federally enforceable emission standards on the 

affected EGUs to determine whether the plan as a whole will 

result in the affected EGUs achieving the applicable goals that 

reflect BSER. 

Section 111(d)(1)(B) also requires a state to submit a 

program that provides for the implementation and enforcement of 

the applicable standards of performance. Under the state 
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measures approach, this requirement regarding implementation is 

satisfied in part by the submission of an approvable trigger 

mechanism for the backstop and appropriate monitoring, reporting 

and recordkeeping requirements. The trigger mechanism provides 

for the “implementation” of the backstop, i.e.., the standards 

of performance, by putting the backstop into effect once the 

associated trigger is deployed. In other words, when the CO2

performance level under a state plan exceeds the trigger as 

described in section VIII.C.4.b, the emission standards that 

were submitted as the federally enforceable backstop and any 

attendant requirements must be implemented and in effect. The 

statutory requirement under CAA section 111(d)(2) regarding 

enforcement is also satisfied under the state measures plan type 

by the state submitting standards of performance sufficient to 

meet the requisite emission performance rates or state goal, in 

the form of the backstop, for inclusion as part of the federally 

enforceable state plan. 

Additionally, by requiring states that choose to impose 

emission standards on affected EGUs under the state measures 

approach to submit such emission standards for inclusion in the 

federally enforceable plan, this requirement further provides 

for implementation and enforcement as required by the statute. 

Regulating the affected EGUs through federally enforceable 
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emission standards themselves in conjunction with any state 

measures the state chooses to rely upon further assures the 

likelihood of the affected EGUs achieving the state goals as 

required under this rule and section 111(d). 

The state measures plan is a variation of the proposed 

portfolio approach in that both plan types allow the state to 

rely upon measures that impose requirements on sources other 

than affected EGUs in meeting the CO2 emission performance rates 

or requisite state CO2 emission performance goal. The state 

measures plan type differs fromis also a variation of the 

proposed portfoliostate commitment approach, however, in that 

the measures involving entities other than affected EGUs are not 

included as part of the federally enforceable 111(d) state plan, 

but the state may rely upon such measures that have the effect 

of reducing CO2 emissions from affected EGUs as a matter of state 

law. The EPA took comment on the proposed portfolio approach and 

state commitment approach, and on the utilization of measures on 

entities other than affected EGUs in meeting the requirements of 

the emission guidelines and CAA section 111(d), and). With 

respect to the proposed state commitment approach, the EPA 

received comments recommending that the EPA require a federally 

enforceable backstop with emission standards sufficient to 

achieve the requisite CO2 emission performance. The backstop 
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component the EPA is finalizing as part of the state measures 

plan type is consistent with the EPA’s statements in the 

proposal regarding states’ obligations under section 111(d) to 

establish emission standards for affected EGUs, as the backstop 

contains federally enforceable emission standards for affected 

EGUs that will achieve the requisite CO2 emission performance, 

and is consistent with comments received regarding the proposed 

state commitment approach. 

The state measures plan type the EPA is finalizing is also 

a logical outgrowth of the comments received on the proposed 

portfolio approach. As further explained below, legal questions 

remain as to whether state plans under section 111(d) can 

include federally enforceable measures that impose requirements 

on sources other than affected EGUs. However, a number of 

commenters and stakeholders expressed robust support for the 

ability to rely on measures and programs that do not impose 

requirements on affected EGUs themselves through plan types such 

as the proposed portfolio and state commitment approaches. The 

EPA is reasonably interpreting 111(d) as authorizing the state 

measures plan type, and believes this plan type is also 

responsive to, and accommodating of, states and stakeholders who 

have expressed the importance of being able to rely upon various 

measures that have the effect of reducing CO2 emissions from 
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affected EGUs. The EPA is finalizing the state measures plan 

type upon careful consideration of statutory requirements and 

comments received based on the proposed portfolio approach and 

state commitment approach. 

On May 20, 2015, theThe EPA additionally notes that the 

state measures plan type is not precluded by the recent Ninth 

Circuit Court of Appeals issued aAppeals’ decision in Committee 

for a Better Arvin et al. v. US EPA et al., Nos. 11-73924 and 

12-71332, that, at first glance, might be thought to conflict 

with the state measures approach. (May 20, 2015). The court held 

that the EPA violated the Clean Air ActCAA by approving a 

California state implementation plan (SIP) which relied on 

emission reductions from state-only mobile source standards 

(“waiver measures”) without including those standards in the 

SIP. The court first looked at the plain language of section 

110(a)(2)(A) of the ActCAA, which states that SIPs “shall 

include” the emission limitations and other control measures on 

which a state relies to comply with the ActCAA. The court then 

stated that the EPA’s action was also inconsistent with the 

structure of the ActCAA. The EPA has the primary responsibility 

to protect the nation’s air quality, but in the court’s view, 

the EPA itself would be unable to enforce the state-only 

standards. In addition, the court stated that the EPA’s action 
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was inconsistent with citizens’ right to enforce SIP provisions 

under section 304. 

There are a number of reasons why this decision does not 

preclude the state measures plan type. The Ninth Circuit’s 

textual analysis does not apply here, as the language of section 

110(a)(2)(A) does not control for 111(d) state plans. Section 

111(d)(1) requires state plans to “establish standards of 

performance” and to “provide for implementation and enforcement” 

of the standards of performance, but, unlike section 

110(a)(2)(A), section 111(d) does not specifically say that 

every emission reduction measure must be “included” in the state 

plan and be made federally enforceable. We interpretEven if 

section 111(d) did impose such requirements, the state measures 

approach to satisfy these requirements by establishingsatisfies 

them because the trigger is included in the plan as a federally 

enforceable implementation measure, and the backstop that is the 

standardincluded in the plan also contains standards of 

performance and providing for its implementation that reflect 

the BSER and enforcement through the federal enforceability of 

the trigger and backstop.are federally enforceable once they are 

triggered. 

The Ninth Circuit’s structural analysis also does not 

apply. The availability of the trigger and backstop gives the 
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EPA and citizens a federally enforceable route to ensure that 

all necessary emission reductions take place in order to achieve 

the standards of performance. This is markedly different than 

the state-only standards, where according to the Ninth Circuit, 

the EPA and citizens had no route to ensure that all necessary 

emission reductions took place in order to attain the NAAQS. In 

addition, case law suggests that federal enforceability for 

every requirement may not be necessary when there are sufficient 

federally enforceable requirements to satisfy the statute, see 

National Mining Ass'n v. United States EPA, 59 F.3d 1351 (D.C. 

Cir. 1995); in this case federal enforceability for the stateonly measures is not necessary to meet the statutory 

requirements of section 111(d)(1) as the federally enforceable 

trigger and backstop are sufficient. 

ed. Legal concernsconsiderations with proposed portfolio 

approach. The EPA is not finalizing the portfolio approach that 

was included in the proposed rulemaking, 79 FR 34830, 34902 

(June 18, 2014). In the proposal, the EPA noted that the 

portfolio approach raised legal questions. 79 FR 34830, 34902-

03. After reviewing comments, the EPA agrees with commenters 

that legal questions remain as to whether measures that impose 

federally enforceable requirements on entities other than 

affected EGUs either constitute “standards of performance” or 
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“provide[] for the implementation and enforcement of . . . 

standards of performance” under CAA section 111(d)(1). In 

addition, shortly after publication of the proposed rulemaking, 

the U.S. Supreme Court issued the UARG decision, which cautions 

against new extensions of CAA jurisdiction to large segments of 

the economy, and raises additional questions as to whether 

entities other than affected EGUs may be included in section 

111(d) plans and thereby subject to CAA enforcement authorities. 

Utility Air Regulatory GroupA number of commenters stated that 

the portfolio approach is unlawful because it exceeds the 

limitations that section 111(d)(1) places on state plans. Upon 

further review, we agree with these comments. v. EPA, 134 S. Ct. 

2427 (2014) (“UARG v. EPA”) 

 The state measures plan type the EPA is finalizing is a 

logical outgrowth of the comments received on the proposed 

portfolio approach. As previously explained, legal questions 

remain as to whether federally enforceable state plans under 

section 111(d) can include measures that impose requirements on 

sources other than affected EGUs. However, a number of 

commenters and stakeholders expressed robust support for the 

ability to rely on measures and programs that do not impose 

requirements on affected EGUs themselves. The EPA is reasonably 

interpreting 111(d) as authorizing the state measures plan type, 
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and believes this plan type is also responsive to, and 

accommodating of, states and stakeholders who have expressed the 

importance of being able to rely upon various measures that have 

the effect of resulting in CO2 reductions from affected EGUs. 

5. Multi-state plans 

 The EPA views the ability of a state to implement an 

individual plan or a multi-state plan as a significant 

flexibility that allows a state to tailor implementation of its 

plan to state policy objectives and circumstances. The EPA sees 

particular value in multi-state plans, which allow states to 

implement a plan in a coordinated fashion with other states. 

Such approaches can lead to more efficient implementation, lower 

compliance costs for affected EGUs and lower impacts on 

electricity ratepayers. Coordinated approaches also will help 

states identify and address any potential electric reliability 

impacts when developing plans. 

 The EPA received broad support in comments for allowing 

states to implement multi-state plan approaches, and has made 

multiple changes in the final rule to address many suggestions 

outlining different approaches states may want to take. These 

changes are intended to provide streamlined approaches for 

multi-state coordination while maintaining transparency and 

assuring that the CO2 emission performance rates or state CO2
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emission goals are achieved. 

 The EPA is finalizing two approaches that allow states to 

coordinate implementation in order to meet the emission 

guidelines.1027

 First, states may meet the requirements of the emission 

guidelines and CAA section 111(d) by submitting multi-state 

plans that address the affected EGUs in a group of states. The 

EPA is finalizing the proposed approach by which multiple states 

aggregate their rate or mass CO2 goals and submit a plan that 

will achieve a joint CO2 emission goal for the fleet of affected 

EGUs located within those states. 

 Second, the EPA is also finalizing another approach, in 

response to comments received on the proposed rule. This 

approach enables states to retain their individual state goals 

for affected EGUs and submit individual plans, but to coordinate 

plan implementation with other states through the interstate 

transfer of ERCs or emission allowances. This approach 

facilitates interstate emission trading without requiring states 

 

1027 The EPA notes that in addition to these approved approaches, 

other types of multi-state approaches may be acceptable in an 

approvable plan, provided the obligations of each state under 

the multi-state plan are clear and the submitted plan(s) meets 

applicable emission guideline requirements. 
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to submit joint plans.1028 

 States have the option to implement this second approach in 

different ways, as discussed in section VIII.C.5.c. These 

different implementation options allow states to tailor their 

implementation of linked emission trading programs, based on 

state policy preferences, as well as economic and other 

considerations. These different options provide varying levels 

of state control over emission trading system partners and 

require varying levels of coordination in the course of state 

plan development. 

 In response to comments, the EPA is also further clarifying 

how multi-state plans with a joint goal for affected EGUs may be 

implemented. The EPA is clarifying that states may participate 

in more than one multi-state plan, if necessary, for example, to 

address affected EGUs in states that are served by more than one 

ISO or RTO. The EPA is further clarifying that a subset of 

affected EGUs in a state may participate in a multi-state plan. 

These clarifications are discussed in section VIII.C.5.d. 

a. Summary of comments on multi-state plans. Multiple commenters 

supported the EPA’s proposed approach that allows states to 

 

1028 States may submit individual plans with such linkages, or if 

they choose, provide a joint submittal. Forms of joint 

submittals are described at section VIII.E. 
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implement a multi-state plan to meet a joint CO2 emission goal. 

However, a number of states commented that states should also be 

allowed to coordinate without aggregating multiple individual 

state goals into a single joint goal. Many states questioned the 

incentives that a state would have to aggregate its goal with 

other states that have different goals. 

 The EPA notes that there are multiple incentives for states 

to collaborate by implementing a multi-state plan to meet an 

aggregated joint goal, regardless of the specific level of their 

individual goals, because states share grid regions and impacts 

from plan implementation will be regional in nature. Further, 

multiple analyses, including those by ISOs and RTOs, indicate 

that regional approaches could achieve state goals at lesser 

cost than individual state plan approaches. However, the EPA 

also recognizes the value in allowing for collaboration where 

states retain individual goals. These approaches could provide 

some of the benefits of a joint goal while reducing the 

negotiations among states necessary to develop a multi-state 

plan with a joint goal. As a result, the EPA has finalized the 

additional approaches described above in section VIII.C.5 to 

provide for coordination while maintaining individual goals. 

These approaches would allow for interstate transfer of ERCs or 

emission allowances while retaining individual state goals. 
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 Many commenters suggested that states should be encouraged 

to join or form regional market-based programs. Many commenters 

touted the economic efficiency benefits of such approaches, and 

noted that such programs have features that support electric 

reliability. 

 The EPA agrees with these comments, and notes that it 

encouraged such approaches in the proposal. While the EPA is not 

requiring states to join and/or form regional market-based 

programs, we note that such programs can be helpful for many 

reasons, including features that support reliability. Marketbased programs allow greater flexibility for affected EGUs both 

in the short-term and long-term. Under a market-based program, 

affected EGUs have the ability to obtain sufficient allowances 

or credits to cover their emissions in order to comply with 

their emission limits. Additionally, we continue to encourage 

states to cooperate regionally. Regional cooperation in planning 

and reliability assessments is an important tool to meeting 

system needs in the most cost-effective, efficient, and reliable 

way. 

b. Multistate coordination through a joint emission goal. 

Multiple states may submit a multi-state plan that achieves an 

aggregated joint CO2 emission goal for the affected EGUs in the 
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participating states.1029 The joint emission goal approach is 

acceptable for both types of state plans, the “emission 

standards” plan type and the “state measures” plan type. 

However, the EPA is requiring that a joint goal may apply only 

to states implementing the same type of plan, either an 

“emission standards” plan or a “state measures” plan.1030 

 Under this approach, a rate-based multi-state plan would 

 

1029 As a conceptual and legal matter, the relationship between 

states coordinating to meet a joint CO2 emission goal under this 

rule is similar to the relationship between states coordinating 

SIP submissions to attain the NAAQS in an interstate 

nonattainment area. In both cases, the states coordinate their 

actions in a way that, cumulatively, the measures applicable in 

each state will lead to achievement of a common interstate goal 

(with the EPA evaluating the sufficiency and success of the 

plans on a holistic, interstate basis). Despite the shared goal, 

in both cases, the mere fact of coordination has no effect on 

each state’s sovereign legal authority. For example, the legally 

applicable rules in a given state are adopted by that state 

individually, not by a joint entity or other interstate 

mechanism. Similarly, the fact that the states coordinate their 

rules does not grant them the authority to directly enforce each 

other’s rules, or to take direct legal action against a state 

that is failing to implement its own rules. Although some states 

may jointly submit their coordinated rules to the EPA as a 

matter of administrative convenience, the state rules within 

such a plan are nothing more than reciprocal laws of the sort 

that states routinely enact in voluntary coordination with each 

other. 

1030 This is necessary because if the joint goal is not achieved 

during a plan performance period, different remedies would apply 

under an emission standards plan and a state measures plan. 

Under an emission standards plan, corrective measures would 

applybe triggered. Under a state measures plan, the federally 

enforceable backstop emission standards would be triggered. See 

section VIII.F.3. 
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include a weighted average rate-based emission goal, derived by 

calculating a weighted average CO2 emission rate based on the 

individual rate-based goals for each of the participating states 

and 2012 generation from affected EGUs. A mass-based multi-state 

plan would include an aggregated mass-based CO2 emission goal for 

the participating states, in cumulative tons of CO2, derived by 

summing the individual mass-based CO2 emission goals of the 

participating states. 

 Such plans could include emission standards in the form of 

a multi-state rate-based or mass-based emission trading 

program.1031 Alternatively, states could submit a multi-state plan 

using a state measures approach.1032 Both approaches could provide 

for implementation of a multi-state rate-based or mass-based 

emission trading program. 

c. Multi-state coordination among states retaining individual 

 

1031 A potential example of this approach is the method by which 

the states participating in RGGI have implemented individual CO2

Budget Trading Program regulations in a linked manner using a 

shared emission and allowance tracking system. Each state’s 

regulations implementing RGGI stand alone on a legal basis, but 

provide for the use of CO2 allowances issued in other 

participating states for compliance under the state regulations. 

These states are not listed by name in state regulations, which 

instead refer to participating states that have established a 

corresponding CO2 Budget Trading Program regulation. More 

information is available at http://www.rggi.org. 

1032 Under this approach, a state measure could include, if a 

state chose, a multi-state emission trading program that is 

enforceable at the state level. 
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state goals. States that do not wish to pursue a joint CO2

emission goal with other states may pursue a second pathway to 

multi-state collaboration. States may submit plans that will 

meet an individual state goal for affected EGUs, but include 

implementation in coordination with other state plans by 

providing for the interstate transfer of ERCs or CO2 allowances, 

depending on whether the state is implementing a rate-based or 

mass-based emission trading program. This form of coordinated 

implementation may occur under both an “emission standards” type 

of plan and a “state measures” type of plan, where states are 

implementing rate-based or mass-based emission trading 

programs.1033

 Under this approach, a state plan could indicate that ERCs 

or CO2 allowances issued by other states with an EPA-approved 

state plan could be used by affected EGUs for compliance with 

the state’s rate-based or mass-based emission standard, 

respectively. Such plans must indicate how ERCs or emission 

allowances will be tracked from issuance through use by affected 

 

1033 ERCs may only be transferred among states implementing ratebased emission limits. Likewise, emission allowances may only be 

transferred among states implementing mass-based emission 

limits. 
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EGUs for compliance,1034 through either a joint tracking system, 

interoperable tracking systems, or an EPA-administered tracking 

system.1035 

 The EPA would assess the approvability of each state’s plan 

individually — the use of ERCs or emission allowances issued in 

another state would not impact the approvability of the 

components of the individual state plan.1036 However, the EPA 

would also assess linkages with other state plans, to ensure 

that the joint tracking system or interoperable tracking systems 

used to implement rate-based or mass-based emission trading 

programs across states are properly designed with necessary 

components, systems, and procedures to maintain the integrity of 

 

1034 Referred to in different programs as “surrender,” 

“retirement,” or “cancellation.” 

1035 The EPA received a number of comments from states and 

stakeholders about the value of the EPA’s support in developing 

and/or administering tracking systems to support state 

administration of rate-based emission trading programs. The EPA 

is exploring options for providing such support and is 

conducting an initial scoping assessment of tracking system 

support needs and functionality.

1036 Note that for mass-based plans, the approvability 

requirements for a state plan would differ, depending on the 

structure of the emission budget trading program included in the 

state plan. For example, approvability requirements and basic 

accounting with regard to whether a plan achieves a state’s mass 

CO2 goal would differ for emission budget trading programs that 

cover only affected EGUs subject to CAA section 111(d) vs. 

programs that apply to a broader set of emission sources. These 

considerations are addressed in subsectionsection 

VIII.C.5.c.(2)(c).J. 
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the linked emission trading programs. 

(1) Multi-state coordination: rate-based emission trading 

programs. Individual rate-based state plans may provide for the 

interstate transfer of ERCs, which would enable an ERC issued by 

one state to be used for compliance by an affected EGU with a 

rate-based emission standard in another state. Such plans would 

include regulatory provisions in each state’s emission standard 

requirements that indicate that ERCs issued in other partner 

states may be used by affected EGUs for compliance. Such plans 

must indicate how ERCs will be tracked from issuance through use 

for compliance, through either a joint tracking system, 

interoperable tracking systems, or an EPA-administered tracking 

system.1037

When demonstrating that a state’s CO2 emission goal is 

achieved as a result of plan implementation, a state with 

linkages to other states would be required to demonstrate that 

any ERCs issued by another state that are used by affected EGUs 

 

1037 The emission standards in each individual state plan must 

include regulatory provisions that address the issuance of ERCs 

and tracking of ERCs from issuance through use for compliance, 

as described in subsectionsection VIII.G.3K.2. The description 

here addresses how those regulatory provisions will be 

implemented through the use of a joint tracking system, 

interoperable tracking systems, or an EPA-administered tracking 

system. 
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in the state for compliance with its rate-based CO2 emission 

standards were issued by states with an EPA-approved state 

plan.1038

 States could implement these linkages among state plans 

with rate-based emission trading systems through three different 

applied implementation approaches: (1) plans that are “readyfor-interstate-trading;” (2) plans that include specified 

bilateral or multilateral linkages; and (3) plans that provide 

for joint ERC issuance among states with materially consistent 

regulations. These approaches are summarized below: 

 Ready-for-interstate-trading plans: A state plan recognizes 

ERCs issued by any state with an EPA-approved plan that 

also uses a specified EPA-approved1039 or EPA-administered 

tracking system. Plans are approved individually. A state 

plan need not designate the individual states by name from 

which it would accept issued ERCs. States can join such a 

coordinated approach over time, without the need for plan 

 

1038 This could be done by reference to data in the tracking 

system used to implement a state’s rate-based emission trading 

program that identifies the origin of each ERC (e.g., by serial 

identifier). 

1039 The EPA would designate tracking systems that it has 

determined adequately address the integrity elements necessary 

for the issuance and tracking of ERCs, as described in 

subsectionsection VIII.C.5.c.(1).K.2. Under this approach, a 

state could include in its plan such a designated tracking 

system, which has already been reviewed by the EPA. 
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revisions.

 Specified bilateral linkage: States recognize ERCs issued 

by named partner states. Partner states must demonstrate 

that they use a shared tracking system, interoperable 

tracking systems, or an EPA-administered tracking system. 

Plans are approved individually, including review of the 

shared tracking system or interoperable tracking systems. 

 Joint ERC issuance: States implement materially consistent 

rate-based emission trading program regulations and share a 

tracking system. States coordinate their review of 

submissions for ERC issuance1040 and their issuance of ERCs 

to the shared tracking system. Issued ERCs are recognized 

as usable for compliance in all states using the shared 

tracking system. Plans are approved individually, including 

review of the shared tracking system. 

 These implementation approaches are designed to streamline 

the process for linking emission trading programs, avoid or 

 

1040 This refers to eligibility applications and monitoring and 

verificationM&V reports, which are required submittals for nonaffected EGU entities seeking the issuance of ERCs. Where 

affected EGUs are issued ERCs for emission performance below a 

specified CO2 emission rate, these ERCs are issued by the 

individual state in which they are subject to a rate-based 

emission standard. Requirements for ERC issuance are discussed 

in subsectionsection VIII.G.3K.2. 
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limit the need for plan revisions as new states join a 

collaborative emission trading approach, and facilitate the 

development of regional or broader multi-state markets for 

ERCs.1041 

(2) Multi-state coordination: mass-based emission trading 

programs. An individual state may provide for the use of CO2

allowances issued by another state(s) for compliance with the 

mass-based emission standards in its plan. This type of state 

plan would include regulatory provisions that enable affected 

EGUs to use allowances issued in other states for compliance 

under the state’s emission budget trading program. This type of 

state plan must also indicate how CO2 allowances will be tracked 

from issuance through use for compliance, through either a joint 

tracking system, interoperable tracking systems, or use of an 

 

1041 The EPA also notes that individual state plans may utilize RE 

and demand-side EE (and other eligible measures), that occur in 

other states, as described in section VIII.G.1L addressing 

interstate effects. Under an individual state plan, ERCs could 

be issued for RE and demand-side EE measures that occur in other 

states, provided the EE/RE provider submits the measures to the 

state and the measures meet requirements in the state’s ratebased emission trading program requirements. The multi-state 

approaches described above provide additional flexibility for 

states to informally and formally coordinate their 

implementation of rate-based plans across states while retaining 

individual rate-based state goals. 
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EPA-administered tracking system.1042 

 Two different implementation approaches could be used to 

create such links. A state could submit a “ready-for-interstatetrading” plan using an EPA-approved tracking system, but the 

plan would not identify links with other states. A state could 

also submit a plan with specified bilateral or multilateral 

links that explicitly identify partner states. 

 Interstate allowance linkages would not affect the 

approvability of each state’s individual plan. However, 

different considerations apply for the approvability of an 

individual plan with such links, based on whether the emission 

budget trading program in the plan applies only to affected EGUs 

or includes other emission sources. These considerations are 

discussed in section VIII.B.5.c.(2)(a) below. 

 Under the first “ready-for-interstate-trading” 

implementation approach, a state would indicate in its state 

plan that its emission budget trading program will be 

 

1042 The emission standards in each individual state plan must 

include regulatory provisions that address the issuance of CO2

allowances and tracking of CO2 allowances from issuance through 

use for compliance, as described in subsection 

VIII.C.3.b.(2)(c).. The description here addresses how those 

regulatory provisions will be implemented through the use of a 

joint tracking system, interoperable tracking systems, or an 

EPA-administered tracking system. 
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administered using an EPA-approved (or EPA-administered) 

emission and allowance tracking system.1043 State plans using a 

specified EPA-approved tracking system would be deemed by the 

EPA as ready for interstate linkage upon approval of the state 

plan. No additional EPA approval would be necessary for states 

to link their emission budget trading programs, and affected 

EGUs in those states could engage in interstate trading 

subsequent to EPA plan approval. 

 A state would indicate in its plan submittal that its 

emission budget trading system will use a specified EPA-approved 

tracking system. The state would also indicate in the regulatory 

provisions for its emission budget trading program that it would 

recognize as usable for compliance any emission allowance issued 

by any other state with an EPA-approved state plan that also 

uses the specified EPA-approved tracking system. 

 States could also adopt such a collaborative emission 

trading approach over time (through appropriate state plan 

revisions if the plan is not already structured as ready-for-

 

1043 The EPA would designate tracking systems that it has 

determined adequately address the integrity elements necessary 

for the issuance and tracking of emission allowances, as 

described in subsection VIII.C.5.c.(2).. Under this approach, a 

state could include in its plan such a designated tracking 

system, which has already been reviewed by the EPA. 
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interstate-trading), without requiring all of the existing 

participating states to revise their EPA-approved plans. 

 Under the second implementation approach, a state could 

specify the other states from which it would recognize issued 

emission allowances as usable for compliance with its emission 

budget trading program. The state would indicate in the 

regulatory provisions for its emission budget trading program 

that emission allowances issued in other identified partner 

states may be used by affected EGUs for compliance. Such plans 

must indicate how allowances will be tracked from issuance 

through use for compliance, through either a joint tracking 

system, interoperable tracking systems, or EPA-administered 

tracking system. The EPA would assess the design and 

functionality of this tracking system(s) when reviewing 

individual submitted state plans. 

 Under this approach, states could also join such a 

collaborative emission trading approach over time. However, all 

participating states would need to revise their EPA-approved 

plans. If the expanded linkage is among previously approved 

plans with mass-based emission standards, approval of the plan 

revision would be limited to assessing the functionality of the 

shared tracking system or interoperable tracking systems in 
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order to maintain the integrity of the linked programs.1044 

(a) Considerations for linked emission budget trading programs. 

For individually submitted plans, interstate emission allowance 

linkages would not affect the approvability of each state’s 

plan. However, approvability of an individual linked plan would 

differ based on the structure of the emission budget trading 

program included in the plan. These differences for plan 

approvability address distinctions among programs that include 

only affected EGUs and programs that cover a broader set of 

emission sources. Differences in approval criteria are necessary 

to ensure that each individual state plan demonstrates it will 

achieve a state’s mass-based CO2 emission goal for affected EGUs. 

The accounting applied to individual plans to assess whether a 

state achieves its mass-based CO2 goal will also differ, based on 

whether an emission budget trading program includes only 

affected EGUs or a broader set of emission sources. These 

considerations are addressed below, for both types of emission 

budget trading programs. 

(i) Links among emission budget trading programs that only 

 

1044 Depending on the specific regulatory provisions in the 

emission standards in their approved state plans, participating 

states may also need to revise their implementing regulations 

(and by extension their state plans) to accept CO2 emission 

allowances issued by new partner states as usable for compliance 

with their mass-based emission standards. 
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include affected EGUs. Where the emission budget trading 

programs in each plan apply only to affected EGUs subject to CAA 

section 111(d), and include compliance timeframes that align 

with the interim and final plan performance periods, both plans 

would functionally be meeting an aggregated multi-state massbased goal, but without formally aggregating the goal. CO2

emissions from affected EGUs in both states could not exceed the 

total combined CO2 emission budgets under the emission standards 

in the two states. A net “import” of CO2 allowances from one 

state would mean that allowable CO2 emissions in the other net 

“exporting” state are less than that state’s established 

emission budget. On a multi-state basis, CO2 emissions from 

affected EGUs could not exceed the sum of the states’ emission 

budgets. 

 Under this approach, if the emission budget for the massbased emission standard in each plan is equal to or lower than 

the state’s mass-based CO2 goal, compliance by affected EGUs with 

the mass emission standard in a state1045 would ensure that 

cumulatively the mass CO2 goals of the linked states are 

achieved. As a result, achievement of an individual state’s mass 

 

1045 Compliance by an affected EGU with the emission standard is 

demonstrated based on surrender to the state of a number of CO2

allowances equal to its reported CO2 emissions. 
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CO2 goal would be assessed by the EPA based on compliance by 

affected EGUs with the mass-based emission standards in the 

state plan, rather than reported CO2 emissions by affected EGUs 

in the state.1046

 The same accounting approach will apply for such plans in 

all cases, even if the state is linked to another state emission 

budget trading program that includes a broader set of emission 

sources, as described below. In all cases, where a state plan 

includes an emission budget trading program that applies only to 

affected EGUs, and includes compliance timeframes that align 

with plan performance periods, achievement of a state mass CO2

goal will be assessed by the EPA based on whether affected EGUs 

comply with the mass-based emission standard, rather than 

reported CO2 emissions from affected EGUs. 

(ii) Links with emission budget trading programs that include a 

broader set of emission sources. State plans may include 

emission budget trading programs that include affected EGUs as 

well as other non-affected emission sources.1047 

 

1046 This approach is warranted because under such linked 

programs, CO2 emissions from affected EGUs in one state that 

exceed a state’s mass CO2 goal would be accompanied by CO2

emissions from affected EGUs in another linked sate that are 

below that state’s mass CO2 goal. 1047 This may apply under both an emission standards plan and a 

state measures plan. 
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 Generally, as described in section VIII.C.3-4 above, such 

plans must demonstrate that the mass-based CO2 goal for affected 

EGUs in a state will be achieved, as a result of implementation 

of the emission budget trading program.1048 Where such a program 

is linked with other programs, the state plan must include a 

demonstration that the mass-based CO2 goal will be achieved, 

considering the emission allowance links with other programs. 

The EPA, in determining the approvability of each state’s plan 

under this approach, would evaluate the linkages between plans. 

Specifically, the EPA would evaluate whether the linkages would 

enable the EGUs in each participating state to meet the state’s 

applicable mass-based CO2 goal. 

 During plan implementation, the EPA would assess whether 

the affected EGUs in a state achieved the state’s mass-based CO2

goal as follows. Reported CO2 emissions from affected EGUs under 

such plans must be at or below a state’s mass-based CO2 emission 

goal during an identified plan performance period, with the 

following state accounting adjustments for net “import” and net 

 

1048 Under a program that applies to affected EGUs and other 

emission sources, compliance by affected EGUs with the emission 

standard – a requirement to surrender emission allowances equal 

to reported emissions – will not assure that a state’s CO2 mass 

goal is achieved. As a result, a further demonstration is 

required in the plan that compliance by affected EGUs with the 

program will result in CO2 emissions from affected EGUs that are 

at or below a state’s CO2 mass goal. 
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“export” of CO2 allowances: 

 Net “imports” of CO2 allowances: Reported CO2 emissions from 

affected EGUs in a state may exceed the state CO2 mass goal 

during an identified plan performance period in the amount 

of an adjustment for the net “imported” CO2 allowances 

during the plan performance period. The adjustment 

represents the CO2 emissions (in tons) equal to the number 

of net “imported” CO2 allowances.1049 Under this adjustment, 

such allowances must be issued by a state with an emission 

budget trading program that only applies to affected EGUs.

Net “imports” of allowances are determined through review 

of tracking system compliance accounts. 

 Net “exports” of CO2 allowances: Reported CO2 emissions from 

affected EGUs in a state during an identified plan 

performance period must be equal to or less than the CO2

mass goal minus an adjustment for the “exported” CO2

allowances during the plan performance period. The 

adjustment represents CO2 emissions (in tons) equal to the 

number of net “exported” CO2 allowances. Net “exports” of 

allowances are determined through review of tracking system 

compliance accounts. 

 

1049 Net “imports” and “exports” of CO2 allowances are defined and 

explained below. 
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 Where CO2 emissions from affected EGUs exceed these levels 

(based on reported CO2 emissions with applied plus or minus 

adjustments for net CO2 allowance “imports” or “exports”) by 10 

percent or more, a state would be considered to not have met its 

CO2 mass goal during an identified plan performance period. As a 

result, under a state measures state plan, implementation of the 

backstop federally enforceable emission standards for affected 

EGUs in the state plan would be triggered. 

 A net transfer of CO2 allowances during a plan performance 

period represents the net number of CO2 allowances (issued by a 

respective state) that are transferred from the compliance 

accounts of affected EGUs in that state to the compliance 

accounts of affected EGUs in another state.1050 This net transfer 

 

1050 A net transfer metric is applied as of the end of the plan 

performance period. This net accounting as of a specified date 

is necessary because multiple individual allowance transfers may 

occur among accounts during a plan performance period, 

representing normal trading activity. In addition, net transfers 

are based on compliance account holdings, because these 

represent the CO2 allowances directly available at that point in 

time for use by an affected EGU for complying with its emission 

limit. Emission budget trading programs typically allow nonaffected entities to hold allowances in general accounts. These 

parties are free to hold and trade CO2 allowances, providing 

market liquidity. General account holdings are not assessed as 

part of a periodic state net transfer accounting, as these 

allowances may subsequently be transferred to other accounts in 

multiple states and do not represent allowances currently held 

by an affected EGU that can be used for complying with its 

emission limit. 
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is determined based on compliance account holdings at the end of 

the plan performance period.1051 For example, assume two states, 

State A and State B, with emission budgets of 1,000 tons of CO2. 

Each state issues 1,000 CO2 allowances. At the end of a plan 

performance period, affected EGUs in State A collectively hold 

500 CO2 allowances in their compliance accounts that were issued 

by State A. Affected EGUs in State B collectively hold in their 

compliance accounts 500 CO2 allowances issued by State A and 

1,000 CO2 allowances issued by State B. In this simplified 

example, a net transfer of 500 CO2 allowances has occurred 

between State A and State B. State A has “exported” 500 CO2

allowances to State B, while State B has “imported” 500 CO2

allowances from state A.

d. Multi-state plans that address a subset of EGUs in a state. 

The EPA is clarifying in the final emission guidelines that a 

state may participate in more than one multi-state plan. Under 

this approach, the state would identify in its submittal the 

subset of affected EGUs in the state that are subject to the 

multi-state plan or plans. This could involve a subset of 

 

1051 Compliance account holdings, as used here, refer to the 

number of CO2 allowances surrendered for compliance during a plan 

performance period, as well as any remaining CO2 allowances held 

in a compliance account as of the end of a plan performance 

period. 
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affected EGUs that are subject to a multi-state plan, with the 

remainder of affected EGUs subject to a state’s individual plan. 

Alternatively, different affected EGUs in a state may be subject 

to different multi-state plans. In all cases, the state would 

need to identify in each specific plan which affected EGUs are 

subject to such plan, with each affected EGU subject to only one 

multi-state plan or subject only to the state’s individual plan 

(if relevant). 

 These scenarios may occur where a state chooses to subject 

affected EGUs in different ISOs or RTOs to different multi-state 

plans. This will provide states with flexibility to participate 

in multi-state plans that address the affected EGUs in a 

respective grid region, in the case where state borders cross 

grid regions. 

 These scenarios may also occur where a state is served by 

multiple vertically integrated electric utilities with service 

territories that cross state lines. This will provide states 

with flexibility to participate in multi-state plans that 

address the affected EGUs owned and operated by a utility with a 

multi-state service territory. 

Section 111(d)(1) provides that state plans shall 

“establish[] “standards of performance for any existing source” 

and “provide[] for the implementation and enforcement of . . . 
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standards of performance” under CAA section 111(d)(1). Although 

in the proposal we identified possible interpretations of 

section 111(d)(1) that could justify the proposed portfolio 

approach, after reviewing the comments, we are not adopting 

those interpretations. Because section 111(d)(1) specifically 

requires state plans to include only (A) standards for emissions 

imposed on affected sources and (B) measures that implement and 

enforce such standards,1052 we interpret it as allowing federal 

enforceability only of requirements or measures that are in 

those two specifically required provisions. We therefore do not 

interpret the term “implementation of ... such standards of 

performance” to authorize the EPA to approve state plans with 

obligations enforceable against the broad array of non-emitting 

entities that would have been implicated by the portfolio 

approach. Thus, the EPA is not finalizing the portfolio 

approach, and in the event that states submit such measures to 

the EPA for inclusion in the state plan, the EPA would not 

approve them into the state plan and therefore would not make 

them federally enforceable. 

We note that section 111(d) limits on federal 

enforceability of requirements against non-affected sources do 

 

1052 Such measures include, for example, in this rule, 

requirements for ERCs.
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not imply that the BSER cannot be based on actions by nonaffected sources. As discussed in section V, the BSER may be 

based on the ability of owners/operators of affected sources to 

engage in commercial relationships with a wide range of other 

entities, from the vendors, installers, and operators of air 

pollution control equipment to, in this rulemaking, 

owners/operators of RE. 

 The EPA notes it is also not finalizing the proposed state 

commitment approach or state crediting approach. The EPA 

believes the finalized state measures plan type provides states 

with the same flexibilities as would have been allowed under 

these two proposed approaches, and does so in a way that is 

legally supportable by the CAA. Therefore, the EPA does not 

believe it necessary to finalize the state commitment approach 

or state crediting approach. 

e. Legal issues regardingbasis for multi-state plans. While 

nothing in section 111(d)(1) explicitly authorizes either states 

to adopt and submit multi-state plans and for, or the EPA to 

approve them as satisfactory, nothing in section 111(d)(1) 

explicitly prohibits thisit, either. In addition, nothing in 

section 111(d)(2)(A)’s standard of “satisfactory” prohibits the 

EPA from considering multi-state plans as satisfactory. There is 

thus a gap that the EPA may reasonably fill. 
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In light of the purpose of these emission guidelines, to 

reduce emissions of a pollutant that globally mixes in the 

stratosphere, and the mechanisms to reduce those emissions, 

which may have beneficial effects across state lines, it is 

reasonable to allow for multi-state plans. Thus, our gap-filling 

interpretation of section 111(d) in this context is reasonable. 

D. State Plan Components and Approvability Criteria 

1. Approvability Criteriacriteria

In the “Criteria for Approving State Plans” section of the 

preamble to the June 2014 proposal (section VIII.C), the EPA 

proposed the following as necessary components of an approvable 

state plan: 

1. The plan must contain enforceable measures that reduce 

EGU CO2 emissions; 

2. The enforceable measures must be projected to achieveCO2

emission performance by affected EGUs must be equivalent to or 

better than the applicablerequired CO2 emission performance rates 

or state-specific CO2 goal on a timeline equivalent to thatlevel

in the emissions guidelinesstate plan; 

3. The EGU CO2 emission performance must be quantifiable and 

verifiable; 

4. The plan must include a process for state reporting of 

plan implementation, CO2 emission performance outcomes, and 
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implementation of corrective measures, if necessary. 

After reviewing the comments we received concerning the 

approvability criteria, the EPA has decided against maintaining 

the four proposed approvability criteria separately from the 

list of components required for an approvable plan, which may be 

confusing and potentially redundant. The EPA has determined that 

a satisfactory state plan that meets the required plan 

components discussed below will inevitably meet the proposed 

approvability criteria. The EPA, therefore, has incorporated the 

proposed approvability criteria into the section titled 

“Components of a state plan submittal” (section VIII.D.2 below), 

which results in). There is no functional change in the 

approvability criteria or the components of a state plan 

addressed in the proposal. We do not expect; they are simply 

combined and this change todoes not have a substantive effect on 

state plan development or approval. 

Under the proposed “Enforceable Measures” criterion 

(section VIII.C.1 of the proposal preamble), the EPA 

specifically requested comment on the appropriateness of 

applying existing EPA guidance on enforceability to state plans 

under CAA section 111(d), considering the types of entities that 
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might be included in a state plan.1053 

The EPA also requested comment on whether the agency should 

provide guidance on enforceability considerations related to 

requirements in a state plan for entities other than affected 

EGUs, and if so, what types of entities. Comments received 

strongly suggested that the EPA provide guidance on 

enforceability considerations for non-EGU affected entities, 

particularly for RE and EE. Comments also requested additional 

guidance specific to this rulemaking, including examples of 

enforceable measures for specific activities, such as solar 

thermal programstechnologies, waste heat recovery, net-metering 

energy savings and state RPSsRPS. 

These enforcement considerations arose primarily under the 

proposed portfolio approach for state plans., which would have 

allowed state plans to include federally enforceable measures 

that apply to entities that are not affected EGUs. In this 

action, the EPA is finalizing the state measures approach 

 

1053 The existing guidance documents referenced were: (1) 

September 23, 1987 memorandum and accompanying implementing 

guidance, “Review of State Implementation Plans and Revisions 

for Enforceability and Legal Sufficiency;”,” (2) August 5, 2004 

“Guidance on SIP Credits for Emission Reductions from ElectricSector Energy Efficiency and Renewable Energy Measures;”,” and 

(3) July 2012 “Roadmap for Incorporating Energy 

Efficiency/Renewable Energy Policies and Programs into State and 

Tribal Implementation Plans, Appendix F.”
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instead of the portfolio approach described in the proposed 

rule. As explained in section VIII.C, the EPA is not finalizing 

the portfolio approach,, under which would have alloweda state 

plan submittals to include can rely upon measures that are not 

federally enforceable measures that as long as the plan also 

includes a backstop of federally enforceable emission standards 

that apply to entities that are not affected EGUs. However, asAs

explained in depth in section VIII.C, if the state is adopting 

the state measures approach, the state plan submittal will need 

to specify, in the supporting materials, the state -enforceable 

measures that the state is relying upon, in conjunction with any 

federally enforceable emission standards for affected EGUs, to 

meet the emission guidelines. As part of the state measures 

approach, the EPA is finalizing a requirement for a federally 

enforceable backstop, which requires the affected EGUs to meet 

emission standards that fully achieve the CO2 emission 

performance rates or the state’s CO2 emission goal if the state 

measures do not meet the intended emission performance levels. 

Because the EPA is not finalizing the portfolio approach, which 

would have allowed states to include federally enforceable 

measures in a state plan that apply to entities that are not 

affected EGUs, the agency is not providing additional guidance 

on federal enforceability of measures that might apply to such 
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entities. As proposed, we are requiring that state plans include 

a demonstration that plan measures are enforceable, which for 

emission standard plansstandards plan types is discussed in 

section VIII.D.2.b.43 below and for state measures plansplan 

types is discussed in section VIII.D.2.c.6 below. 

Commenters also requested that the EPA allow states to rely 

on provisions with flexible compliance mechanisms in state plans 

and clarify how to address flexible compliance mechanisms when 

demonstrating achievement of thea state CO2 emission goal. 

Additionally, a commenter requested that the enforceability 

mechanisms that the EPA requires in state plans should support 

existing programs, as well as new programs in other states, by 

minimizing program changes required purely to conform with 

federal requirements, while still providing enough additional 

program review and accounting to ensure that CO2 emission 

reductions are achieved. These and related comments contributed 

to the EPA’s decision to finalize the option for states to 

submit a state measures plan, which would be comprised, at least 

in part, of measures implemented by the state that are not 

included as federally enforceable components of the plan, with a 

backstop of federally enforceable emission standards for 

affected EGUs that fully meet the emission guidelines and that 

would be triggered if the plan failed to achieve the CO2 emission 
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performance levels specified in the plan on schedule. For more 

information on the state measures plan approach, see section 

VIII.C.43 of this preamble above. 

2. Components of a state plan submittal 

In this action, the EPA is finalizing that a state plan 

submittal must include the components described below. TheAs a 

result of constructive comments received from many commenters 

and additional considerations, the EPA is finalizing state plan 

components that are responsive to that input and are appropriate 

for the types of state plans allowed in the final emission 

guidelines. A state plan submittal must also be consistent with 

additional specific requirements elsewhere in this final rule 

and with the EPA implementing regulations at 40 CFR 60.23-60.29, 

except as otherwise specified by this final rule. These 

requirements apply to both individual state plan submittals and 

multi-state plan submittals. When a state plan submittal is 

approved by the EPA, the EPA will codify the approved CAA 

section 111(d) state plan in 40 CFR part 62. Section VIII.D.3 

discusses the components of thea state plan submittal that would 

be codified as the state CAA section 111(d) plan when the state 

plan submittal is approved by the EPA. 

The EPA is finalizing that states can choose to meet the 

emission guidelines through one of two types of state plans: an 
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Page 1252 of 2153

“emission standards approach” plan type or a “state measures 

approach” plan. States may also type. A state pursuing the 

emission standards plan type may opt to submit a plan that meets 

the CO2 emission performance rates for affected EGUs or achieves 

ameets the state rate-based or mass-based CO2 emission goal. for 

affected EGUs. A state implementing a state measures approach 

plan type must submit a plan that meets the state mass-based CO2

goal for affected EGUs. The content of the state plan submittal 

will vary depending on which approachplan type the state decides 

to adopt. States that choose to participate in multi-state plans 

must adequately address plan components that apply to all 

participating states in the multi-state plan. 

The rest of this section covers components that are 

required for all types of plans, as well as components specific 

to each specific type of plans. Section VIII.D.2.a addresses the 

components required for all plan submittals. Section VIII.D.2.b 

addresses the additional components required for submittals 

under the emission standards plan approachtype. Section 

VIII.D.2.c addresses additional components required for 

submittals under the state measures plan approachtype. 

a. Components required for all state plan submittals. The EPA is 

finalizing requirements that a final plan submittal must contain 

the following components, in addition to those in either section 
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VIII.D.2.b (for the emission standards plan approachtype) or 

VIII.D.2.c (for the state measures plan approachtype) of this 

section. 

(1) Description of the plan approach and geographic scope. 

The description of the plan approachtype must indicate 

whether the state will meet the emission guidelines on an 

individual state basis or jointly through a multi-state 

approachplan, and whether the state is adopting an emission 

standards approach plan type or a state measures approach plan

type. For multi-state plans this component must identify all 

participating states and geographic boundaries applicable to 

each component in the plan submittal. If a state intends to 

implement its individual plan in coordination with other states 

by allowing for the interstate transfer of ERCs or emission 

allowances, such links must also be identified.1054

(2) Applicability of state plans to affected EGUs. 

The state plan submittal must list the individual affected 

EGUs that meet the applicability criteria of 40 CFR 60.5845 and 

provide an inventory of CO2 emissions from those affected EGUs 

for the most recent calendar year prior to plan submission for 

 

1054 If applicable, this plan component must also identify if the 

plan is being submitted as a “ready-for-interstate-trading” 

plan, as discussed in section VIII.J.3 and VIII.K.4. 
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which data are available. 

(3) Demonstration that a state plan will achieve the CO2

emission performance rates or state CO2 emission goal. 

A state plan submittal must demonstrate that the federally 

enforceable emission standards for affected EGUs and/or state 

measures are sufficient to meet either the CO2 emission 

performance rates or the state’s CO2 emission goal for affected 

EGUs in the emission guidelines for the interim and final plan 

performance periods. This includes during the interim period of 

2022-2029, including the interim step 1 period (2022-2024); 

interim step 2 period (2025-2027); and interim step 3 period 

(2028-2029) period, as well as during the final period of 2030-

2031 and subsequent 2-year periods.1055 A demonstration of CO2

emission performance is required through 2031. For the post-2031 

period, the demonstration requirement may be satisfied by 

showing that emission standards or state measures on which the 

demonstration through 2031 is based are permanent and will 

 

1055 State plans may meet the CO2 emission performance rates in 

the emission guidelines during the interim plan performance step 

periods, or assign different interim step CO2 emission 

performance rates, provided the CO2 emission performance rates in 

the emission guidelines are achieved during the full interim 

period. Likewise, a state plan may meet the interim step state 

CO2 emission goals in the emission guidelines or establish 

different interim step CO2 emission levels, provided the state 

interim CO2 goal is achieved during the full interim period. 
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remain in place. As discussed in more detail in section VIII.J, 

states adopting a plan based upon a mass-based state CO2 emission 

goal must demonstrate that they have addressed the risk of 

potential emission leakage in their mass-based state plan. 

The type of demonstration of CO2 emission performance and 

documentation required for such a demonstration in a state plan 

submittal will vary depending on how the CO2 emission standards 

for affected EGUs and/or state measures in a state plan are 

applied across the fleet of affected EGUs in a state, as 

discussed below.1056 

(a) State plan type designs that require a projection of CO2

emission performance. Whether a projection of affected EGU CO2

emission performance must be included in a state plan submittal 

depends on the design of the state plan. The following plan 

designs do not require a projection of CO2 emission performance 

by affected EGUs under the state plan because they ensure that 

the CO2 emission performance rates or state rate-based or mass-

 

1056 For simplicity, the EPA refers here to state measures under a 

state measures plan as being included “in the state plan” 

although such state-enforceable measures are not codified as 

part of the federally enforceable approved state plan. However, 

the approval of a state measures plan is dependent on a 

demonstration in the state plan submittal that those stateenforceable measures meet the requirements in the emission 

guidelines and that those state measures, alone or in 

combination with federally enforceable emission standards for 

affected EGUs, will meet the mass-based CO2 goal. 
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based CO2 goals are achieved when affected EGUs comply with the 

emission standards: 

 State plan establishes separate rate-based CO2 emission 

standards for affected fossil fuel-fired electric utility 

steam generating units and stationary combustion turbines 

(in lb CO2/MWh) that are equal to or lower than the CO2

emission performance rates in the emission guidelines 

during the interim and final plan performance periods. 

 State plan establishes a single rate-based CO2 emission 

standard for all affected EGUs that is equal to or lower 

than the state’s rate-based CO2 goal in the emission 

guidelines during the interim and final plan performance 

periods. 

 State plan establishes mass-based CO2 emission standards 

for affected EGUs that cumulatively do not exceed a 

state’s mass-based CO2 goal in the emission guidelines 

during the interim and final plan performance periods. 

 State plan establishes mass-based CO2 emission standards 

for affected EGUs that, together with state enforceable 

limits on mass emissions from new EGUs, cumulatively do 

not exceed the state’s EPA-specified mass CO2 emission 
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budget1057 in the emission guidelines during the interim 

and final plan performance periods. 

All other state plan designs must include a projection of 

CO2 emission performance by affected EGUs under the state plan. 

For example, if a state chooses to apply rate-based CO2 emission 

standards to individual affected EGUs, or to subcategories of 

affected EGUs (such as fossil fuel-fired electric utility steam 

generating units and stationary combustion turbines), at a lb 

CO2/MWh rate that differs from the CO2 emission performance rates 

or the state’s rate-based CO2 goal in the emission guidelines, 

then a projection is required. Also, if a state chooses to 

implement a mass-based program including both affected EGUs and 

new EGUs, but with total allowable emissions in excess of the 

presumptively approvable EPA-specified mass CO2 emission budget 

for that state, the state must provide a projection of CO2

emission performance. Likewise, if a state chooses a state 

measures state plan approach, a projection of CO2 emission 

performance is required. 

(b) Methods and tools. A satisfactory demonstration of the 

future CO2 emission performance of affected EGUs must use 

 

1057 A state’s EPA-specified mass CO2 emission budget is the 

state’s mass-based CO2 goal for affected EGUs plus the EPAspecified new source CO2 emission complement. See section 

VIII.J.2.b. 
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technically sound methods that are reliable and replicable. A 

state plan submittal must explain how the projection method 

and/or tool works and why the method and/or tool chosen is 

appropriate considering the type of emission standards and/or 

state measures included (or relied upon, in the case of state 

measures) in a state plan. The results of the demonstration must 

be reproducible using the documented assumptions described in 

the state plan submittal. The method and projection of EGU 

generation and CO2 emissions can differ from the EPA’s forecast 

in the RIA. The EPA received comments on whether it would 

require specific modeling tools and input assumptions. 

Commenters raised concerns that the EPA may require states to 

use proprietary models, and that states do not have the 

financial resources to use such models. The EPA is not requiring 

a specific type of method or model, as long as the one chosen 

uses technically sound methods and tools that establish a clear 

relationship between electricity grid interactions and the range 

of factors that impact future EGU economic behavior, generation, 

and CO2 emissions. The EPA will assess whether a method or tool 

is technically sound based on its capability to represent 

changes in the electric system commensurate to the set of 

emission standards and state measures in a state plan while 

accounting for the key parameters specified in section 
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VIII.D.2.a.(3)(c) below. Including a base case CO2 emission 

projection in the state plan submittal (i.e., one that does not 

include any federally enforceable CO2 emission standards included 

in a plan or state-enforceable measures referenced in a plan 

submittal), will help facilitate the EPA’s assessment of the CO2

emission performance projection. Methods and tools could range 

from applying future growth rates to historical generation and 

emissions data, using statistical analysis, or electric sector 

energy modeling. 

(c) Required documentation of projections. When required to 

provide a CO2 emission performance projection, the state must 

also provide comprehensive documentation of analytic parameters 

for the EPA to assess the reasonableness of the projection. The 

analytic parameters, when considered as a whole, should reflect 

a logically consistent future outlook of the electric system. 

Refer to the Incorporating RE and Demand-side EE Impacts into 

State Plan Demonstrations TSD of the final rule for further 

details on quantifying impacts of eligible RE and demand-side EE 

measures. 

The CO2 emission performance projection documentation must 

include: 

 Geographic representation, which must be appropriate for 

capturing impacts and/or changes in the electric system 
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 Time period of analysis, which must extend through 2031 

 Electricity demand forecast (MWh load and MW peak demand) 

at the state and regional level. If the demand forecast 

is not from NERC, an ISO or RTO, EIA, or other publicly 

available source, then the projection must include 

justification and documentation of underlying assumptions 

that inform the development of the demand forecast, such 

as annual economic and demand growth rate, population 

growth rate. 

 Planning reserve margins 

 Planned new electric generating capacity 

 Analytic treatment of the potential for building 

unplanned new electric generating capacity 

 Wholesale electricity prices 

 Fuel prices, when applicable; 

 Fuel CO2 content 

 Unit-level fixed operations and maintenance costs, when 

applicable; 

 Unit-level variable operations and maintenance costs, 

when applicable; 

 Unit-level capacity 

 Unit-level heat rate 
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 If applicable, EGU-specific actions in the state plan 

designed to meet the required CO2 emission performance, 

including their timeline for implementation 

 If applicable, state-enforceable measures, with 

electricity savings and renewable electricity generation 

(MWhs) expected for individual and collective measures, 

as applicable. Quantification of MWhs expected from EE 

and RE measures will involve assumptions that states must 

document, as described in the Incorporating RE and 

Demand-side EE Impacts into State Plan Demonstrations 

TSD. 

 Annual electricity generation (MWh) by fuel type and CO2

emission levels, for each affected EGU 

 ERC or emission allowance prices, when applicable 

The state must also provide a clear demonstration that the state 

measures and/or federally enforceable emission standards 

informing the projected achievement of the emission performance 

requirements will be permanent and remain in place. 

The EPA encourages participation in regional modeling 

efforts which are designed to allow sharing of data and help 

promote consistent approaches across state boundaries. A state 

that submits a single-state plan must consider interstate 

transfer of electricity across state boundaries, taking into 
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account other states’ plan types reflecting the best available 

information at the time of the CO2 emission performance 

projection. Projections of CO2 emission performance for multistate plans and single-state plans that include multi-state 

coordination must either use a single (regional) electricity 

demand forecast or must document the use of electricity demand 

forecasts from different information sources and demonstrate how 

any inconsistencies between the individual electricity demand 

forecasts have been reconciled. 

(d) Additional projection requirements under a rate-based 

emission standards plan. For an emission standards plan that 

applies rate-based CO2 emission standards to individual affected 

EGUs, or to subcategories of affected EGUs, at a lb CO2/MWh rate 

that differs from the CO2 emission performance rates or the 

state’s rate-based CO2 goal in the emission guidelines, a 

projection of affected EGU CO2 emission performance is required. 

The state must demonstrate that the weighted average CO2 emission 

rate of affected EGUs, when weighted by generation (in MWh) from 

affected EGUs subject to the different rate-based emission 

standards, will be equal to or less than the CO2 emission 

performance rates or the state's rate-based CO2 emission goal 

during the interim and final plan performance periods. 

The projection will involve an analysis of the change in 
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generation of affected EGUs given the compliance costs and 

incentives under the application of different emission rate 

standards across affected EGUs in a state. It must accurately 

represent the emission standards in the plan, including the use 

of market-based aspects of the emission standards (if 

applicable), such as use of ERCs or emission allowances as 

compliance instruments. 

In addition to the elements described in the previous 

section (c), the projection under this plan design must include: 

• The assignment of federally enforceable emission 

standards for each affected EGU; 

• A projection showing how generation is expected to shift 

between affected EGUs and across affected EGUs and nonaffected EGUs over time; 

• Underlying assumptions regarding the availability and 

anticipated use of the MWh of electricity generation or 

electricity savings from eligible measures that can be 

issued ERCs; 

• The specific calculation (or assumption) of how eligible 

MWh of electricity generation or savings that can be 

issued ERCs are being used in the projection to adjust 

the reported CO2 emission rate of affected EGUs, 

consistent with the accounting methods for adjusting the 
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CO2 emission rate of an affected EGU specified in section 

VIII.K.1 of the emission guidelines, if applicable; 

• ERC prices, if applicable; 

• If a state plan provides for the ability of RE resources 

located in states with mass-based plans to be issued ERCs 

for use in adjusting the reported CO2 emission rates of 

affected EGUs, consideration in the projection that such 

resources must meet geographic eligibility requirements, 

based on power purchase agreements or related 

documentation, consistent with the requirements at 

section VIII.K.1 and section VIII.L; and 

• Any other applicable assumptions used in the projection. 

(e) Additional projections requirements for a state measures 

plan. For a state measures plan, a projection of affected EGU CO2

emission performance must demonstrate that the state measures, 

whether alone or in conjunction with any federally enforceable 

CO2 emission standards for affected EGUs, will achieve the 

state’s mass-based CO2 goals in the emission guidelines for the 

interim and final periods. The projection must accurately 

represent individual state-enforceable measures (or bundled 

measures) and timing for implementation of these state measures.

 A state must demonstrate that its state-enforceable 

measures, along with any federally enforceable CO2 emission 
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standards for affected EGUs included in a state plan, will 

achieve the state mass-based CO2 goal. In addition to the 

elements described in section VIII.D.2.a.(3).(c), the state must 

clearly document, at a minimum: 

• the assignment of federally enforceable emission 

standards for each affected EGUs, if applicable; and 

• the individual state measures, including their 

projected impacts over time. 

 Because different types of state measures could have 

varying degrees of impact on reducing or avoiding CO2 emissions 

from affected EGUs, and different state measures may interact 

with one another in terms of CO2 emission reduction impacts, the 

method and tools a state uses to project CO2 emissions impacts 

must have the capability to project how the combined set of 

state-enforceable measures are likely to impact CO2 emissions at 

affected EGUs. If a state chooses to use an emission budget 

trading program as a mass-based state measure, for example, the 

state must choose an analytic method or tool that can account 

for and properly represent any program flexibilities that impact 

CO2 emissions from affected EGUs, such as use of out-of-sector 

GHG offsets and cost-containment provisions. The state would 

show that the emissions budget trading program included in the 

state measures plan, as well as any other state measures, ensure 
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that the sum of emissions at all affected EGUs will be lower 

than or equal to the state’s CO2 emission goal in the time 

periods specified in these guidelines. All flexibilities must be 

clearly documented in the demonstration. 

(4) Monitoring, reporting and recordkeeping requirements 

for affected EGUs. 

The state plan submittal must specify how each emission 

standard is quantifiable and verifiable by describing the CO2

emission monitoring, reporting and recordkeeping requirements 

for affected EGUs. The applicable monitoring, recordkeeping and 

reporting requirements for affected EGUs are outlined in section 

VIII.F. 

In the June 2014 proposal, the EPA proposed that states 

must include in their state plans a record retention requirement 

for affected EGUs to maintain records for at least 10 years 

following the date of each occurrence, measurement, maintenance, 

corrective action, report or record. Commenters requested 

clarification of the record retention requirements for states as 

compared to for affected EGUs and also requested that the EPA 

clarify onsite versus offsite record maintenance requirements 

for affected EGUs. The EPA is finalizing that states must 

include in their plans a record retention requirement for 

affected EGUs of not less than 5 years following the date of 
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each compliance period, compliance true-up period, occurrence, 

measurement, maintenance, corrective action, report, or record, 

whichever is latest. Affected EGUs must maintain each record 

onsite for at least 2 years after the date of the occurrence of 

each record and may maintain records offsite and electronically 

for the remaining years. Each record must be in a form suitable 

and readily available for expeditious review. The EPA finds that 

these final recordkeeping requirements are appropriate and 

consistent with the requirements for other CAA section 111(d) 

emission guidelines. 

(5) State reporting and recordkeeping requirements. 

A state plan submittal must contain the process, content 

and schedule for state reporting to the EPA on plan 

implementation and progress toward meeting the CO2 emission 

performance rates or state CO2 emission goal. 

The EPA requested comments on whether full reports 

containing all of the report elements should only be required 

every 2 years and on the appropriate frequency of reporting of 

the different proposed elements, considering both the goals of 

minimizing unnecessary burdens on states and ensuring program 

transparency and effectiveness. Commenters recognized that 

different reporting frequencies may be appropriate for different 

types of state plans. The EPA agrees with the commenters and is 
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finalizing state reporting requirements based on the type of 

plan the state chooses to adopt and implement. These state 

reporting requirements and reporting periods are discussed in 

section VIII.D.2.b (for emission standards plan types) and 

VIII.D.2.c (for state measures plan types). The EPA finalizes 

that each state report is due to the EPA no later than the July 

1 following the end of each reporting period. The EPA recognizes 

the multiple comments received recommending extending the state 

report due date from July 1 to a later date or to allow the 

states the flexibility to propose an alternative report 

submittal date. The EPA is not pursuing these recommendations 

due to the implications of the state reports’ due date and the 

trigger and schedule for implementation of corrective measures 

(for the emission standards approach) or the backstop federally 

enforceable emission standards (for the state measures 

approach). The EPA believes the July 1 deadline for states to 

submit reports to the EPA on plan implementation is feasible 

given that the information required to be included in the 

reports will be available per the reporting requirements for 

affected EGUs in state plans. 

In addition to the state reporting requirements discussed 

in section VIII.D.2.b (for emission standards approach) and 

VIII.D.2.c (for state measures approach) and as discussed below, 
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states must include in the supporting material of a final state 

plan submittal a timeline with all the programmatic milestone 

steps the state will take between the time of the final state 

plan submittal and 2022 to ensure the plan is effective as of 

2022. The EPA is also finalizing a requirement that states must 

submit a report to the EPA in 2021 that demonstrates that the 

state has met the programmatic milestone steps that the state 

indicated it would take from the submittal of the final plan 

through the end of 2020, and that the state is on track to 

implement the approved state plan as of January 1, 2022. A final 

state plan submission must include a requirement for the state 

to submit this report to the EPA no later than July 1, 2021. 

This report will help the EPA further assist and facilitate plan 

implementation with states as part of an ongoing joint effort to 

ensure the necessary reductions are achieved. 

The EPA is finalizing the requirement that submissions 

related to this program be submitted electronically. 

Specifically, this includes negative declarations, state plan 

submittals (including any supporting materials that are part of 

a state plan submittal), any plan revisions, and all reports 

required by the state plan. The EPA is developing an electronic 

system to support this requirement that can be accessed at the 

EPA’s Central Data Exchange (CDX) (http://www.epa.gov/cdx/). See 
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section VIII.E.8 for additional information on electronic 

submittal requirements. 

In the June 2014 proposal, the EPA proposed that states 

must keep records, for a minimum of 20 years, of all plan 

components, plan requirements, plan supporting documentation and 

status of meeting the plan requirements, including records of 

all data submitted by each affected EGU used to determine 

compliance with its emission standards. The EPA received 

multiple comments recommending that the EPA reduce recordkeeping 

requirements due to the burden in expenditure of resources and 

manpower to maintain records for at least 20 years. Commenters 

recommended that recordkeeping requirements be reduced to 5 

years consistent with emission guidelines for other existing 

sources. 

After considering the comments received, this final rule 

requires that a state must keep records of all plan components, 

plan requirements, supporting documentation, and the status of 

meeting the plan requirements defined in the plan for the 

interim plan period from 2022-2029 (including interim steps 1, 2 

and 3). After 2029, states must keep records of all information 

relied upon in support of any continued demonstration that the 

final CO2 emission performance rates or goals are being achieved.

The EPA agrees with comments that a 20-year record retention 
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requirement could be unduly burdensome, and has reduced the 

length of the record retention requirement for the final rule. 

During the interim period, states must keep records for 10 years 

from the date the record is used to determine compliance with an 

emission standard, plan requirement, CO2 emission performance 

rate or CO2 emission goal. During the final period, states must 

keep records for 5 years from the date the date the record is 

used to determine compliance with an emission standard, plan 

requirement, CO2 emission performance rate or CO2 emissions goal.

All records must be in a form suitable and readily available for 

expeditious review. States must also keep records of all data 

submitted by each affected EGU that was used to determine 

compliance with each affected EGU’s emission standard, and such 

data must meet the requirements of the emission guidelines, 

except for any information that is submitted to the EPA 

electronically pursuant to requirements in 40 CFR part 75. If 

the state is adopting and implementing the state measures 

approach, the state must also maintain records of all data 

regarding implementation of each state measure and all data used 

to demonstrate achievement of the CO2 emission goal and such data 

must meet the requirements of the emission guidelines. The EPA 

finds that these final recordkeeping requirements balance the 

need to maintain records while reducing the strain on state 
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resources. 

(6) Public participation and certification of hearing on 

state plan. 

A robust and meaningful public participation process during 

state plan development is critical. For the final plan 

submittal, states must meaningfully engage with members of the 

public, including vulnerable communities, during the plan 

development process. This section describes how the EPA will 

evaluate a state plan for compliance with the minimum required 

elements for public participation provided in the existing 

implementing regulations as well as recommendations for other 

steps the state can take to assure robust and inclusive public 

participation. 

The existing implementing regulations regarding public 

participation requirements are in 40 CFR 60.23(c)-(f). Per the 

implementing regulations, states must conduct a public hearing 

on a final state plan before such plan is adopted and submitted. 

State plan development can be enhanced by tapping the expertise 

and program experience of several state government agencies. The 

EPA encourages states to include utility regulators (e.g. the 

PUCs) and state energy offices as appropriate early on and 
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throughout in the development of the state plan.1058 The EPA notes 

that utility regulators and state energy offices have the 

opportunity during the public participation processes required 

for state plans to provide input as well. The EPA also 

encourages states to conduct outreach meetings (that could 

include public hearings or meetings) with vulnerable communities 

on its initial submittal before the plan is submitted. In its 

final plan submittal, a state must provide certification that 

the state made the plan submittal available to the public and 

gave reasonable notice and opportunity for public comment on the 

state plan submittal. The state must demonstrate that the public 

hearing on the state plan was held only after reasonable notice, 

which will be considered to include, at least 30 days prior to 

the date of such hearing, notice given to the public by 

prominent advertisement announcing the date(s), time(s) and 

place(s) of such hearing(s). For each hearing held, a state plan 

submittal must include in the supporting documentation the list 

of witnesses and their organizational affiliations, if any, 

appearing at the hearing, and a brief written summary of each 

presentation or written submission pursuant to the requirements 

 

1058 While we specifically encourage state environmental agencies 

and utility regulators to consult here, we note that, under CAA 

programs, state agencies have a history of consultation with one 

another as appropriate. 
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of the implementing regulations at 40 CFR 60.23. Additionally, 

the EPA recommends that states work with local municipalities, 

community-based organizations and the press to advertise their 

state public hearing(s). The EPA also encourages states to 

provide background information about their proposed final state 

plan or their initial submittal in the appropriate languages in 

advance of their public hearing and at their public hearing. 

Additionally, the EPA recommends that states provide translators 

and other resources at their public hearings, to ensure that all 

members of the public can provide oral feedback. 

As previously discussed in this rule, recent studies also 

find that certain communities, including low-income communities 

and some communities of color (more specifically, populations 

defined jointly by ethnic/racial characteristics and geographic 

location) are disproportionately affected by certain climate 

change related impacts.1059 Also as discussed in this rule, 

effects from this rule can be anticipated to affect vulnerable 

communities in various ways. Because certain communities have a 

potential likelihood to be impacted by state plans, the EPA 

believes that the existing public participation requirements 

 

1059 USGCRP 2014: Melillo, Jerry M., Terese (T.C.) Richmond, and 

Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United 

States: The Third National Climate Assessment. U.S. Global 

Change Research Program, 841 pp. 
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under 40 CFR 60.23 are effectuated for the purposes of this 

final rule by states engaging in meaningful, active ways with 

such communities. 

In addition, certain communities whose economies are 

significantly dependent on coal, or whose economies may be 

affected by ongoing changes in the utility power and related 

sectors, may be particularly concerned about the final rule. The 

EPA encourages states to make an effort to provide background 

information about their proposed initial submittal and final 

state plans to these communities in advance of their public 

hearing. In particular, the EPA encourages states to engage with 

workers and their representatives in the utility and related 

sectors, including the EE sector. 

The EPA notes that meaningful public involvement goes beyond 

the holding of a public hearing. The EPA envisions meaningful 

engagement to include outreach to vulnerable communities, 

sharing information and soliciting input on state plan 

development and on any accompanying assessments, such as those 

described in section IX. The agency uses the terms “vulnerable” 

and “overburdened” in referring to low-income communities, 

communities of color, and indigenous populations that are most 

affected by, and least resilient to, the impacts of climate 

change, and are central to our community and environmental 
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justice considerations. In section VIII.E, the EPA provides 

states with examples of resources on how they can engage with 

vulnerable communities in a meaningful way. With respect 

specifically to ensuring meaningful community involvement in 

their public hearing(s), however, the EPA recommends that states 

have both a website and toll-free number that all stakeholders, 

including overburdened communities, labor unions, and others can 

access to get more information regarding the upcoming hearing(s) 

and to get their questions related to upcoming hearings 

answered. Furthermore, the EPA recommends that states work with 

their local government partners to help them in reaching out to 

all stakeholders, including vulnerable communities, about the 

upcoming public hearing(s). 

(7) Supporting documentation. 

The state plan submittal must provide supporting material 

and technical documentation related to applicable components of 

the plan submittal. 

(a) Legal authority. 

In its submittal, a state must adequately demonstrate that 

it has the legal authority (regulations/legislation) and funding 

to implement and enforce each component of the state plan 

submittal, including federally enforceable emission standards 

for affected EGUs and state measures. A state can make such a 
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demonstration by providing supporting material related to the 

state’s legal authority used to implement and enforce each 

component of the plan, such as copies of statutes, regulations, 

PUC orders, and any other applicable legal instruments. For 

states participating in a multi-state plan, the submittal(s) 

must also include as supporting documentation each state’s 

necessary legal authority to implement the portion of the plan 

that applies within the particular state, such as copies of 

state regulations and statutes, including a showing that the 

states have the necessary authority to enter into a multi-state 

agreement. 

(b) Technical documentation. 

As applicable, the state submittal must include materials 

necessary to support the EPA’s evaluation of the submittal 

including analytical materials used in the calculation of 

interim goal steps (if applicable), analytical materials used in 

the multi-state goal calculation (if multi-state plan), 

analytical materials used in projecting CO2 emission performance 

that will be achieved through the plan, relevant implementation 

materials and any additional technical requirements and guidance 

the state proposes to use to implement elements of the plan. 

(c) Programmatic milestones and timeline. (2 

As part of the state plan supporting documentation, the 
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state must include in its submittal a timeline with all the 

programmatic milestone steps the state will take between the 

time of the state plan submittal and 2022 to ensure the plan is 

effective as of January 1, 2022. The programmatic milestones and 

timeline should be appropriate to the overall state plan 

approach included in the state plan submittal. 

(d) Reliability. 

As discussed in more detail in section VIII.G.2, each state 

must demonstrate as part of its state plan submission that it 

has considered reliability issues while developing its plan. 

b. Additional components required for the emission standards 

plan type. The EPA is finalizing requirements that a final plan 

submittal using the emission standards plan type must contain 

the following components, in addition to the components 

discussed in the preceding section VIII.D.2.a. 

(1) Identification of interim period emission performance 

rates or state goal (for 2022-2029), interim step performance 

rates or interim state goals (2022-2024; 2025-2027; 2028-2029) 

and final emission performance rates or state goal (2030 and 

beyond). 

The state plan submittal must indicate whether the plan is 

designed to meet the CO2 emission performance rates or the state 

CO2 emission goal. As noted in the emission guidelines, the EPA 
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is finalizing state goals in the form of a CO2 emission rate 

(emission performance rates for fossil fuel-fired steam 

generating units and for stationary combustion turbines. The EPA 

has translated the source category-specific CO2 emission 

performance rates into equivalent state-level rate-based goal) 

and in the form of tonnage CO2 emissions (and mass-based 

goal).CO2 goals in order to maximize the range of choices that 

states will have in developing their plans. The state may 

adoptchoose to develop a state plan that meets the CO2 

performance rates for the two subcategories of affected EGUs or 

develop a plan that adopts either the rate-based or the massbased state CO2 emission goal provided in the emission 

guidelines. If the state chooses the option of developing a plan 

that achieves the 

Each state CO2 emission goal, the state plan submittalplan

must identify the emission performance rates or rate-based or 

mass-based CO2 emission goal that must be achieved through the 

plan (expressed in numeric values, including the units of 

measurement, such as pounds of CO2 per net MWh of useful energy 

output or tons of CO2). The plan submittal must identify the 

state CO2 interim period performance rates or state goal (for 

2022-2029), interim stepsstep performance rates or state goals 

(interim step performance rates or state goal 1 for 2022-2024; 
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interim step performance rates or state goal 2 for 2025-2027; 

interim step performance rates or state goal 3 for 2028-2029) 

and final CO2 emission performance rates or state goal of 2030 

and beyond. 

For each state, the The EPA has finalized an interim 

performance rates or state goal for the interim period of 2022-

2029 and a final performance rates or state goal to be met by 

2030. For the interim period, the EPA has also finalized three 

interim step performance rates or state goals: interim step 1 

performance rates or state goal for 2022-2024, interim step 2 

performance rates or state goal for 2025-2027 and interim step 3 

performance rates or state goal for 2028-2029.1060 States are free 

to establish different interim step performance rates or interim 

step state goals than those the EPA has specified in this final 

rule. If states choose to determine their own interim step 

performance rates or state goals, the state must demonstrate 

that itthe plan will still meet the interim performance rates or 

state goal for 2022-2029 finalized in this actionthe emission 

guidelines and the plan submittal must include in its supporting 

documentation a description of the analytic process, tools, 

 

1060 In this action, the EPA is providing interim state goals in 

the form of a CO2 emission rate (emission rate-based goal) and in 

the form of tonnage CO2 emissions (mass-based goal). 
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methods, and assumptions used to make this demonstration. 

The final rule allows states the opportunity to switch from 

a rate-based CO2 goal for the interim plan performance period 

(2022-2029) to a mass-based CO2 goal for the final plan 

performance period (2030 and onward). Conversely, a state plan 

may use a mass-based CO2 goal for the 2022-2029 interim period, 

and a rate-based CO2 goal for the final goal plan performance 

periods. Some commenters requested that flexibility be provided 

to allow states to switch from rate-based goals to mass-based 

goals either as a one-time change between the interim goal to 

the final goal, or more frequently if necessary year-by-year. 

The EPA recognizes that it may be necessary to switch between 

rate-based goals and mass-based goals, and therefore provides 

the option for states to change approaches between the interim 

plan performance period and the final plan performance period. 

To ensure progress toward the goals, maintain consistency with 

rule provisions, and minimize delays due to plan revisions, the 

EPA does not grant states the ability to change approaches more 

often than from the interim period to the final period. For 

instance, if a state plan indicates that a mass-based CO2 goal 

will be used for demonstrating achievement of the interim goal, 

then that state will be required to demonstrate achievement of 

the specified mass-based interim steps on a mass basis, and will 
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have the option to change to a rate-based approach for the final 

plan performance period. 

For states participating in a multi-state plan with a joint 

goal (for interim and final periods), the individual state goals 

in the emission guidelines would be replaced with an equivalent 

multi-state goal for each period (interim and final). For a

rate-based multi-state plan this would be a weighted average 

rate-based emission goal, derived by the participating states, 

by calculating a weighted average CO2 emission rate based on the 

individual rate-based goals for each of the participating states 

and 2012 generation from affected EGUs. For a mass-based multistate plan, the joint goal would be a sum of the individual 

mass-based goals of the participating states, in tons of CO2. The 

plan submittal must include in its supporting documentation a 

description of the analytic process, tools, methods, and 

assumptions used to calculate the joint multi-state goal. 

(3) Applicability of state plans to affected EGUs. The state 

plan submittal must list the individual affected EGUs that meet 

the applicability criteria of § 60.5805 and provide an inventory 

of CO2 emissions from those affected EGUs for the most recent 

calendar year prior to plan submission for which data are 

available. 

(4) Monitoring, reporting and recordkeeping requirements 
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for affected EGUs. The state plan submittal must specify how 

each emission standard is quantifiable and verifiable by 

describing the CO2 emission monitoring, reporting and 

recordkeeping requirements for affected EGUs. The applicable 

monitoring, recordkeeping and reporting requirements for 

affected EGUs with are outlined in section VIII.F. 

In the June 2014 proposal, the EPA proposed that states 

must include in their state plans a record retention requirement 

for affected EGUs to maintain records for at least 10 years 

following the date of each occurrence, measurement, maintenance, 

corrective action, report or record. Commenters requested 

clarification of the record retention requirements for states 

vs. for affected EGUs and also requested that the EPA clarify 

onsite vs. offsite record maintenance requirements for affected 

EGUs. Consistent with state recordkeeping requirements, the EPA 

is finalizing that states must include in their plans a record 

retention requirement for affected EGUs of not less than 5 years 

following the date of each compliance period, occurrence, 

measurement, maintenance, corrective action, report, or record., 

that affected EGUs must maintain each record onsite for at least 

2 years after the date of the occurrence of each record and may 

maintain records offsite and electronically for the remaining 

years. Each record must be in a form suitable and readily 
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available for expeditious review. The EPA finds that these final 

recordkeeping requirements are appropriate and consistent with 

the requirements for other CAA section 111(d) emission 

guidelines. 

(5) State reporting and recordkeeping requirements. A state plan 

submittal must contain the process, content and schedule for 

state reporting to the EPA on plan implementation and progress 

toward meeting the CO2 emission performance rates or state CO2

emission goal. 

The EPA is finalizing state reporting requirements based on 

the type of plan approach the state chooses to adopt and 

implement. These state reporting requirements are discussed in 

section VIII.D.2.b (for emission standards approach) and 

VIII.D.2.c (for state measures approach). 

In addition to the state reporting requirements discussed 

in section VIII.D.2.b (for emission standards approach) and 

VIII.D.2.c (for state measures approach) and as discussed below, 

states must include in the supporting material of a final state 

plan submittal a timeline with all the programmatic milestone 

steps the state will take between the time of the state plan 

submittal and 2022 to ensure the plan is effective as of 2022. 

The EPA is also finalizing a requirement that states must submit 

a report to the EPA in 2021 that demonstrates that the state has 
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met the programmatic milestone steps that the state indicated it 

would take from the submittal of the final plan through the end 

of 2020, and that the state is on track to implement the 

approved state plan as of January 1, 2022. An approvable final 

state plan submission must include a requirement for the state 

to submit this report to the EPA no later than July 1, 2021. If 

the EPA approves a state plan that includes the required 

obligation on the state to submit this report, and the state 

either does not submit the requisite report by July 1, 2021, or 

the state submits a report demonstrating it has not met the 

programmatic milestones, the EPA’s approval of the state plan 

will convert to a disapproval. Per the requirements of CAA 

section 111(d), the EPA will develop and implement a federal 

plan in the instance of such disapproval. As discussed in 

section VIII.B, if a state demonstrates, in its July 1, 2021 

report, that it has implemented such early action measures, the 

EPA will consider its report to be presumptively approvable. 

The EPA is finalizing a requirement for states to 

electronically submit state plan submittals, any supporting 

materials that are part of a state plan submittal, and state 

reports required by the state plan. The EPA is developing an 

electronic system to support this requirement that can be 

accessed at the EPA’s Central Data Exchange (CDX) 
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(http://www.epa.gov/cdx/). See Section VIII.E.7 for additional 

information on electronic submittal requirements. 

In the June 2014 proposal, the EPA proposed that states 

must keep records at minimum for 20 years of all plan 

components, plan requirements, plan supporting documentation and 

status of meeting the plan requirements, including records of 

all data submitted by each affected EGU used to determine 

compliance with emission standards. The EPA received multiple 

comments recommending that the EPA reduce recordkeeping 

requirements due to the burden in expenditure of resources and 

manpower to maintain records for at least 20 years. Commenters 

recommended that recordkeeping requirements be reduced to five 

years consistent with emission guidelines for other existing 

sources. 

After considering the comments received, this final rule 

requires that a state must keep records of all plan components, 

plan requirements, supporting documentation, and the status of 

meeting the plan requirements defined in the plan for the 

interim steps 1, 2 and 3 and the interim plan period from 2022-

2029. After 2029, states must keep records of all information 

relied upon in support of any continued demonstration that the 

final CO2 emissions performance rates or goals are being 

achieved. The EPA agrees with comments that a 20-year record 
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retention requirement could be unduly burdensome, and has 

reduced the length of the record retention requirement for the 

final rule. During the interim period, states must keep records 

for 10 years from the date of conclusion of each compliance 

period for its EGUs and/or plan performance period. During the 

final period, states must keep records for 5 years from the date 

of conclusion of each compliance period for its EGUs and/or plan 

performance period. All records must be in a form suitable and 

readily available for expeditious review. States must also keep 

records of all data submitted by each affected EGU that was used 

to determine compliance with each affected EGU’s emission 

standard, and such data must meet the requirements of the 

emission guidelines, except for any information that is 

submitted to the EPA electronically pursuant to requirements in 

40 CFR part 75. If the state is adopting and implementing the 

state measures approach, the state must also maintain records of 

all data regarding implementation of each state measure and all 

data used to demonstrate achievement of CO2 emission performance 

rates or CO2 emission goal and such data must meet the 

requirements of the emission guidelines. The EPA finds that 

these final recordkeeping requirements balance the need to 

maintain records while reducing the strain on state resources. 

(6) Certification of hearing on state plan. For the final plan 
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submittal, states must meaningfully engage with all members of 

the public, including communities, during the plan development 

process. The existing implementing regulations regarding public 

participation requirements are in40 CFR 60.23(c)-(f). Per the 

implementing regulations, states must conduct a public hearing 

on a final state plan before such plan is adopted and submitted. 

In its plan submittal, a state must provide certification that 

the state gave reasonable notice and opportunity for public 

comment on the state plan. The state must demonstrate that the 

public hearing on the state plan was held only after reasonable 

notice, which will be considered to include, at least 15 days 

prior to the date of such hearing, notice given to the public by 

prominent advertisement announcing the date(s), time(s) and 

place(s) of such hearing(s). For each hearing held, a state plan 

submittal must include in the supporting documentation the list 

of witnesses and their organizational affiliations, if any, 

appearing at the hearing, and a brief written summary of each 

presentation or written submission pursuant to the requirements 

of the implementing regulations at 40 CFR 60.23. Additionally, 

the EPA recommends that states work with local municipalities, 

community-based organizations and the press to advertise their 

state hearing(s). 

As previously discussed in this rule, recent studies also 
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find that certain communities, including low-income communities 

and some communities of color, are disproportionately affected 

by certain climate change related impacts. Also as discussed in 

this rule, effects from this rule can be anticipated to impact 

communities in various ways. Because certain communities have a 

potential likelihood to be impacted by state plans, the EPA 

believes that the existing public participation requirements 

under 40 CFR 60.23 are effectuated for the purposes of this 

final rule by states engaging in meaningful, active ways with 

such communities. 

The EPA notes that meaningful public involvement goes beyond 

the holding of a public hearing. In section VIII.E, the EPA 

provides states with resources on how to engage with affected 

communities in a meaningful way. With respect specifically to 

ensuring meaningful community involvement in their public 

hearing(s), however, the EPA recommends that states have both a 

website and toll-free number that all stakeholders, including 

affected communities, can access to get more information 

regarding the upcoming hearing(s). In addition, the EPA 

recommends that states provide all communities with a mechanism 

on their website and on the toll-free number to get their 

questions related to upcoming hearings answered. Furthermore, 

the EPA recommends that states work with their local government 
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partners to help them in reaching out to all stakeholders, 

including affected communities about the upcoming public 

hearing(s). 

(7) Supporting documentation. The state plan submittal must 

provide supporting material and technical documentation related 

to applicable components of the plan submittal. 

(a) Legal authority. In its submittal, a state must 

adequately demonstrate that it has the legal authority 

(regulations/legislation) and funding to implement and enforce 

each component of the state plan submittal, including federally 

enforceable emission standards for affected EGUs and state 

measures. A state can make such a demonstration by providing 

supporting material related to the state’s legal authority used 

to implement and enforce each component of the plan, such as 

copies of statutes, regulations, PUC orders, and any other 

applicable legal instruments. For states participating in a 

multi-state plan, the submittal(s) must also include as 

supporting documentation each state’s necessary legal authority 

to implement the portion of the plan that applies within the 

particular state, such as copies of state regulations and 

statutes, including a showing that the states have the necessary 

authority to enter into a multi-state agreement. 

(b) Technical documentation. As applicable, the state submittal 
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must include materials necessary to support the EPA’s evaluation 

of the submittal including analytical materials used in the 

calculation of interim goal steps, multi-state goal calculation 

(if joint multi-state demonstration), analytical materials used 

in projecting CO2 emission performance that will be achieved 

through the plan, relevant implementation materials and any 

additional technical requirements and guidance the state 

proposes to use to implement elements of the plan. 

(c) Programmatic milestones and timeline. As part of the state 

plan supporting documentation, the state must include in its 

submittal a timeline with all the programmatic milestone steps 

the state will take between the time of the state plan submittal 

and 2022 to ensure the plan is effective as of 2022. The 

programmatic milestones and timeline should be appropriate to 

the overall state plan approach included in the state plan 

submittal. 

(d) Reliability. As discussed in section VIII.H.2, each state 

must demonstrate that it has considered reliability issues while 

developing its plan. 

b. Additional components required for the emission standards 

approach. The EPA is finalizing requirements that a final plan 

submittal using the emission standards approach must contain the 

following components, in addition to the components discussed in 
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section VIII.D.2.a. 

(1) Identification of federally enforceable emission 

standards for affected EGUs. 

The state plan submittal for an emission standards plan 

type must include federally enforceable emission standards that 

apply to affected EGUs. The emission standards must meet the 

requirement of component 2(3) of this section, “Demonstrations 

that each emission standard is quantifiable, non-duplicative, 

permanent, verifiable, and enforceable.” The plan must identify 

the affected EGUs to which these standards apply. The compliance 

periods for each emission standard for affected EGUs, on a 

calendar year basis, must be as follows for the interim period: 

January 1, 2022 – December 31, 2024; January 1, 2025 – December 

31, 2027; and January 1, 2028 – December 31, 2029. Starting on 

January 1, 2030, the compliance period for each emission 

standard is every two2 calendar years. States can choose to set 

shorter schedules of compliance periods for the emission 

standards but no longer than the compliance periods the EPA is 

finalizing in this rulemaking, but cannot set longer periods. As 

discussed in more detail in section VIII.F, the EPA recognizes 

that the compliance periods provided for in this rulemaking are 

longer than those historically and typically specified in CAA 

rulemakings. The EPA determined that the longer compliance 
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periods provided for in this rulemaking are acceptable in the 

context of this specific rulemaking because of the unique 

characteristics of this rulemaking, including that CO2 is longlived in the atmosphere, and this rulemaking is focused on 

performance standards related to those long-term impacts. 

For state plans in which affected EGUs may rely upon the 

use of ERCs for meeting a rate-based federally enforceable 

emission standard, the emission standards in the state plan must 

include requirements addressing the issuance, tracking and use 

for compliance of ERCs consistent with the requirements in the 

emission guidelines. These requirements are discussed in 

sections VIII.K.1-2. The state plan must also demonstrate that 

the appropriate ERC tracking infrastructure that meets the 

requirements of the emission guidelines will be in place to 

administer the state plan requirements regarding ERCs and 

document the functionality of the tracking system. State plan 

requirements must include provisions to ensure that ERCs are 

properly tracked from issuance to submission for compliance. The 

state plan must also demonstrate that the MWh for which ERCs are 

issued are properly quantified and verified, through stateplan 

requirements for EM&V and other verification plan requirements 

that meet the requirements in the emission guidelines. EM&V 

requirements are discussed in section VIII.K.3. Rate-based 
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emission standards must also include monitoring, reporting, and 

recordkeeping requirements for CO2 emissions and useful energy 

output for affected EGUs; and related compliance demonstration 

requirements and mechanisms. All of theseThese requirements are 

discussed in more detail in sections VIII.G.3F and 4VIII.K. 

 For state plans using a mass-based emission trading program 

approach, the emission standards in the state plan must include 

implementation requirements that specify the emission budget and 

related compliance requirements and mechanisms. These 

requirements must include: CO2 emission monitoring, reporting, 

and recordkeeping requirements for affected EGUs; provisions for 

state allocation of allowances; provisions for tracking of 

allowances, from issuance through submission for compliance; and 

the process for affected EGUs to demonstrate compliance 

(allowance “true-up” with reported CO2 emissions.)). 

(23) Demonstration that each emission standard is 

quantifiable, non-duplicative, permanent, verifiable and 

enforceable. 

The plan submittal must demonstrate that each emission 

standard is quantifiable, non-duplicative, permanent, verifiable 

and enforceable with respect to an affected EGU, as outlined 

below. 

An emission standard is quantifiable if it can be reliably 
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measured, using technically sound methods, in a manner that can 

be replicated.1061 

An emission standard is non-duplicative with respect to an 

affected EGU if it is not already incorporated in another state 

plan, except in instances where incorporated as part of a multistate plan. An example of a duplicative emission standard would 

occur, for example, where a quantified and verified MWh from a 

wind turbine could be applied in more than one state’s CAA 

section 111(d) plan to adjust the reported CO2 emission rate of 

an affected EGU, (e.g., through issuance and use of an ERC),

except in the case of a multi-state plan where CO2 emission 

performance is demonstrated jointly for all affected EGUs 

subject to the multi-state plan or where states are implementing 

coordinated individual plans that allow for the interstate 

transfer of ERCs.1062 This does not mean that measures in used to 

 

1061 A CO2 continuous emissions monitoring system (CEMS) is the 

most technically reliable method of emission measurement for 

EGUs. A CEMS provideprovides a measurement method that is 

performance based rather than equipment specific whichand is 

verified based on NIST traceable standards. A CEMS 

provideprovides a continuous measurement stream that can account 

for variability in the fuels and the combustion 

process. Reference methods have been developed to ensure that 

all CEMS meet the same performance criteria, which helps to 

ensure a level playing field and consistent, accurate data. 

1062 For example, an ERC that is issued by a state under its ratebased emission standards may be used only once by an affected 

EGU to adjust its reported CO2 emission rate when demonstrating 
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comply with an emission standard cannot also be used for other 

purposes. For example, a MWh of electric generation from a wind 

turbine could be used by an electric distribution utility to 

comply with state RPS requirements and also be used by an 

affected EGU comply with emission standard requirements under a 

state plan. Another example is when actions taken pursuant to 

CAA section 111(d) requirements can satisfy other CAA program 

requirements (e.g., Regional Haze requirements, MATS etc.)).

An emission standard is permanent if the emission standard 

must be met for each applicable compliance period. 

An emission standard is verifiable if adequate monitoring, 

recordkeeping and reporting requirements are in place to enable 

the state and the Administrator to independently evaluate, 

measure, and verify compliance with it. 

An emission standard is enforceable if: (1) it: (1)

represents a technically accurate limitation or requirement and 

the time period for the limitation or requirement is specified,;

 

compliance with the emission standards. However, an ERC issued 

in one state could be used by an affected EGU to demonstrate 

compliance with its emission standardsstandard in another state, 

where states are collaborating in the implementation of their 

individual emission trading programs through interstate transfer 

of ERCs or CO2 emission allowances, or participating in a multistate plan with a rate-based or mass-based emission trading 

program. These coordinated multi-state approaches are addressed 

in subsectionsections VIII.C.5, VIII.J.3, and VIII.K.4.
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(2) compliance requirements are clearly defined,; (3) the 

entities responsible for compliance and liable for violations 

can be identified,; and (4) each compliance activity or measure 

is practically enforceable as a practical matter in accordance 

with EPA guidance on practical enforceability,1063 and the 

Administrator and, the state, and third parties, maintain the 

ability to enforce against affected EGUs for violations and 

secure appropriate corrective actions, in the case of the 

Administrator pursuant to CAA sections 113(a)–(h), and statesin 

the case of a state, pursuant to its state plan, state law or 

CAA section 304, as applicable, and other third parties maintain 

the ability to enforce against violations and secure appropriate 

corrective actionsin the case of third parties, pursuant to CAA 

section 304. 

In developing its CAA section 111(d) plan, to ensure that 

the plan submittal is enforceable and in conformance with the 

CAA, a state should follow the EPA’s prior guidance on 

 

1063 See prior footnote. The EPA guidance on enforceability 

includes: (1) September 23, 1987, memorandum and accompanying 

implementing guidance, “Review of State Implementation Plans and 

Revisions for Enforceability and Legal Sufficiency,” (2) August 

5, 2004, “Guidance on SIP Credits for Emission Reductions from 

Electric-Sector Energy Efficiency and Renewable Energy 

Measures,” and (3) July 2012 “Roadmap for Incorporating Energy 

Efficiency/Renewable Energy Policies and Programs into State and 

Tribal Implementation Plans, Appendix F.” 
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enforceability.1064 These guidance documents serve as the 

foundation for the types of monitoring, reporting, and emission 

standards that the EPA has found can be, as a practical matter, 

enforced. 

In the proposed regulatory text describing the enforcing 

measures that states must include in state plans, the EPA 

inadvertently excluded a required demonstration that states and 

other third parties can enforce against affected EGUs for 

violations of an emission standard included in a state plan via 

civil action pursuant to CAA section 304. Commenters noted the 

EPA’s intent to require this demonstration based on statements 

in both the proposal preamble text and “State Plan 

Considerations” TSD1065 and based on the requirements of CAA 

section 304. We are finalizing a requirement for a demonstration 

that states and other third parties can enforce against affected 

 

1064 The EPA guidance on enforceability includes: (1) September 

23, 1987, memorandum and accompanying implementing guidance, 

“Review of State Implementation Plans and Revisions for 

Enforceability and Legal Sufficiency,” (2) August 5, 2004, 

“Guidance on SIP Credits for Emission Reductions from ElectricSector Energy Efficiency and Renewable Energy Measures,” and (3) 

July 2012 “Roadmap for Incorporating Energy Efficiency/Renewable 

Energy Policies and Programs into State and Tribal 

Implementation Plans, Appendix F.” See prior footnote.

1065 State Plan Considerations technical support document for the 

Clean Power Plan Proposed Rule: http://www2.epa.gov/carbonpollution-standards/clean-power-plan-proposed-rule-state-planconsiderations. 
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EGUs for violations of an emission standard included in a state 

plan via civil action as part of the required plan component 

demonstrating enforceability. We are finalizing this requirement 

as a logical outgrowth of proposal preamble text, the proposal 

preamble citation to existing enforceability guidance documents 

that discuss this requirement, and comments received, and the 

clear statutory foundation. 

(3) Demonstration that the emission standards contained in the 

plan achieve the CO2 emission performance rates or state CO2

emission goal. A state plan submittal must demonstrate that the 

federally enforceable emission standards on affected EGUs are 

sufficient to meet either the CO2 emission performance rates or 

the state’s CO2 emission goals in the emission guidelines for the 

interim and final periods. This includes the interim period of 

2022-2029, including interim step 1 2022-2024 period; interim 

step 2 2025-2027 period and interim step 3 2028-2029 period (or 

alternative CO2 emission performance step levels adopted by the 

state, provided they result in achievement of the CO2 emission 

performance rates or state CO2 emission goal during the 2022-2029 

interim period), as well as the final period of 2030 and beyond. 

The type of demonstration required for emission standards plans 

will vary depending on how the CO2 emission performance standards 

are applied across the fleet of affected EGUs in a state, as 
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described below. 

(a) Demonstration for a rate-based emission standards state 

plan. The type of demonstration for a rate-based emission 

standards plan depends on the design of the plan submitted to 

the EPA. 

 When a state submits an emission standards plan that 

establishes separate rate-based CO2 emission standards for 

affected fossil fuel-fired electric utility steam generating 

units and stationary combustion turbines (in lbs CO2/MWh) that 

are equal to or lower than the CO2 emission performance rates in 

the emission guidelines, then no additional demonstration is 

required beyond inclusion of the emission standards in the plan. 

Under this approach, compliance by affected EGUs with the 

emission standards will ensure that the CO2 emission performance 

rates or the state rate-based CO2 emission goal is achieved. 

If a state chose to instead apply rate-based emission 

performance standards to individual affected EGUs, or to subcategories of affected EGUs (such as fossil fuel-fired electric 

utility steam generating units and stationary combustion 

turbines), at a lb CO2/MWh rate that differs from the CO2

emission performance rates or the state’s rate-based CO2 goal, 

then a further demonstration is required that application of the 

CO2 emission standards will achieve the CO2 emission performance 
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rates or state rate-based CO2 goal in the emission guidelines. 

The state must demonstrate through a projection that the 

weighted average CO2 emission rate of affected EGUs, when 

weighted by generation (in MWh), will be equal to or less than 

the CO2 emission performance rates or the state's rate-based CO2

emission goal. This projection must address both the interim 

period (including interim step periods 1-3, for 2022-2024, 2025-

2027, and 2028-2029), and the final period (2030-2031, and 

subsequent two-year periods). The projection in a state plan 

must include the following key information, at a minimum: 

 a summary of each affected EGU’s anticipated future 

operation characteristics, including annual 

generation, CO2 emissions, capacity and capacity 

factors; 

 planned retirements; 

 anticipated use of ERCs to adjust the reported CO2

emission rate of affected EGUs, including but not 

limited to, anticipated use (in MWh) by technologytype (e.g., wind, solar, demand-side EE), the physical 

location of the resources providing ERCs, and any 

other relevant information (e.g., power purchase 

agreements (PPAs) and other long-term power 

contracts); and an explanation, with calculation, of 
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how these measures are being used in the projection to 

adjust the CO2 emission rate of affected EGUs; 

 expected electricity demand growth at the state or 

regional level, including the source and basis for 

these estimates (e.g., based on population growth, 

GDP, adoption of demand-side EE or other applicable 

factors); if demand growth is not from NERC, an ISO or 

RTO, EIA or other publicly available source, then the 

projection must include justification and assumptions 

that inform the demand growth used; 

 expected fuel switching at affected EGUs; 

 heat rate improvements; and 

 any other applicable assumptions used in the 

projection. 

Because electricity flows across state boundaries, single 

state plan demonstrations must explain any regional 

information considered in developing the assumptions. 

Multi-state plans or plans sharing common elements should 

use regional assumptions or demonstrate reconciliation of 

any inconsistencies between state-level assumptions. 

(b) Demonstration for a mass-based emission standards state 

plan. Under the emission standards plan type, a mass-based 

emission budget trading program must be designed such that 
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compliance by affected EGUs would achieve the state mass-based 

CO2 goal. Under this approach, a state plan establishes emission 

budgets for affected EGUs during the interim and final plan 

performance periods that are equal to or lower than the 

applicable state mass-based CO2 goals specified in the final 

emission guidelines. Compliance periods for affected EGUs are 

also aligned with the interim and final plan performance 

periods. This approach limits total CO2 emissions from affected 

EGUs during the interim and final plan performance periods to an 

amount equal to or less than the state’s mass-based CO2 goal. 

 Under this approach, compliance by affected EGUs with the 

mass-based emission standards in a plan would ensure that the 

state achieves its mass-based CO2 goal for affected EGUs. No 

further demonstration is necessary by the state to demonstrate 

that its plan would achieve the state’s mass-based CO2 goal. 

For this type of plan, where the emission budget is equal 

to or less than the state mass CO2 goal,1066 the EPA will assess 

achievement of the state goal based on compliance by affected 

EGUs with the mass-based emission standards, rather than 

reported CO2 emissions by affected EGUs during the interim plan 

 

1066 As specified for the interim plan performance period 

(including specified levels in interim steps 1 through 3) and 

the final two-year plan performance periods. 
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performance periods and final plan performance periods. This 

approach allows for allowance banking between performance 

periods, which is a typical design element for emission budget 

trading programs addressing GHG emissions. 

(4) State reporting requirements. 

After consideration of the comments received regarding 

state reporting requirements, the EPA is finalizing for state 

plans using the emission standards approach that a state report 

is due to the EPA no later than the July 1 following the end of 

each reporting period. ForWithin the interim period (2022-2029) 

the EPA is finalizing the following interim reporting periods: 

interim step 1 covers the three calendar years 2022-2024;,

interim step 2 covers the three calendar years 2025-2027, and 

interim step 3 covers the two calendar years 2028-2029. A 

biannualbiennial state report is required starting in 2030 and 

beyond covering the two calendar years of each reporting period. 

The EPA believes thisThis final reporting schedule will 

reducereduces the reporting frequency for states implementing 

the emission standards approach. and is responsive to comments 

received that different reporting frequencies may be appropriate 

for different type of state plans. The EPA believes that because 

of the federally enforceable emission standards that apply to 

affected EGUs and their corresponding monitoring, reporting and 
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recordkeeping requirements under the emission standards plan 

type, a lesser frequency of reporting by the state is warranted. 

The state must include in each report to the EPA the status 

of implementation of emission standards for affected EGUs under 

the state plan, including current aggregate and individual CO2

emission performance by affected EGUs during the reporting 

period. The state report must include compliance demonstrations 

for affected EGUs and identify whether affected EGUs are on 

schedule to meet the applicable CO2 emission performance rate or 

emission goal during the performance periods and compliance 

periods, as specified in the state plan. 

AsFor rate-based emission trading programs, the report must 

also include for EPA review the state’s review of the 

administration of their state rate-based emission trading 

program, as discussed in more detail in section VIII.F, in each 

report during the interim period (2022-2029), K.2.g. 

As discussed in more detail in section VIII.F, the state 

must include an interim performance check. in the report 

submitted after each of the first two interim step periods. The 

interim performance check will compare the CO2 emission 

performance level identified in the state plan for the 

applicable interim step period versuswith the actual CO2 emission 

performance achieved by affected EGUs during the period. In the 
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report due to the EPA on July 1, 2030, the state must include a 

comparison of the actual CO2 emission performance achieved by 

affected EGUs for the interim period (2022-2029) with the 

interim CO2 emission performance rates or state rate-based or 

mass-based CO2 interim goal, as applicable. The report due on 

July 1, 2030, must also include the actual CO2 emission 

performance achieved by affected EGUs during the interim step 3 

period (2028-2029). Starting in 2032, the biannualbiennial state 

report must include a final performance check to demonstrate 

that the state continuesaffected EGUs continue to meet the final 

CO2 emission performance rates or state rate-based or mass-based 

CO2 goal. 

For states usingstate plans that use the emission standards 

approach and are subject to the corrective measures provisions 

in the emission guidelines, if actual CO2 emission performance 

by(i.e., the emissions or emission rate) of affected EGUs 

exceeds the specified level of CO2 emission performance in the 

state plan by 10 percent or more during any of the specified 

interim step 1 or step 2 reporting periods or during a final 

plan reporting period (after 2030),, the state report must 

include a notification to the EPA that corrective measures have 

been triggered. The same notification is required if actual CO2 

emission performance fails to meet the specified level of 
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emission performance in the state plan for the 8-year interim 

performance period or any final plan reporting period. 

Corrective measures are discussed in detail in section VIII.F. 

c. Additional components required for the state measures 

approach. The EPA is finalizing requirements that a final plan 

submittal using the state measures approach must contain the 

following components, in addition to the components discussed in 

section VIII.D.2.a. We note again that states choosing the state 

measures plan type must use a mass-based state goal.

(1) Identification of interim state mass goal (for 2022-

2029), interim step state mass goals (2022-2024; 2025-2027; 

2028-2029) and final state mass goal (2030 and beyond). 

The state plan submittal must identify the mass-based CO2

emission goal that must be achieved through the plan (expressed 

in tons of CO2). The plan submittal must identify the state CO2 

interim period goal (for 2022-2029), interim step goals (interim 

step goal 1 for 2022-2024; interim step goal 2 for 2025-2027; 

interim step goal 3 for 2028-2029) and final CO2 emission goal of 

2030 and beyond. 

 For each state, the EPA has finalized an interim goal for 

the interim period of 2022-2029 and a final goal to be met by 

2030. For the interim period, the EPA has also finalized three 

interim step goals: interim step 1 goal for 2022-2024, interim 
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step 2 goal for 2025-2027 and interim step 3 goal for 2028-

2029.1067 States are free to establish different interim step 

goals than those the EPA has specified in this final rule. If 

states choose to determine their own interim step goals, the 

state must demonstrate that it will still meet the interim goal 

for 2022-2029 finalized in this action and the plan submittal 

must include in its supporting documentation a description of 

the analytic process, tools, methods, and assumptions used to 

make this demonstration. 

For states participating in a multi-state plan with a joint 

goal (for interim and final periods), the individual state goals 

in the emission guidelines would be replaced with an equivalent 

multi-state goal for each period (interim and final). The joint 

goal would be a sum of the individual mass-based goals of the 

participating states, in tons of CO2. The plan submittal must 

include in its supporting documentation a description of the 

analytic process, tools, methods, and assumptions used to 

calculate the joint multi-state goal. 

(2) Identification of federally enforceable emission 

standards for affected EGUs (if applicable). 

 

1067 In this action, the EPA is providing interim state goals in 

the form of a CO2 emission rate (emission rate-based goal) and in 

the form of tonnage CO2 emissions (mass-based goal). 
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If applicable, the state plan submittal must include any 

federally enforceable CO2 emission standards that apply to 

affected EGUs, and demonstrate that those emission standards 

meet the requirements that apply in the context of an emission 

standards approach, discussed in the preceding section 

VIII.D.2.b. Specifically, the state plan submittal must 

demonstrate that each federally enforceable emission standard is 

quantifiable, non-duplicative, permanent and 

verifiableverifiable, and enforceable. If a state measures plan 

type includes CO2 emission standards that apply to affected EGUs, 

these emission standards must be federally enforceable. 

(23) Identification of backstop of federally enforceable 

emission standards. 

A state measures plan must include a backstop of federally 

enforceable emission standards for affected EGUs that fully 

achieve the interim and final CO2 emission performance rates or 

the state’s interim and final CO2 emission goal if the state plan 

fails to achieve the intended level of CO2 emission performance. 

The backstop emission standards could be based on the federal 

plan, using the federal plan regulations as afinalized model 

rule. that the EPA is proposing in a separate action. For the 

federally enforceable backstop, the state plan submittal must 

identify the federally enforceable emission standards for 
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affected EGUs, demonstrate that those emission standards meet 

the requirements that apply in the context of an emission 

standards approach, discussed in the preceding section, identify 

a schedule and trigger for implementation of the backstop that 

is consistent with the requirements in the emission guidelines 

as discussed in section VIII.C.3.b and identify all necessary 

state administrative and technical procedures for implementing 

the backstop (e.g. how and when the state would notify affected 

EGUs that the backstop has been triggered). Aspects of the 

backstop are discussed in detail in section VIII.C.3.b. 

(4.b.) Identification of state measures. 

(3) Identification of state measures. A state adopting a state 

measures plan approachtype must provide as a part of the supporting 

documentation of its plan submittal, a description of all the state 

enforceable measures the state will rely upon to achieve the requisite 

CO2 emission performance rates or state mass-based goal, the 

applicable state laws or regulations related to such measures, and 

identification of parties or entities implementing or complying with 

such state measures. The state must also include in its supporting 

documentation the schedule and milestones for the implementation of 

the state measures., showing that the measures are expected to achieve 

the mass-based CO2 emission goal for the interim period (including the 

interim step periods) and meet the final goal by 2030. A state 

measures plan submittal that relies upon state measures that include 
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RE and demand-side EE programs and projects must also demonstrate in 

its supporting documentation that the minimum EM&V requirements in the 

emission guidelines apply to those programs and projects. 

(4) Demonstration that the standards and/or measures are 

projected to achieve the CO2 emission performance rates or state 

CO2 emission goal. A state plan submittal must demonstrate that 

the federally enforceable emission standards for affected EGUs, 

if included, and state measures, are sufficient to attain the CO2

emission performance rates or state rate-based or mass-based CO2

emission goal for the interim period of 2022-2029 and the final 

period of 2030 and beyond. The elements required in the state 

demonstration will vary depending on the design of the state 

plan, as described below in this section. 

(a) Demonstration for a state measures state plan. A state 

measures plan submittal must demonstrate that the state 

measures, whether alone or in conjunction with any federally 

enforceable CO2 emission standards, will achieve either the CO2

emission performance rates or the state rate-based or mass-based 

CO2 goals in the emission guidelines for the interim and final 

periods. This includes the interim period of 2022-2029, 

including interim step 1 2022-2024 period, interim step 2 2025-

2027 period, and interim step 3 2028-2029 period (or alternative 

CO2 emission performance step levels adopted by the state, 
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provided they result in achievement of the CO2 emission 

performance rates or state CO2 emission goal during the 2022-2029 

interim period), as well as the final period of 2030 and beyond. 

 A satisfactory demonstration of the future CO2 performance 

of quantifiable and verifiable state-enforceable measures must 

use technically sound quantification methods that are reliable 

and replicable. The demonstration must be supported by the 

methods and measurement procedures by which the federally 

enforceable CO2 emission standards for affected EGUs are reliably 

measured, if these standards are incorporated into the state 

measures state plan. In addition, the demonstration must include 

details about individual state-enforceable measures (or bundled 

measures), timing for implementation and future MWh impacts of 

these measures. The future performance of affected EGUs must be 

based on verifiable and quantifiable energy and emissions 

quantification methods accompanied with underlying analytical 

assumptions and verifiable data sources used to demonstrate 

future CO2 performance by affected EGUs under this type of state 

plan. 

A satisfactory state measures plan demonstration must 

include a state measures CO2 performance projection that shows 

how the measures in the state plan, alone or in conjunction with 

federally enforceable CO2 emission standards, will achieve the 
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future CO2 performance at affected EGUs. Elements of this 

projection must include the following for the interim and final 

periods: 

 An explanation of the tools and emission 

quantification approaches used in the projection 

(described in section VIII.D.2.c.(4)(b). 

 State Measures Plan CO2 Performance Projection that 

includes all state measures and/or emission standards 

in the state plan (see the State Plans Technical 

Support Document for details). 

 Underlying assumptions used in the projection (as 

described below in sections VIII.D.2.c.(4)(b),(c) and 

(d). 

 (b) Emission quantification approaches and tools. The EPA 

received comments on whether we would require specific modeling 

tools and input assumptions. Commenters raised concerns that the 

EPA may require states to use proprietary models because many 

states do not have the financial resources to conduct their own 

modeling using utility dispatch models or capacity expansion 

models. The EPA is not requiring a specific type of emission 

quantification approach or model, as long as the one chosen uses 

technically sound methods that establish a clear relationship 

between electricity grid interactions of the state enforceable 
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measures, affected EGU dispatch, generation cost and operations 

within the time frame outlined in these guidelines. Emission 

quantification methodologies could range from historical 

estimates using growth rate or statistical analysis to electric 

sector energy modeling. If a state chose to include supplemental 

material on emission baseline projections, then the emissions 

quantification method used for both the baseline projection and 

state measure plan scenario should be similar. A state should 

include an explanation of how the emission quantification method 

works and the associated tool(s) that employ the method, as well 

as an explanation for why the methodology and tool chosen is 

best suited for an electric sector analysis of affected EGUs for 

the interim period and final period. The results in the 

demonstration must be verifiable and reproducible using the 

documented assumptions described in the following paragraph. 

The projections of EGU dispatch and generation can differ 

from the EPA’s forecast in the RIA, but should have a clear 

relationship between future electricity demand, costs and 

generation capacity to establish the projected future CO2

emissions from affected EGUs. The following assumptions 

demonstrating the relationship between the state measures and CO2

emission performance of affected EGUs should be documented and 

explained: projected CO2 emission rates in lbs/MWh; projected CO2
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emissions; projected generation at the EGU in MWhs; fuel prices, 

when applicable; heat rates for each affected EGU; wholesale 

electricity prices, when available; projected emission limits 

and/or rates as a result of environmental or economic 

constraints; planned retirements; planned new generation; fuel 

switches at affected EGUs; fixed operations and maintenance 

costs, when applicable; variable operations and maintenance 

costs, when applicable; and planning reserve margins, when 

applicablematter of state law. 

(c) Elements of a rate-based state measures plan. Under a ratebased state measures plan, MWh from state enforceable qualifying 

measures may be used to adjust the CO2 emission rate of affected 

EGUs when demonstrating achievement of the CO2 emission 

performance rates or the state rate-based CO2 goal in the 

emission guidelines. The state plan would include the following 

key information, at a minimum, to demonstrate the rate-based 

state measures plan for affected EGUs are commensurate with the 

state’s goal: 

 a summary of each affected EGU’s anticipated future 

operation characteristics, including annual 

generation, CO2 emissions, capacity and capacity 

factors; 

 planned retirements; 
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 a detailed description of the zero CO2 emitting demandside EE savings and RE generation (and any other 

qualifying MWh) from state measures that will be 

available for use in adjusting the reported CO2

emission rates of affected EGUs, including, but not 

limited to, the amount of generation or savings by 

technology-type (e.g., wind, solar, EE), the physical 

location of the EE measures or RE generation, and any 

other relevant information (e.g., power purchase 

agreements (PPAs) and other long-term power 

contracts); and an explanation, with calculation, of 

how these measures are being used in the projection to 

adjust the CO2 emission rate of affected EGUs; 

 expected electricity demand growth at the state or 

regional level, including the source and basis for 

these estimates (e.g., based on population growth, 

GDP, adoption of demand-side EE or other applicable 

factors); if demand growth is not from NERC, an ISO or 

RTO, EIA or other publicly available source, then the 

projection must include justification and assumptions 

that inform the demand growth used; 

 expected fuel switching at affected EGUs; 

 heat rate improvements; and 
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 any other applicable assumptions used in the 

projection. 

In the state plan demonstration, the state must show the 

calculation of this adjustment from these state enforceable 

actions at their affected EGUs either in aggregate or at each 

affected EGU. As specified in section VIII.G, the zero-emitting 

MWhs of EE and RE can be added to the denominator of the 

emission rate of the affected EGUs. The demonstration should 

illustrate this arithmetic adjustment for rate-based state 

measure plans. 

(d) Elements of a mass-based state measures plan. Under a massbased state measures plan, a state must demonstrate that the 

combined state-enforceable measures, along with any federally 

enforceable CO2 emission standards for affected EGUs, if 

included, will achieve the state mass-based CO2 goal. Because 

these measures could have varying degrees of impact on CO2

emissions from affected EGUs, the approach a state chooses to 

quantify projected emissions impacts should have the capability 

to demonstrate how the combined state enforceable measures are 

impacting CO2 emissions at affected EGUs so that the sum of 

emissions at all affected EGUs will be lower than or achieve the 

state’s CO2 emission goal for each specified time period in the 

emission guidelines. The EPA is not requiring a specific method 
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or tool, but clear documentation of assumptions and explanation 

of methods used, as discussed in section VIII.D.2.c and in the 

State Plans Technical Support Document, must be included in a 

satisfactory demonstration. 

(5) State reporting requirements. 

After consideration of the comments received regarding 

state reporting requirements, the EPA is requiring in this final 

rule for states using the state measures approach that an annual 

state report is due to the EPA no later than July 1 following 

the end of each calendar year during the interim period. This 

annual state report must include the status of implementation of 

federally enforceable emission standards (if applicable) and 

state measures, and shouldmust include a report of the periodic 

programmatic milestones to show progress in program 

implementation. The programmatic milestones with specific dates 

for achievement should be appropriate to the state measures 

included in the state plan submittal. The EPA believes that 

annual state reporting is appropriate for state measures 

approach due to the flexibility inherent to the approach 

described in section VIII.C.3 including the potential use by the 

state of a wider variety of state measures, responsible parties, 

etc. This reporting frequency will also increase the degree of 

certainty on plan performance for states pursuing the state 
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measures approach. 

As discussed in section VIII.F, for states using the state 

measures approach, the EPA is finalizing that at the end of 

eachthe first two interim step periodperiods, the state must 

also include in their annual report to the EPA the corresponding 

emission performance checks. The interim performance checks will 

compare the CO2 emission performance level identified in the 

state plan for the applicable interim step period versus the 

actual CO2 emission performance achieved by the aggregate of 

affected EGUs. In the report submitted to the EPA on July 1, 

2030, the state must also report the actual CO2 performance check 

for the interim period (2022-2029) with the interim mass-based 

CO2 goal, as well as the actual CO2 emission performance achieved 

by affected EGUs during the interim step 3 period (2028-2029). 

Beginning with the final period, the state must submit 

biannualbiennial reports no later than July 1 after the end of 

each reporting period that includes an actual performance check 

to demonstrate that the state continues to meet the final CO2

emission performance rates or state CO2 goal. 

If, at the time of the state report to the EPA, the state 

didhas not meetmet the programmatic milestones for the reporting 

period, or the performance check shows that the actual CO2

emission performance byof affected EGUs exceeds the specified 
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level of emission performance in the state plan submittal by 10 

percent or more,warrants implementation of backstop 

requirements,1068 the state must include in the state report a 

notification to the EPA that the backstop has been triggered and 

describe the steps taken by the state to inform the affected 

EGUs that the backstop has been triggered. In the event of such 

an exceedance under the state measures approach, the backstop 

federally enforceable emission standards for the EGUs must be 

effective within 18 months of the deadline for the state 

reporting to the EPA on plan implementation and progress toward 

the meeting the CO2 emission performance rates or state CO2

emission goal. For example, if a state report due on July 1, 

2025, shows that actual CO2 emission performance byof affected 

EGUs exceedsis deficient by 10 percent or more relative to the 

specified level of emission performance for 2022-2024 in the 

state plan by 10 percent or more, the backstop federally 

 

1068 As explained in section VIII.C.3.b, state plans subject to 

the backstop requirement must require the backstop to take 

effect if actual CO2 emission performance by affected EGUs fails 

to meet the level of emission performance specified in the plan 

over the 8-year interim performance period (2022-2029), or for 

any 2-year final goal performance period. The plan also must 

require the backstop to take effect if actual emission 

performance is deficient by 10 percent or more relative to the 

performance levels that the state has chosen to specify in its 

plan for the interim step 1 period (2022-2024) or the interim 

step 2 period (2025-2027).
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enforceable emission standards for affected EGUs must be 

effective as of January 1, 2027. 

(76) Supporting documentation. 

(a) Demonstration that each state measure is quantifiable, 

non-duplicative, permanent, verifiable and enforceable. 

A state using the state measures approach, in support of 

its plan, must also include in the supporting documentation of 

the state plan submittal the state measures1069 that are not 

federally enforceable emission standards, and describe how each 

state measure is quantifiable, non-duplicative, permanent, 

verifiable, and enforceable with respect to an affected entity. 

A state measure is quantifiable if it can be reliably 

measured, using technically sound methods, in a manner that can 

be replicated. 

A state measure is non-duplicative with respect to an 

affected entity if it is not already incorporated as a state 

measure or an emission standard in another state plan or state 

plan supporting material, except in instances where incorporated 

in another state as part of a multi-state plan. An example of a 

duplicative state measure would occur, for example, where a 

 

1069 “State measures” refer to measures that the state adopts and 

implements as a matter of state law. Such measures are 

enforceable only per applicable state law, and are not included 

in the federally enforceable state plan. 
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quantified and verified MWh from a wind turbine could be applied 

in more than one state’s CAA section 111(d) plan to adjust the 

CO2 emission rate of an affected EGU, except in the case of a 

multi-state plan where CO2 emission performance is demonstrated 

jointly for all affected EGUs subject to the multi-state plan. 

This does not mean that measures in a state measure cannot also 

be used for other purposes. For example actions taken pursuant 

to CAA section 111(d) requirements can satisfy other CAA program 

requirements (e.g., Regional Haze requirements, MATS etc.)) and 

state requirements (e.g., RPS). 

A state measure is permanent if the state measure must be 

met for each applicable compliance period. 

A state measure is verifiable if adequate monitoring, 

recordkeeping and reporting requirements are in place to enable 

the state to independently evaluate, measure and verify 

compliance with it. 

A state measure is enforceable1070 if: (1) it: (1) represents 

a technically accurate limitation or requirement and the time 

period for the limitation or requirement is specified,; (2) 

compliance requirements are clearly defined,; (3) the affected 

entities responsible for compliance and liable for violations 

 

1070 Under the state measures approach, state measures are 

enforceable only per applicable state law. 
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can be identified,; and (4) each compliance activity or measure 

is practically enforceable in accordance with EPA guidance on 

practical enforceability,1071 and the state maintains the ability 

to enforce against affected EGUs for violations and secure 

appropriate corrective actions pursuant to its plan or state 

law. 

The EPA will disapprove a state plan if the documentation 

is not sufficient for the EPA to be able to determine whether 

the state measures are expected to yield CO2 emission reductions 

sufficient to result in the necessary CO2 emission performance 

from affected EGUs for the CO2 emission performance rates or 

state CO2 emission goal to be achieved. 

d. Legal basis for the components. 

(1) General legal basis. 

Under section 111(d), state plans must “provide for the 

implementation and enforcement of [the] standards of 

 

1071 The EPA’s prior guidance on enforceability serves as the 

foundation for the types of measures that the EPA has found can 

be, as a practical matter, enforced. The EPA’s guidance on 

enforceability includes: (1) September 23, 1987, memorandum and 

accompanying implementing guidance, “Review of State 

Implementation Plans and Revisions for Enforceability and Legal 

Sufficiency,” (2) August 5, 2004, “Guidance on SIP Credits for 

Emission Reductions from Electric-Sector Energy Efficiency and 

Renewable Energy Measures,” and (3) July 2012 “Roadmap for 

Incorporating Energy Efficiency/Renewable Energy Policies and 

Programs into State and Tribal Implementation Plans,” Appendix 

F. 
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performance.” Similar language occurs elsewhere in the CAA. 

First, for SIPs, section 110(a)(1) requires SIPs to “provide for 

implementation, maintenance, and enforcement” of the NAAQS. 

However, section 110(a)(2), unlike 111(d), details a number of 

specific requirements for SIPs that, in part, speak exactly to 

how a SIP should “provide for implementation, maintenance, and 

enforcement” of the NAAQS. We note that section 111(d) provides 

explicitly only that the “procedures,” and not the substantive 

requirements, for section 111(d) state plans should be “similar” 

to those in section 110, and thus a substantive requirement in 

section 110(a)(2) is not an independent source of authority for 

the EPA to require the same for section 111(d) plans. However, 

when there is a gap for the EPA to fill in interpreting how a 

section 111(d) plan should “provide for implementation and 

enforcement of the] standards of performance,” and Congress 

explicitly addressed a similar gap in section 110, then it may 

be reasonable for the EPA to fill the gap in section 111(d) 

using an analogous mechanism to that in section 110(a)(2), to 

the extent that the section 110(a)(2) requirement makes sense 

and is reasonable in the context of section 111(d). On the other 

hand, that Congress did not explicitly provide such details as 

are found in section 110(a)(2) indicates that Congress intended 

to give the EPA considerable leeway in interpreting the 
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ambiguous phrase “provides for implementation and enforcement of 

[the] standards of performance.” 

For example, section 110(a)(2)(E)(i) explicitly requires 

states to provide necessary assurances that they have adequate 

personnel, funding and authority to carry out the SIP. Section 

111(d), on the other hand, does not explicitly contain this 

requirement. Thus, there is a gap to fill with respect to this 

issue when the EPA interprets section 111(d)’s requirement that 

plans “provide for implementation and enforcement” of the 

standards of performance, and it is reasonable for the EPA to 

fill the gap by requiring adequate funding and authority, both 

because adequate funding and authority are fundamental 

prerequisites to adequate implementation and enforcement of any 

program, and because Congress has explicitly recognized this 

fundamental nature in the section 110 context.1072 

We note two other places where the CAA requires a state 

program to satisfy similar language regarding implementation and 

enforcement. First, section 112(l)(1) allows states to adopt and 

 

1072 On the other hand, there are specific requirements in 

110(a)(2) that are fundamental for SIPs, but would not make 

sense in the 111(d) context. For example, the specific 

requirement for an ambient air quality monitoring network in 

110(a)(2)(B) is irrelevant in the 111(d) context. For a detailed 

discussion of the specific legal basis for each component, 

please see the Legal Memorandum for this final rule. 
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submit a program for “implementation and enforcement” of section 

112 standards. Section 112(l)(5) further provides that the 

program must (among other things) have adequate authority to 

enforce against sources, and adequate authority and resources to 

implement the program. Second, section 111(c) provides that, if 

a state develops and submits “adequate procedures” for 

“implementing and enforcing” section 111(b) standards of 

performance for new sources in that state, the Administrator 

shall delegate to the state the Administrator’s authority to 

“implement and enforce” those standards. The EPA has interpreted 

these ambiguous provisions in the EPA’s “Good Practices Manual 

for Delegation of NSPS and NESHAPS” and recommended (in the 

context of guidance) that state programs have a number of 

components, such as source monitoring, recordkeeping, and 

reporting, in order to adequately implement and enforce section 

111(b) or 112 standards. This again indicates it is reasonable 

for the EPA to fill a gap in section 111(d)’s language and 

similarly require source monitoring, recordkeeping, and 

reporting, as these are fundamental to implementing and 

enforcing standards of performance that achieve the state 

performance rates or goals. 

Some commenters argued that states have primary authority 

over the content of state plans and that the EPA lacks authority 
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to disapprove a state plan as unsatisfactory simply because it 

lacks one or more of these components. We disagree. The EPA has 

the authority to interpret the statutory language of section 

111(d) and to make rules that effectuate that interpretation. 

With respect to the components of an approvable plan, we are 

interpreting the statutory phrase “provide for implementation 

and enforcement” and making rules that set out the minimum 

elements that are necessary for a state plan to be 

“satisfactory” in meeting this statutory requirement. This does 

not in any way intrude on the state’s ability to decide what mix 

of measures should be used to achieve the necessary emission 

reductions. Nor does it intrude in any way on the state’s 

ability to decide how to satisfy a component. For example, for 

legal authority, we are not dictating which state agencies or 

officials must specifically have the necessary legal authority; 

that is entirely up to the state so long as the fundamental 

requirement to have adequate legal authority to implement and 

enforce the plan is met. 

In addition, the EPA has already determined in the 1975 

implementing regulations that certain components, such as 

monitoring, recordkeeping, and reporting, are necessary for 

implementation and enforcement of section 111(d) standards of 

performance. 40 FR 53340, 53348/1 (Nov. 17, 1975). Thus, EPA’s 
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position here is hardly novel. The EPA notes in discussing the 

implementing regulations, nothing in this final rule reopens 

provisions or issues that were previously decided in the 

original promulgation of the regulations unless otherwise 

explicitly reopened for this rule.

(2) Legal issuesconsiderations with changes to affected 

EGUs. 

In the proposed rulemaking, the EPA tookproposed the 

positioninterpretation that if an existing source is subject to 

a section 111(d) state plan, and then undertakes a modification 

or reconstruction, the source remains subject to the state plan, 

while also becoming subject to the modification or 

reconstruction requirements. 79 FR 34830, 34903–4. We noted that 

section 111(d) is silent as to this issue, which we took to 

grant us authority to provide a reasonable interpretation under 

the Supreme Court’s decision in Chevron U.S.A. Inc. v. NRDC, 467 

U.S. 837, 842–844 (1984). We stated two reasons to disallow 

existing sources to escape 111(d) through modification or 

reconstruction. First, if a source did so, that could prove 

disruptive to the state plan. Second, allowing sources to do so 

could provide them an incentive to do so that would be contrary 

to the purposes of 111(d). We then asked for comment on “whether 

this interpretation is supported by the statutory text and 
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whether this interpretation is sensible policy and will further 

the goals of the statute.”The EPA is not finalizing a position 

on this issue in this final rule, and is re-proposing and taking 

comment on this issue through the federal plan rulemaking being 

proposed concurrently with this action. The EPA’s deferral of 

action on this issue does not impact states’ and affected EGUs’ 

pending obligations under this final rule relating to plan 

submission deadlines, as this issue concerns potential 

obligations or impacts after an existing source is subject to 

the requirements of a state plan. The EPA will propose and 

finalize its position on this issue through the federal plan 

rulemaking, which will be well in advance of the plan 

performance period beginning in 2022, at which point state plan 

obligations on existing sources are effectuated. 

 With respect to our request for comments on whether our 

proposed interpretation is supported by the statutory text, we 

received comments arguing that it violates the statute. The 

commenters noted that section 111(a)(6) defines “existing 

source” as “any stationary source other than a new source,” and 

section 111(a)(2) defines “new source” to include stationary 

sources that are constructed or modified after “the publication 

of regulations (or, if earlier, proposed regulations) 

prescribing a standard of performance under [section 111] which 
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will be applicable to such source.” The comments concluded from 

this that the two categories are mutually exclusive, regardless 

of section 111(d)’s silence on the issue. The comments also 

noted that section 111(d)(1) only allows states to impose 

standards of performance in 111(d) plans on existing sources “to 

which a standard of performance under [111] would apply if such 

existing source were a new source,” from which the comments 

inferred that states lacked authority under 111(d) to regulate 

sources that are regulated under 111(b). 

 We do not completely agree with these comments, which 

“prove too much.” It is not the case that a source can never be 

both an existing source and a new source within the meaning of 

sections 111(a)(6) and 111(a)(2), respectively. First, a source 

that was a new source under 111(b) standards of performance for 

one pollutant can of course later become an existing source 

under 111(d) for another pollutant when the EPA promulgates 

111(b) standards of performance and 111(d) emission guidelines 

for the second pollutant. Any other result would be 

illogical. Second, we have taken the position under section 129 

(which has similar but not identical definitions) that a new 

source can subsequently become an existing source under revised 

129(b) guidelines. E.g., 74 FR 51368, 51374-75 (Oct. 6, 2009). 

Thus, the comments’ “plain meaning” argument fails to take into 
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account context such as these. 

 However, we do agree that, in the particular context here, 

i.e. when section 111(d) emission guidelines are initially 

promulgated for existing stationary sources in response to 

corresponding section 111(b) standards of performance for the 

same pollutant, that the statute prohibits new sources 

(including under those particular 111(b) standards of 

performance from simultaneously being subject to state plans 

under those particular 111(d) emission guidelines. This 

interpretation gives meaning to the definition of “existing 

source” in section 111(a)(6) and is consistent with the 

definition of “new source” in section 111(a)(2). And, it is 

consistent with the historical treatment of modified and 

reconstructed sources in the section 111 program. The EPA plans 

to address ways to minimize disruption to state plans if such a 

modification or reconstruction were to take place. 

 We believe our final interpretation could reasonably be 

anticipated from our proposal notice. Although our notice 

proposed only a different interpretation of the statute, we did 

not indicate that the proposed interpretation was a settled 

matter (for example, based on previous EPA practice), and we 

invited comment on whether our interpretation was supported by 

the statute. Furthermore, we are basing our final position on 
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the language of sections 111(a)(2) and 111(a)(6), which were 

quoted in our discussion of this exact issue in our proposal 

notice. 79 FR 34830, 34903/3. Thus, we gave adequate notice of 

the relevant provisions of the statute, and it could not be 

unfair surprise that sections 111(a)(2) and 111(a)(6) formed the 

basis of our ultimate position. Finally, there are a very 

limited number of potential interpretations of these provisions 

with respect to this issue; thus our final position could be 

reasonably anticipated. 

(3) Legal issuesconsiderations regarding design, equipment, 

work practice or operational standards. 

In the proposal, the EPA asked for comment on three 

approaches to inclusion of design, equipment, work practice and 

operational standards in section 111(d) plans. 79 FR 34830, 

34926/3 (June 18, 2014). Under the first approach, states would 

be precluded from including these standards in section 111(d) 

plans unless the design, equipment, work practice or operational 

standard could be understood as a “standard of performance” or 

could be understood to “provide for implementation and 

enforcement” of standards of performance. We also asked, for the 

first approach, whether it was even possible, given the 

statutory language of 111(h), to consider a design, equipment, 

work practice or operational standard as a “standard of 
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performance.” Under the second approach, states could include 

design, equipment, work practice or operational standards in the 

event that it could be shown a “standard of performance” was not 

feasible, as set out in section 111(h). Under the third 

approach, a state could include design, equipment, work practice 

and operational standards in a 111(d) plan without any 

constraints. We also asked whether, if there was legal 

uncertainty as to the status of these standards, the EPA should 

authorize states to include them in their 111(d) plans with the 

understanding that if the EPA’s authorization were invalidated 

by a court, states would have to revise their plans accordingly. 

The EPA is finalizing the first approach. Specifically, a 

state’s standards of performance (in other words, either the 

federally enforceable backstop under the state measures approach 

or the emissionsemission standards under the emissionsemission

standards approach) cannot consist of (in whole or part) design, 

equipment, work practice or operational standards. A state may 

include such standards in a 111(d) plan in order to implement 

the standards of performance. For example, a state taking a 

mass-based approach may include in its 111(d) plan a limit on 

hours of operation on a particular affected EGU, but that 

operational standard itself cannot substitute for a mass-based 
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limitemission standard on the affected EGU.1073 

This follows from the statute. First, section 111(h)(1) 

authorizes the Administrator, when it is not feasible for 

certain reasons (specified in 111(h)(2)) to prescribe or enforce 

a standard of performance, to instead promulgate a design, 

equipment, work practice or operational standard. If a standard 

of performance could include design, equipment, work practice or 

operational standards, such authority would be unnecessary. 

Second, 111(h)(5) states that design, equipment, work practice 

or operational standards “described in” 111(h) shall be treated 

as standards of performance for the purposes of the CAA. This 

creates a strong inference that standards of performance 

otherwise should not include design, equipment, work practice, 

or operational standards. Finally, the general definition of 

“standard of performance” in section 302(l) is similar to the 

definition of “emission limitation” (or “emission standard”) in

section 302(k), with the exception that the definition of 

“emission limitation” explicitly includes design, equipment, 

work practice and operational standards, but the definition of 

“standard of performance” omits them. Thus, as with our 

 

1073 In particular, a state may include in its 111(d) state plan 

an emission standard that is reflective of the CO2 performance 

resulting from operational standards the state imposes on an 

affected EGU. 
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discussion of the term “standard of performance” above in 

VIII.B.7.e(1),C.6.b, even if the general definition of “standard 

of performance” in 302(l) applies to 111(d), the omission of 

design, equipment, work practice, and operational standards in 

302(l) confirms our interpretation that they cannot be a 111 

“standard of performance” (except under the limited 

circumstances in 111(h)). We conclude that it is reasonable, and 

perhaps compelled, to interpret the term “standards of 

performance” in 111(d) to not include design, equipment, work 

practice and operational standards. 

However, section 111(d) requires plans to “provide for 

implementation and enforcement of [the] standards of 

performance.” This language does not explicitly prohibit a plan 

from including design, equipment, work practice and operational 

standards, and allows for them to be included so long as they 

are understood to provide for implementation of the standards of 

performance. If they are included, the 111(d) plan must still be 

“satisfactory” in other respects, in particular in establishing 

standards of performance that are not in whole or in part 

design, equipment, work practice, and operational standards. 

(4) Legal basis for engagement with communities. 

As previously discussed, section 111(d)(1) requires the EPA 

to promulgate procedures “similar” to those in section 110 under 
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which states adopt and submit 111(d) plans. Section 110(a)(1) 

requires states to adopt and submit implementation plans “after 

reasonable notice and public hearings.” The implementing 

regulations under 40 CFR 60.27 reflect similar public 

participation requirements with respect to section 111(d) state 

plans. The EPA is sensitive to the legal importance of adequate 

public participation in the state plan process, including public 

participation by affected communities. As previously discussed 

in this rule, recent studies also find that certain communities, 

including low-income communities and some communities of color, 

are disproportionately affected by certain climate change -

related impacts. Because certain communities have a potential 

likelihood to be impacted by state plans for this rule, the EPA 

believes that the existing public participation requirements 

under 40 CFR 60.23 are effectuated for the purposes of this 

final rule by states engaging in meaningful, active ways with 

such communities. By requiring states to demonstrate how they 

have meaningfully engaged with affectedvulnerable communities 

potentially impacted by state plans as part of the state plan 

development process, states meeting this requirement will 

satisfy the applicable statutory and regulatory requirements 

regarding public participation. 

3. Components of the federally approved state plan
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In this action the EPA finalizes that, to be fully 

approved, a state plan submittal must meet the criteria and 

include the required components described above. The EPA will 

propose and take final action on each state plan submittal in 

the Federal Register and provide an opportunity for notice and 

comment. When a state plan submittal is approved by the EPA, the 

EPA will codify the approved 111(d) state plan in 40 CFR part 

62. The following components of the state plan submittal will 

become the federally enforceable state 111(d) plan: 

 Federally enforceable emission standards for affected EGUs 

 Federally enforceable backstop of emission standards for 

affected EGUs 

 Implementing and enforcing measures for federally 

enforceable emission standards including EGU monitoring, 

recordkeeping and reporting requirements 

 State recordkeeping and reporting requirements 

E. State Plan Submittal and Approval Process and Timing 

1. Overview 

 In this action the EPA is finalizing that state plan 

submittals are due on August 31, 2016, which is 13 months after 

finalization of the emission guidelines. The EPA recognizes that 

due to state legislative schedules and rulemaking processes, 

coordination needed among states involved in multi-state plans, 
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coordination with third parties, and the complex technical work 

needed to develop a state plan, states may not be able to 

develop a final plan submittal by 13 months after the final 

rule. However, various states have existing CO2 reduction 

programs in place, such as RE and demand-side EE measures, as 

well as state and regional programs designed to reduce CO2

pollution from EGUs. Furthermore, state governments have already 

begun active discussions on how to address the final rule 

through policy forums, white papers and non-profit 

organizations. The EPA is also in the process of developing a 

federal plan that states may wish to use as a model rule. The 

EPA views these actions as positive steps that make the 13-month 

timeline achievable. In order to address the concern that 13 

months is not sufficient time for states to prepare and submit a 

final plan submittal and to allow consistent timelines for both 

a single state and multi-state approach to state plan 

submittals, the EPA is also finalizing a plan submittal process 

that provides additional time for states that need it to submit 

a final plan submittal to the EPA after August 31, 2016. This 

approach involves the option that we refer to as an initial 

submittal, followed by submittal of a final state plan submittal 

no later than August 31, 2018, for both single state and multistate plan submittals. During the initial outreach process as 
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well as the public comment period on the proposed rule, 

stakeholders commented that additional time was needed to 

accommodate, among other things, state legislative and 

rulemaking schedules, coordination among states involved in 

multi-state plans, coordination with third parties, and the 

complex technical work needed to develop a state plan. The EPA 

recognizes that state administrative procedures can be lengthy, 

some states may need new legislative authority, and states 

planning to join in a multi-state plan will likely need more 

than 13 months to get necessary elements in place. Balanced 

against that concern, however, is the urgency of addressing CO2

emissions and the fact that there are certain steps the EPA 

believes states can take within 13 months to set themselves on a 

clear path to adoption of a final plan. 

 In this action the EPA is finalizing that state plan 

submittals are due on September 6, 2016, with the option of an 

extension to submit final state plans by September 6, 2018, 

which is 3 years after finalization of this rule. The compelling 

nature of the climate change challenge, and the need to begin 

promptly what will be a lengthy effort to implement the 

requirements of these guidelines, warrant this schedule. The EPA 

also believes, for reasons further described in the next 

section, why this schedule is achievable for states to submit 
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final plans. We discuss the timing of state plans in more detail 

in this section below. 

Discussed in the following sections are state plan 

submittal and timing, required components for initial submittals 

and the 2017 update, multi-state plan submissions, process for 

EPA review of state plans, failure to submit a plan, state plan 

modifications (including modifications to interim and final CO2

emission goals), plan templates and electronic submittal, and 

legal bases regarding state plan process. 

2. State plan submittal and timing 

The implementing regulations (40 CFR 60.23) require that 

state plans be submitted to the EPA within 9 months of 

promulgation of the emission guidelines, unless the EPA 

specifies otherwise.1074 For these 111(d) guidelines, the EPA is 

finalizing that each state must by September 6, 2016, either 

submit a final plan submittal or seek an extension to submit a 

final plan by September 6, 2018. In the case of a state electing 

to participate in the CEIP, this 2016 submittal must include a 

non-binding statement of intent to participate in the program. 

To seek an extension of the September 6, 2016 deadline until no 

later than September 6, 2018, a state must submit an initial 

 

1074 40 CFR 60.23(a)(1). 
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submittal by September 6, 2016, that addresses three required 

components sufficiently to demonstrate that a state is able to 

undertake steps and processes necessary to timely submit a final 

plan by the extended date of September 6, 2018. If an extension 

is requested and granted, states must also submit a 2017 update 

by September 6, 2017, that documents the state’s continued 

progress towards meeting the September 6, 2018 final plan 

submittal deadline. 

In the proposal, EPA proposed a 13 month final state plan 

submittal deadline, with a 1 year possible extension for states 

submitting individual state plans and a 2 year possible 

extension for states submitting multi-state plans as part of a 

multi-state region. The EPA received substantive comment on the 

achievability of these proposed deadlines for state plan 

submittals. Multiple commenters expressed concern that due to 

timing of legislative cycles (some of which are every 2 years), 

regulatory processes, and other necessary tasks, states would 

find it extremely difficult to submit plans in 1 or 2 years, 

whether or not they were planning to submit as part of a multistate region. The EPA agrees based on this input that a schedule 

shorter than 3 years will be challenging for many — though not 

all - states. In light of the comments received and in order to 

provide maximum flexibility to states while still taking timely 
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action to reduce CO2 emissions, in this final rule the EPA is 

allowing for a 2 year extension until September 6, 2018, for 

both individual and multi-state plans, to provide a total of 3 

years for states to submit a final plan if an extension is 

received. Based on comments received, information the EPA has 

regarding steps states have already begun taking towards plan 

development, and extensive experience with similar state plan 

submission deadlines under CAA section 110 state implementation 

plans, the EPA believes states will be able to submit final 

plans within 3 years by September 6, 2018, in the event states 

are not required to submit a final plan by September 6, 2016. We 

address the substantive requirements of initial submittals and 

the 2017 update in the next section. States that receive 2-year 

extensions may submit the final plan earlier than September 6, 

2018, if they so choose. 

The EPA highlights one purpose of the initial submittal is 

to encourage and potentially facilitate states to do necessary 

planning and engagement with stakeholders so states are able to 

submit an approvable final state plan by the extended deadline 

of September 6, 2018. Some states have well-developed existing 

programs and the attendant legal authority underpinning such 

programs to more easily meet the September 6, 2016 deadline by 

submitting a final plan which largely contains or relies upon 
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such existing programs.1075 Based on comments and stakeholder 

feedback, however, the EPA anticipates that many states 

intending to develop and submit a final plan will seek the 

optional extension given the time it may take to undergo 

necessary legislative, stakeholder, and planning processes. The 

EPA acknowledges that the initial submittal of September 6, 

2016, is not essential to the ability for states to submit final 

plans by September 6, 2018, so that even without this 2016 

deadline, the EPA could require states to meet the 2018 

deadline. Even so, this earlier date in the 3 year planning 

process serves as a useful “check-in” that provides several 

significant advantages. First, this earlier date provides all 

states an opportunity to understand what approaches other states 

are considering. Because there are significant benefits to 

regional cooperation, the EPA believes that a formal process to 

collect and then provide this information will help all states 

develop better plans. Second, because the guidelines provide 

significant flexibility, the ability for the EPA to provide 

early input to states who may be pursuing more innovative 

approaches will help ensure that all state plans are ultimately 

 

1075 Based on comments received, we understand that the Northeast 

and Mid-Atlantic states that participate in RGGI may be in this 

position.
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approvable. The EPA therefore believes the initial submittal is 

an appropriate means by which to offer the optional extension, 

and for reasons further described in section VIII.E.3, that the 

requirements of the initial submittal are achievable by 

September 6, 2016, so states will be able to develop and submit 

a plan that meets the requirements of the final emission 

guidelines and section 111(d) of the CAA by the extended date. 

Additionally, some states may not submit a state plan as 

required by the final emission guidelines and section 111(d) of 

the CAA. For states that do not submit a state plan, the CAA 

gives the EPA express authority to implement a federal plan for 

sources in that state upon determination by the EPA that a state 

has failed to submit a state plan by the required date. For 

states that do not intend to submit a state plan to meet the 

obligations of this final rule, by promulgating a federal plan 

for affected EGUs in states that do not submit a plan by 

September 6, 2016, such affected EGUs would have an additional 2 

years to plan for and determine compliance strategies than had 

promulgation of a federal plan been predicated on states failing 

to submit a plan by September 6, 2018. The EPA also notes that 

this final rule affords states and affected EGUs with many 

implementation flexibilities and approaches for state plans that 

the EPA itself may not have the authority to implement through a 
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federal plan. Therefore, affected EGUs subject to a federal plan 

promulgated for a state that refuses to submit a state plan may 

benefit from an additional 2 years to plan for compliance with a 

federal plan with potentially fewer flexibilities. 

If no affected EGU is located within a state, the state 

must submit a letter to the EPA certifying that no such 

facilities exist by September 6, 2016.1076 The EPA will publish a 

notice in the Federal Register to notify the public of receipt 

of such letters. If an affected EGU is later found to be located 

in that state, the state must submit a final plan addressing 

such affected EGU or the EPA will determine the state has failed 

to submit a plan as required by the emission guidelines and CAA 

section 111(d), and begin the process of implementing a federal 

plan for that affected EGU. 

In the case of a tribe that has one or more affected EGUs 

located in its area of Indian country, if the tribe either does 

not submit a CAA section 111(d) plan or does not receive EPA 

approval of a submitted plan, the EPA has the responsibility to 

establish a CAA section 111(d) plan for that area if it 

determines that such a plan is necessary or appropriate to 

protect air quality.1077 See the proposed federal plan rulemaking 

 

1076 40 CFR 60.23(b). 1077 See 40 CFR 49.1 to 49.11. 
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for further information. 

The EPA notes that the current implementing regulations at 

40 CFR part 60 do not specify who has the authority to make a 

formal submission of the state plan to the EPA for review. In 

order to clarify who on behalf of a state is authorized to 

submit an initial submittal, 2017 update, final state plan (or 

negative declaration, if applicable), and any revisions to an 

approved plan, the EPA has included a requirement in this final 

rule mirroring that of the requirement in 40 CFR part 51 App. 

V.2.1.(a) with respect to SIPs that identifies the Governor of a 

state as the authorized official for submitting the state plan 

to the EPA. If the Governor wishes to designate another 

responsible official the authority to submit a state plan, the 

EPA must be notified via letter from the Governor prior to the 

2016 deadline for plan submittal so that they have the ability 

to submit the initial submittal or final plan in the State Plan 

Electronic Collection System (SPeCS). If the Governor has 

previously delegated authority to make CAA submittals on the 

Governor’s behalf, a state may submit documentation of the 

delegation in lieu of a letter from the Governor. The letter or 

documentation must identify the designee to whom authority is 

being designated and must include the name and contact 

information for the designee and also identify the state plan 
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preparers who will need access to SPeCS discussed in section 

VIII.E.8. A state may also submit the names of the state plan 

preparers via a separate letter prior to the designation letter 

from the Governor in order to expedite the state plan 

administrative process. Required contact information for the 

designee and preparers includes the person’s title, organization 

and email address. The EPA recommends this information be 

submitted early in the state planning process to allow 

sufficient time for completion of SPeCS registration so that 

those authorized to use the system are provided access. 

3. Components of an initial submittal and 2017 update 

As noted, states may request a 2-year extension to submit a 

final plan through making an initial submittal by September 6, 

2016. For the extension to be granted, the EPA is finalizing 

that the initial submittal must address three required 

components sufficiently to demonstrate that a state is able to 

undertake steps and processes necessary to timely submit a final 

plan by the extended date of September 6, 2018:1078 

 An identification of final plan approach or approaches 

under consideration, including a description of progress 

 

1078 As stated previously, in the case of a state electing to 

participate in the Clean Energy Incentive Program, this 2016 

submittal must include a non-binding statement of intent to 

participate in the program. 
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made to date. 

 An appropriate explanation for why the state requires 

additional time to submit a final plan by September 6, 

2018. 

 Demonstration or description of opportunity for public 

comment on the initial submittal and meaningful 

engagement with stakeholders,1079 including vulnerable 

communities, during the time in preparation of the 

initial submittal and plans for engagement during 

development of the final plan. 

During the public comment period, multiple commenters 

stated that the proposed timeframe for states to submit an 

initial submittal was not achievable, citing, among other 

things, the number of decisions needed to be made by a state or 

states, and that the EPA needed to clarify the requirements for 

an initial submittal. Multiple commenters also expressed concern 

that the requirements for an initial submittal required final 

decisions to be made by states, and that the initial submittal 

deadline was not enough time for states to make these decisions. 

It is important to note that the EPA is not requiring the 

 

1079 Such stakeholders may include labor unions and workers that 

have an interest in the state plan, and communities whose 

economies are dependent on coal. 
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adoption of any enforceable measures or final decisions in order 

for the state to address any of the initial submittal components 

by September 6, 2016. The EPA believes the absence of requiring 

enforceable measures to be included with the initial submittal 

greatly supports the ability of states intending to develop a 

final state plan to submit an initial submittal by September 6, 

2016. States are required to submit enforceable measures 

supported by technically complex documentation, such as 

modeling, and adopted through state public participation and 

regulatory or legislative processes as part of SIPs under other 

parts of the CAA within timeframes comparable to the time the 

EPA is providing for initial submittals.1080 

In order to further address the commenters’ concerns 

regarding possible ambiguity of the requirements for an initial 

submittal so that an extension is granted, the EPA is providing 

clarity regarding the required components for an initial 

submittal. Regarding the component that states address an 

appropriate explanation for an extension, the EPA proposed that 

 

1080 For example, 13 states were required to submit SIP revisions 

sufficient to regulate GHGs under the Prevention of Significant 

Deterioration (PSD) permitting requirements of the CAA within 

either 3 weeks or 12 months in response to the EPA’s SIP call. 

See “Action To Ensure Authority To Issue Permits Under the 

Prevention of Significant Deterioration Program to Sources of 

Greenhouse Gas Emissions: Finding of Substantial Inadequacy and 

SIP Call”, 75 FR 77698, (December 13, 2010). 
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appropriate explanations for seeking an extension beyond 2016 

for submitting a final plan include: a state’s required schedule 

for legislative approval and administrative rulemaking, the need 

for multi-state coordination in the development of an individual 

state plan, or the process and coordination necessary to develop 

a multi-state plan. In this final rule, the EPA is finalizing 

these as appropriate explanations for seeking an extension 

beyond 2016, but makes clear — as explained further below — that 

other appropriate explanations will be acceptable as well. It is 

important to note that the initial submittal does not require 

legislation and/or regulations to be passed prior in order for 

the state to be granted an extension, but the initial submittal 

should describe any concrete steps the state has already taken 

on legislation and/or administrative rulemaking and detail what 

the remaining steps are in those processes before a final plan 

can be submitted. The EPA also sought comment on other 

circumstances for which an extension of time would be 

appropriate, and also whether some explanations for extensions 

should not be permitted. Commenters stated that states should be 

able to seek extensions whenever an extension can be reasonably 

justified, and that the EPA should take at face value states’ 

good faith efforts by accepting any state assertion that more 

time is needed to develop a plan unless there is clear evidence 
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to the contrary. The EPA believes there may be appropriate 

explanations states may submit in addition to the ones described 

in this final rule sufficient to demonstrate that a state is 

able to undertake steps and processes necessary to timely submit 

a final plan by the extended date of September 6, 2018. Given 

the opportunity for states to submit appropriate explanations 

other than the ones detailed here, the EPA believes addressing 

this component requiring an appropriate explanation for an 

extension is easily achievable by September 6, 2016. 

In order to additionally clarify the required components of 

the initial submittal, the following are types of explanations 

of information states may provide as part of the initial 

submittal to sufficiently address each of the three required 

components for getting an extension: 

 Details on whether a state is considering a single or 

multi-state plan, a plan that meets the CO2 emission 

performance rates or state CO2 rate or mass emission 

goal, and/or an emission standards or state measures plan 

type. 

 A description of how the state intends to address 

development of the required components of the final state 

plan, including describing what actions have already been 

taken, what steps remain, and the schedule for completing 
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those steps. 

 A commitment to maintain any existing measures the state 

intends to rely upon for its final plan in order to 

achieve the necessary reductions once the performance 

period begins. 

 Describing public participation opportunities such as 

stakeholder and community meetings, or public hearings, 

throughout the 3 year plan development process. This 

could also include leverage of public participation 

approaches that states already use to identify and engage 

potentially affected communities. 

The EPA emphasizes the required initial submittal 

components are intended to provide a reasonable pathway for 

states to demonstrate whether they will be able to submit an 

approvable plan by the extended date of September 6, 2018. The 

EPA also anticipates that through the requirement to address 

these components, the initial submittal will also facilitate 

state planning and stakeholder engagement, particularly as one 

component requires the public and stakeholders to have an 

opportunity to comment on the initial submittal. As previously 

described, these components do not require final decisions to be 

made by states, and this is further illustrated by the 

clarifications on how states may meet each of the three required 
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components. Accordingly, the EPA believes none of these 

components is onerous for states to address in an initial 

submittal by the September 6, 2016 deadline. To further 

underscore this point, the EPA is further explaining the 

clarifying examples listed above of how states may address the 

three required components, and highlighting the achievability of 

these examples for states to address through the initial 

submittal by September 6, 2016. 

For identification of the final plan approach or approaches 

the state is considering, and description of progress made to 

date, states could identify whether the state is considering the 

option of the CO2 emission performance rates, a rate-based CO2

goal, or a mass-based CO2 goal, and whether the state is 

intending to pursue a single-state or multi-state plan.

Stakeholders commented that states will not be far enough along 

in the rule development process to have made these decisions. 

Commenters also stated that many state legislatures would need 

to pass legislation giving state environmental agencies legal 

authority and direction before they could begin to make 

decisions such as rate or mass-based approach or single or 

multi-state plan submittal. In order to address the commenters’ 

concerns, the EPA wishes to clarify that state approaches 

identified in the initial submittal do not need to be final 
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and/or formalized through a state legislature, and that states 

may opt to identify pursuit of more than one approach at the 

same time, or to indicate the status of the deliberation of this 

issue within the state. 

The EPA received substantive comment regarding the 

potential adverse consequences for states pursuing a multi-state 

approach and receiving an extension until 2018, where, for 

various reasons, a state or states then decide(s) to pursue the 

single state approach. Commenters viewed this as being 

potentially problematic since, as proposed, a single state could 

only receive an extension until 2017, and if a multi-state plan 

effort does not work out the deadline for seeking the extension 

until 2017 would have passed. The EPA notes finalizing a 2 year 

extension that is available for any state, whether they are 

pursuing an individual state plan or a multi-state plan resolves 

the commenters’ concern about conflicting extension deadlines if 

states involved in a multi-state effort decide not to pursue the 

multi-state approach. Importantly, such identification in an 

initial submittal does not obligate the state to then actually 

adopt that approach in their final plan as the EPA acknowledges 

that based on state processes and public input through plan 

development during the extended submission period, a state may 

end up adopting a state plan approach more suitable to the needs 
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of that state and its affected EGUs than previously identified 

in the initial submittal. 

States can also describe progress made to date by 

identifying steps already taken to address development of the 

final state plan, as the EPA recognizes that states in general 

have already taken a number of steps to prepare for state plan 

development to meet the obligations of this rule. For example, 

since proposal, states have: begun exploring tradeoffs among 

various state plan approaches such as individual versus 

multistate coordination, increased utilization of demand-side EE 

and RE programs, and implementing rate-based versus mass-based 

programs; increased their understanding of existing state 

programs and policies that reduce carbon emissions; built 

relationships and communications between key state institutions 

such as environmental agencies, PUCs, governors’ offices, and 

energy regulators; hosted public stakeholder meetings to educate 

and solicit input from the public; and begun discussing state 

processes for developing potential state plans. States may meet 

the first required component by describing steps such as these 

already undertaken. 

The EPA underscores that states may easily address the 

first component of the initial submittal by describing such 

steps, and also address the second required component by 
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identifying next steps (which may be a natural extension of 

these already implemented activities), and laying out a schedule 

for development of a final plan. States that have taken these 

steps would especially be able to address the component 

regarding an appropriate explanation for an extension as the EPA 

recognizes the substantial work such states have begun to put 

towards development of state plans, and the continuation of this 

work justifies additional time to complete necessary steps to 

result in an approvable state plan. The EPA emphasizes that for 

states who intend to submit a final plan and need an extension, 

the components of the initial submittal are not intended to 

require burdensome final action by states by September 6, 2016, 

but to identify a viable path to completing a final plan by 

September 6, 2018. 

An initial submittal that contains a commitment to maintain 

any existing measures the state intends to rely upon for its 

final plan in order to get the necessary reductions once the 

performance period begins (e.g. RE standards and demand-side EE 

programs the state intends to rely upon through a state measures 

plan type), at least until the final plan is approved, also 

addresses the requirement that states provide an appropriate 

explanation for an extension. Given the state’s request for 

additional time prior to putting in place enforceable measures 
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to reduce CO2, it would be reasonable and appropriate, and in 

keeping with the goals of 111(d) to ensure that any existing CO2

reduction measures that the state intends to rely upon remain in 

place while the state is developing a final plan. Such 

commitment would demonstrate that the state is taking 

substantive steps towards successful development of a final plan 

within 3 years. 

Regarding the required public participation component of 

the initial submittal, the EPA believes this requirement is both 

achievable for states to submit an initial submittal by the 

September 6, 2016 deadline, and provides a benefit in 

facilitating state plan development so that states are more 

likely to be able to submit a final plan within 3 years if the 

extension is granted. The EPA can use a comment opportunity on 

the initial submittal to advise the state whether aspects of the 

draft initial submittal and overall plan development are 

appropriate for purposes of meeting the requirements of the 

final rule so that the state will be able to procure the 

extension through an acceptable initial submittal and submit a 

final plan by the extended deadline. The EPA notes the comment 

period on the initial submittal is only one opportunity the EPA 

has to assist a state in the state plan development process. The 

EPA has historically worked with states throughout the state 
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plan development process to help ensure that the state plan is 

approvable once submitted to the EPA, and expects this level of 

engagement with states to continue throughout the plan 

development process. This requirement will also facilitate early 

identification of concerns stakeholders and the public may have 

with aspects of a final plan the state is considering. As states 

have longtime and extensive experience with responding to public 

comments in numerous contexts, including in the context of other 

CAA programs such as section 110 SIP development and in permit 

issuance under NSR and Title V, the EPA anticipates states will 

be able to timely address the initial submittal public 

participation. 

As previously discussed, because certain communities have a 

potential likelihood to be impacted by state plans, the EPA 

believes that the existing public participation requirements 

under 40 CFR 60.23 are effectuated for the purposes of this 

final rule by states engaging in meaningful, active ways with 

such communities. Therefore, the public participation component 

of the initial submittal includes meaningful engagement with 

vulnerable communities, throughout the state plan development 

process and including through the initial submittal. In order to 

demonstrate to the EPA that states are actively engaging with 

communities, states could provide in their initial submittal a 
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summary of steps they have already taken to engage the public 

and how they intend to continue meaningful engagement, including 

with vulnerable communities, during the additional time (if an 

extension is granted) for development of the final plan. In 

addition to approaches that states already use to identify and 

engage potentially affected communities, the EPA encourages 

states to use the proximity analysis conducted for this 

rulemaking (which is described in section IX.A) as a tool to 

help them identify overburdened communities that could be 

potentially impacted by their plans. Other tools, such as EJ 

screen, can also be helpful. The EPA in its continued outreach 

with states during the implementation phase will also provide 

resources to assist them in engaging with communities. The EPA 

believes that through the provision of these resources states 

will also more easily be able to address this required component 

of the initial submittal regarding public engagement, including 

with vulnerable communities, by September 6, 2016. 

In addition to the resources the EPA intends to provide to 

states, there are existing resources states can take advantage 

of to address this component as well. On the steps that states 

could take to engage vulnerable communities in a meaningful way, 

the Agency recommends that states consult the EPA’s May 2015 

Guidance on Considering Environmental Justice During the 
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Development of Regulatory Actions. In this document, the EPA 

defines meaningful involvement as ensuring that “potentially 

affected community members have an appropriate opportunity to 

participate in decisions about a proposed activity (i.e., 

rulemaking) that may affect their environment and/or health; the 

population’s contribution can influence the EPA’s [regulatory 

authority’s] rulemaking decisions; the concerns of all 

participants involved will be considered in the decision-making 

process; and the EPA [decision-makers] will seek out and 

facilitate the involvement of those potentially affected by the 

EPA’s [or other regulatory authority’s] rulemaking process.”1081

Additionally, this guidance document also encourages those 

writing rules to consider the positive impacts that a rulemaking 

will have on communities).1082 Another resource that the EPA 

recommends that states consult when devising their state plans 

is the document “Considering Environmental Justice in 

Permitting” available on the agency’s website.1083 Both of the 

resources discussed above can add to what states may already 

 

1081 Guidance on Considering Environmental Justice During the 

Development of Regulatory Actions. 

http://epa.gov/environmentaljustice/resources/policy/considering

-ej-in-rulemaking-guide-final.pdf. May 2015. 

1082 Ibid. 1083 Considering Environmental Justice in Permitting. 

http://www.epa.gov/environmentaljustice/planej/permitting.html#actions. 
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have in place to effectively engage vulnerable communities in 

the rulemaking process. 

The EPA recommends that as part of their meaningful 

engagement with vulnerable communities, states work with 

communities to ensure that they have a clear understanding of 

the benefits and any potential adverse impacts that a state plan 

might have on their overburdened communities and that there is a 

clear process for states to respond to input from communities. 

If a state seeks an extension by submitting an appropriate 

initial submittal addressing the three required components as 

described above by September 6, 2016, the EPA will grant the 

extension. If the state does not submit an initial submittal by 

September 6, 2016, that contains the three required components, 

the EPA will notify the state by letter, within 90 days, that 

the agency cannot grant the extension request based the state’s 

initial submittal. The EPA will notify a state by letter only if 

the initial submittal does not address the three required 

components. An extension for submitting a final plan will be 

deemed granted if the EPA does not deny the extension request 

based on the initial submittal. The EPA has determined this 

approach is authorized by, and consistent with, 40 CFR 60.27(a) 

of the implementing regulations. 

For states that request and receive a 2-year extension, the 
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state must submit an update halfway through that extension, by 

September 6, 2017. In the proposal the EPA included a 

requirement regarding a 2017 check in. Because the EPA is 

finalizing that states are able to get a 2-year extension 

regardless of whether they are submitting an individual or multi 

state final plan, the EPA believes it appropriate to ensure 

through the 2017 update that the state is making continuous 

progress on its initial submittal and that it is on track to 

meet the final plan submittal deadline of September 6, 2018. The 

EPA will also be able to use the information provided through 

the 2017 update to further assist states in plan development. 

The final rule requires that states address in the 2017 

update the following components: 

 A summary of the status with respect to required 

components of the final plan, including a list of which 

components are not yet complete. 

 A commitment to a plan approach (e.g., single or multistate, rate or mass emission performance level), 

including draft or proposed legislation and/or 

regulations. 

 An updated comprehensive roadmap with a schedule and 

milestones for completing the plan, including progress to 

date in developing a final plan and steps taken in 
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furtherance of actions needed to finalize a final plan. 

In order to assess whether a state is on track to submit a 

final plan by the 2018 extension deadline, the EPA is requiring 

that the 2017 update must contain a progress update on 

components from the initial submittal and a list of which final 

plan components are still not complete. This progress update 

must demonstrate that state is meeting any steps and schedule it 

outlined in its initial submittal. 

The EPA is also requiring that the 2017 update include a 

commitment to the type of plan approach the state will take in 

the final plan submittal. During the public comment period, many 

commenters stated that legislative action would be required to 

enact this final rule at the state level, and that the proposal 

did not provide enough time for legislative action or other 

regulatory actions needed for a state to be granted an 

extension. In order to respond to these comments, the EPA is 

clarifying that proposed or passed legislation or regulations 

are not required in the initial submittal due by September 6, 

2016. While a state may indicate consideration of multiple state 

plan approaches in the initial submittal, the EPA is requiring 

that the state commit to one approach in the 2017 update. This 

commitment must include draft or proposed legislation or 

regulations that must become final at the state level prior to 
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submitting a final plan submittal to the EPA. While commenters 

expressed concern with not being able to have legislation 

enacted in time to receive an extension until 2018, the EPA has 

determined that 2 years is a reasonable timeframe for a state to 

decide on the type of approach it will take in the final plan 

submittal and to draft legislation or regulations for this 

approach in order to timely meet the extended September 6, 2018 

deadline. 

4. Multi-state plan submittals 

For states wishing to participate in a multi-state plan, 

the EPA is finalizing three forms of submittal that states may 

choose for the submittal of a multi-state plan. 

TheFirst, the EPA is finalizing its proposed approach where 

one multi-state plan submittal is made on behalf of all 

participating states. The joint submittal must be signed by 

authorized officials for each of the states participating in the 

multi-state plan and would have the same legal effect as an 

individual submittal for each participating state. The joint 

submittal must adequately address plan components that apply 

jointly for all participating states and for each individual 

state in the multi-state plan, including necessary state legal 

authority to implement the plan, such as state regulations and 

statutes. Because the multi-state plan functions as a single 
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plan, each of the required plan components (e.g., plan emission 

goals, program implementation milestones, emission performance 

checks, and reporting) would be designed and implemented by the 

participating states on a multi-state basis. 

The EPA received comments from states requesting 

flexibility for multi-state plan submittals. In response to 

these comments, the EPA is also finalizing two additional 

options on which it solicited comment on for multi-state plan 

submittals. . First, states participating in a multi-state plan 

have the option of providingcan provide a single submittal — 

signed by authorized officials from each participating state — 

that addresses common plan elements. This option requires 

individual participating states to provide supplemental

individual submittals that provide state-specific elements of 

the multi-state plan. The common multi-state submittal must 

address all relevant common plan elements and each individual 

participating state submittal must address all required plan 

components (including common plan elements, even if only through 

cross reference to the common plan submittal). Under this 

approach, the combined common submittal and each of the 

individual participating state submittals would constitute the 

multi-state plan submitted for EPA review. The joint common 

submittal must be signed by authorized officials for each of the 
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states participating in the multi-state plan and would have the 

same legal effect as an individual submittal for each 

participating state. 

Second, the EPA is finalizing an approach where all states 

participating in a multi-state plan separately make individual 

submittals that address all elements of the multi-state plan. 

These submittals would need to be materially consistent for all 

common plan elements that apply to all participating states, and 

would also address individual state-specific aspects of the 

multi-state plan. Each individual state plan submittal would 

need to address all required plan components. The EPA encourages 

states participating in this type of multi-state plan to use as 

much common material as possible to ease review of the state 

plans.

These approaches will provide states with flexibility in 

addressing contingencies where one or more states submit plan 

components that are not approvable. In such instances, these 

options simplify the EPA’s approval of remaining common or 

individual portions of a multi-state plan and help address 

contingencies during plan development where a state fails to 

finalize its participation in a multi-state plan, with minimal 

disruption to the submittals of the remaining participating 

states. These additional submittal approaches also facilitate 
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multi-state plans where the participating states are 

coordinating the implementation of their plans but are not 

taking on a joint multi-state emission goal for affected EGUs. 

For example, states may seek to engage in a multi-state approach 

that links rate-based or mass-based emission trading programs 

through appropriate authorizations (e.g. reciprocity agreements, 

or state regulations) that allow affected EGUs to use emission 

allowances or RE/EE credits issued in one state for compliance 

with an emission standard in another state. 

In order to avoid a multi-state plan becoming unapprovable 

due to one state submitting an unapprovable portion of a multistate plan, withdrawing from the multi-state plan, or failing to 

implement the multi-state plan, states may include express 

severability clauses if their multi-state plan is able to stand 

without further revision if one of the situations described 

above occurs. The severability clause must specify how the 

remainder of the multi-state plan or individual state plan would 

continue to function with the withdrawal of a state or states, 

and may also include pre-specified revisions. The EPA will 

evaluate the appropriateness of such a clause as part of its 

review of the multi-state plan submittal. 

2. State plan submittal and timing 

The EPA implementing regulations (40 CFR 60.23) require 
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that state plans be submitted to the EPA within 9 months of 

promulgation of the emission guidelines, unless the EPA 

specifies otherwise.1084 The EPA is finalizing that each state 

must submit a final plan submittal to the EPA by August 31, 

2016, (13 months after the final rule). The state may submit a 

final plan submittal by this date, or seek an extension to 

submit a final plan by submitting an initial plan submittal. In 

this final rule the EPA is providing states with the option of 

up to a 2-year extension that will provide a total of 3 years 

for a state to develop and submit a final state plan to the EPA. 

To qualify for an extension of the August 31, 2016 deadline 

until August 31 2018, a state must submit an initial plan 

submittal by August 31, 2016, that documents the state’s plan 

for preparing a final plan submittal by 2018. The EPA is also 

finalizing that a state must submit one progress update by 

August 31, 2017. 

The EPA notes that the current implementing regulations at 

40 CFR part 60 do not specify who has the authority to make a 

formal submission of the state plan to the EPA for review. In 

order to clarify who on behalf of a state is authorized to 

submit an initial plan submittal, 2017 update, final state plan 

 

1084 40 CFR 60.23(a)(1). 
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(or negative declaration, if applicable), and any revisions to 

an approved plan, the EPA has included a requirement in this 

final rule mirroring that of the requirement in 40 CFR part 51 

App. V.2.1.(a) with respect to SIPs that identifies the Governor 

of a state as the authorized official for submitting the state 

plan to the EPA. If the Governor wishes to designate another 

responsible official the authority to submit a state plan, the 

EPA must be notified via letter from the Governor prior to the 

2016 deadline for plan submittal so that they have the ability 

to submit the initial or final plan submittal in the State Plan 

Electronic Collection System (SPeCS). If the Governor has 

previously delegated authority to make CAA submittals on the 

Governor’s behalf, a state may submit documentation of the 

delegation in lieu of a letter from the Governor. The letter or 

documentation must identify the designee to whom authority is 

being designated and must include the name and contact 

information for the designee and also identify the state plan 

preparers who will need access to SPeCS discussed in section 

VIII.E.7. A state may also submit the names of the state plan 

preparers via a separate letter prior to the designation letter 

from the Governor in order to expedite the state plan 

administrative process. Required contact information for the 

designee and preparers includes the person’s title, organization 
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and email address. The EPA recommends this information be 

submitted early in the state planning process to allow 

sufficient time for completion of SPeCS registration so that 

those authorized to use the system are provided access. 

An initial plan submittal must include the components of a 

final plan submittal described in section VIII.D. Based on these 

components, potential justifications for seeking extensions 

include, among other things, a state’s required schedule for 

legislative approval and administrative rulemaking, the need for 

multi-state coordination in the development of an individual 

state plan, additional time needed for the development of RE or 

demand-side EE programs in low-income communities, and process 

and coordination necessary to develop a multi-state plan. 

As previously discussed, because certain communities have a 

potential likelihood to be impacted by state plans, the EPA 

believes that the existing public participation requirements 

under 40 CFR 60.23 are effectuated for the purposes of this 

final rule by states engaging in meaningful, active ways with 

such communities. Therefore, as part of its overall evaluation 

of whether the initial submittal justifies granting an extension 

for submission of the final plan, the EPA is requiring that 

states seeking an extension until 2018 must actively engage with 

communities with a potential likelihood of being adversely 
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impacted by state plans, including low income communities and 

communities of color, throughout the state plan development 

process. In order to demonstrate to the EPA that states are 

actively engaging with affected communities, states must provide 

in their initial plan submittal a summary of how they have been 

engaging with community stakeholders and how they intend to 

meaningfully engage with community stakeholders during the 

additional time (if an extension is granted) for development of 

the final plan. In particular, states must document meetings and 

interactions that they have had with affected communities. 

Furthermore, states in their initial plan submittal and 2017 

update must show how they identified low income and communities 

of color that they are conducting meaningful community 

engagement with in the state plan development process. 

For some recommendations on the steps that states could 

take to engage communities in a meaningful way, the agency 

recommends that states consult the EPA’s Interim Guidance on 

Considering Environmental Justice During the Development of an 

Action. In this document, the EPA defines meaningful 

involvement, as ensuring that, “potentially affected community 

members have an appropriate opportunity to participate in 

decisions about a proposed activity that will affect their 

environment and/or health; the public’s contribution can 
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influence the regulatory agency’s decision; the concerns of all 

participants involved will be considered in the decision-making 

process; and the decision-makers seek out and facilitate the 

involvement of those potentially affected.”1085 Additionally, this 

guidance document also encourages those writing rules consider 

the positive impacts that a rulemaking will have on 

communities).1086 Another resource that the EPA recommends that 

states consult when devising their state plans is the 

Considering Environmental Justice in Permitting resources 

available on the agency’s website.1087 Both of the resources 

discussed above will provide states with assistance on how to 

effectively engage communities in the rulemaking process. 

The EPA recommends that as part of their meaningful 

engagement with affected communities, that states work with 

affected communities to ensure that they have a clear 

understanding of the benefits and potential adverse impacts that 

a state plan might have on their communities and that there is a 

 

1085 Interim Guidance on Considering Environmental Justice During 

the Development of an Action. 

http://www.epa.gov/environmentaljustice/resources/policy/ejrulemaking.html. July 2010. 

1086 Ibid. 1087 Considering Environmental Justice in Permitting. 

http://www.epa.gov/environmentaljustice/planej/permitting.html#actions. 
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clear process for states to respond to input from communities. 

If no affected EGU is located within a state, the state 

must submit a letter to the EPA certifying that no such 

facilities exist by August 31, 2016.1088 The EPA will publish a 

notice in the Federal Register to notify the public of receipt 

of such letters. 

If a state submits an acceptable initial plan submittal by 

August 31, 2016, as specified in the plan guidelines, then the 

deadline extension for submitting a final plan submittal that 

the state requested will be deemed granted. If the EPA 

determines that the initial plan submittal does not meet the 

guidelines, the EPA will notify the state by letter, within 90 

days, that the agency cannot approve the extension request based 

the state’s initial plan submittal as submitted. The EPA will 

notify a state by letter only if the initial plan submittal does 

not meet the guidelines. An extension for submitting a final 

plan submittal will be deemed granted if the EPA does not deny 

the extension request based on the initial plan submittal. The 

EPA has determined this approach is authorized by, and 

consistent with, 40 CFR 60.27(a) of the implementing 

regulations. 

 

1088 40 CFR 60.23(b). 
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 In the proposal, EPA proposed an initial 13 month 

submittal, with a 1-year possible extension for states 

submitting plans on their own and a 2-year possible extension 

for states submitting as part of a multi-state region. The EPA 

received substantive comment on the achievability of these 

proposed deadlines for state plan. Multiple commenters expressed 

concern that due to timing of legislative cycles (some of which 

are every 2 years), regulatory processes, and other necessary 

tasks, states would find it extremely difficult, if not 

impossible, to submit plans in 1 or 2 years, whether or not they 

were planning to submit as part of a multi-state region. The EPA 

agrees that a schedule shorter than 3 years will be extremely 

challenging for many — though not all - states. We note that the 

CAA provides multiple years for states to complete other types 

of plans, such as those under CAA section 110, that are similar 

(or less) in scope and complexity than these plans. In light of 

the comments received and in order to provide maximum 

flexibility to states while still taking timely action to reduce 

CO2 emissions, in this final rule the EPA is allowing for an 

extension until 2018 for both individual and multi-state plans. 

This 2-year extension is contingent upon a state submitting a 

detailed description of steps already taken, a detailed 

description of additional actions to be taken in order to meet 
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the 2018 plan submittal date and the initial 2022 compliance 

deadline and a schedule for those actions. This 2-year extension 

is also contingent upon the state submitting an acceptable 2017 

update by August 31, 2017 that documents the state’s continued 

progress towards meeting the 2018 submittal deadline. If the 

state does not submit an acceptable 2017 update by August 31, 

2017, the state will have failed to meet the conditions for the 

2-year extension and the EPA will develop a federal plan unless 

the state submits a final plan during this time. The EPA is also 

clarifying the requirements for approvable initial plan 

submittals and 2017 updates, which can be found in section 

VIII.E.3. 

3. Components of an initial state plan submittal and 2017 update 

and approvability criteria 

As noted, if a state is unable to prepare and submit a 

final plan submittal by August 31, 2016, the state must make an 

initial plan submittal by that date and may request up to a 2-

year extension to submit a final plan. To be approved, the EPA 

is finalizing that the initial plan submittal must address all 

components of a final plan submittal, including identifying 

which components are not complete. For incomplete components, an 

approvable initial plan submittal must contain a comprehensive 

roadmap outlining the path to completion, including milestones 
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and dates. 

During the public comment period, multiple commenters 

stated that the proposed timeframe for states to submit an 

approvable initial state plan submittal was not achievable, 

citing, among other things, the amount of decisions needed to be 

made by a state or states, and that the EPA needed to clarify 

the requirements for submitting an approvable initial state plan 

submittal. Multiple commenters also expressed concern that the 

requirements for an approvable initial plan submittal required 

final decisions to be made by states, and that the initial plan 

submittal deadline was not enough time for states to make these 

decisions. In order to address the commenters’ concerns, the EPA 

is finalizing that in order to be approvable, an initial state 

plan submittal must address all components of a final plan 

submittal, including identifying which components are not 

complete, and include the following information: 

 All components of a final plan, including which 

components are not complete. 

 A justification for seeking an extension. 

 A description of the plan approach (e.g., single or 

multi-state, CO2 emission performance rates or state CO2

rate or mass emission goal) 

 A commitment to maintain existing measures that limit or 
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avoid CO2 emissions (e.g., RE standards), at least until 

the final plan is approved. 

 A comprehensive roadmap with a schedule and milestones 

for completing the plan, including progress to date in 

developing a final plan and steps taken in furtherance of 

actions needed to finalize a final plan. 

 Demonstration of opportunity for public comment on 

submittal and response to significant comments, and 

meaningful engagement with affected communities likely to 

be impacted by the state plan. 

As stated above, the EPA is finalizing that the initial 

plan submittal must address all components of a final plan 

submittal, including identifying which components are not 

complete. For incomplete components, an approvable initial plan 

submittal must contain a comprehensive roadmap outlining the 

path to completion, including milestones and dates. 

The EPA proposed that approvable justifications for seeking 

an extension beyond 2016 for submitting a final plan include: a 

state’s required schedule for legislative approval and 

administrative rulemaking, the need for multi-state coordination 

in the development of an individual state plan, or the process 

and coordination necessary to develop a multi-state plan. In 

this final rule, the EPA is finalizing these as acceptable 
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justifications for seeking an extension beyond 2016. Although 

legislation and/or regulations do not need to be passed prior to 

the initial plan submittal in order to be granted an extension, 

the initial plan submittal must include any concrete steps the 

state has already taken on legislation and/or administrative 

rulemaking and detail what the remaining steps are in those 

processes before a final plan submittal can be submitted. The 

EPA also sought comment on other circumstances for which an 

extension of time would be appropriate, and also whether some 

justifications for extensions should not be permitted. 

Commenters stated that states should be able to seek extensions 

whenever an extension can be reasonably justified, and that the 

EPA should take at face value states’ good faith efforts by 

accepting any state assertion that more time is needed to 

develop a plan unless there is clear evidence to the contrary. 

The EPA does not agree with the assertion that any reason 

provided by a state should automatically be deemed as an 

acceptable justification for being granted an extension. The EPA 

is not finalizing other justifications in this final rule, 

however, the EPA will evaluate the appropriateness of other 

justifications not listed here during review of the initial 

state plan submittals. 

For descriptions of plan approaches, states must include a 
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basic outline of the approach used to meet the state’s CO2

emission goals or the CO2 emission performance rates. This should 

include, at a minimum, whether the state is choosing the option 

of the CO2 emission performance rates, a rate-based CO2 goal, or 

a mass-based CO2 goal, and whether the state is pursuing a 

single-state or multi-state plan. Stakeholders commented that 

states will not be far enough along in the rule development 

process to have made these decisions. Commenters also stated 

that many state legislatures would need to pass legislation 

giving state environmental agencies legal authority and 

direction before they could begin to make decisions such as rate 

or mass-based approach or single or multi-state plan submittal. 

In order to address the commenters’ concerns, the EPA wishes to 

clarify that state approaches in the initial state plan 

submittal do not need to be final and/or formalized through a 

state legislature, and that states may opt to pursue more than 

one approach at the same time. In order to fulfill the 

requirement for a description of the plan approach, the initial 

plan submittal may include the various compliance options a 

state or group or states is exploring and a detailed schedule 

outlining the process for making decisions necessary to meet the 

deadline for final plan submittal. 

The EPA received substantive comment regarding the 
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potential adverse consequences for states pursuing a multi-state 

approach and receiving an extension until 2018, where, for 

various reasons, a state or states then decide(s) to back out of 

the multi-state plan and pursue the single state approach.

Commenters viewed this as being potentially problematic since, 

as proposed, a single state could only receive an extension 

until 2017, and if a multi-state plan effort does not work out 

the deadline for seeking the extension until 2017 would have 

passed. Finalizing a 2-year extension that is available for any 

state, whether they are pursuing an individual state plan or a 

multi-state plan resolves the commenters’ concern about 

conflicting extension deadlines if states involved in a multistate effort decide not to pursue the multi-state approach. 

In order for a state’s initial plan submittal to be 

approvable, the EPA is finalizing that the initial submittal 

must contain a commitment to maintain existing measures, such as 

RE standards and demand-side EE programs, at least until the 

final plan is approved. The EPA could not in good faith agree 

with a state’s rationale for needing more time to develop a 

final state plan while at the same time the state was removing 

already in place measures that reduce CO2 emissions from EGUs. 

An initial state plan submittal must also include a 

description of the progress a state has made in the development 
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of a final plan submittal as well as a comprehensive roadmap for 

completing the plan. This includes a schedule with milestones 

and dates. The milestones should outline the state’s path to 

submitting a final plan by August 31, 2018. 

The EPA is finalizing the public comment requirements that 

were outlined in the proposal for initial plan submittals. Prior 

to submittal to the EPA, the state must provide an opportunity 

for public comment on a substantial draft of its initial plan 

submittal. This public comment opportunity will not be governed 

by the procedural requirements of the implementing regulations 

that apply to the state’s adoption of a final plan, such as the 

requirement that the state hold a public hearing. 40 CFR 

60.23(c)-(f). An initial plan submittal might not include any 

legally enforceable provisions that the state would have adopted 

through its administrative or legislative processes, which 

generally provide for public input. Therefore, to ensure that 

the public has an opportunity to understand and inform the 

initial plan submittal, the final rule requires that prior to 

submittal on August 31, 2016, the state must have provided a 

reasonable opportunity for public comment on a substantial draft 

of the initial plan submittal, with notice to the EPA of that 

comment period. 

The EPA can use this comment opportunity to advise the 
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state whether it is on track to submit an approvable initial 

plan submittal. The comment period on the initial plan submittal 

is only one opportunity the EPA has to assist a state in the 

state plan development process. The EPA has historically worked 

with states throughout the state plan development process to 

help ensure that the state plan is approvable once submitted to 

the EPA, and expects this level of engagement with states to 

continue for this final rule. When the state submits its initial 

plan submittal, it must provide the EPA with a response to any 

significant comments it received on issues relating to the 

approvability of the initial plan so that the EPA can fully 

assess whether it is approvable. 

For states participating in a multi-state program, the 

initial plan submittal must include the elements described above 

as well as any executed agreements among the participating 

states and a road map for both design of the multi-state program 

and its implementation at the state level. A multi-state initial 

plan submittal should also address situations where states may 

join together on only certain elements, such as RE, or standards 

on subsets of EGUs. 

In this final rule, the EPA is allowing states up to 3 

years to submit a final plan. This is contingent upon submitting 

an acceptable initial plan submittal and 2017 update. The 2017 
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updates will ensure that a state is making continuous progress 

on its initial plan and that a state is on track to meet the 

final plan submittal deadline of August 31, 2018. The EPA is 

requiring that the 2017 update must contain the following 

components: 

 A summary of the status of each component of the final 

plan, including an update from the 2016 initial plan 

submittal and a list of which components are not 

complete. 

 A commitment to a plan approach (e.g., single or multistate, rate or mass emission performance level), 

including draft or proposed legislation and/or 

regulations. 

 An updated comprehensive roadmap with a schedule and 

milestones for completing the plan, including progress to 

date in developing a final plan and steps taken in 

furtherance of actions needed to finalize a final plan. 

In order to assess if a state is on track to submit a final 

plan by the 2018 extension deadline, the EPA is requiring that 

the 2017 update must contain a summary of all components of a 

final plan, including a progress update on any incomplete 

components from the initial plan submittal, and a list of which 

components are still not complete. This progress update must 
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demonstrate that state has met the milestones and dates it 

outlined in its initial plan submittal. If a state has not met a 

milestone and date that it set in the initial plan submittal, or 

is not on pace to meet a future date, the state may revise its 

schedule in the 2017 update, provided that the schedule meets 

the 2018 deadline for final plan submittal. 

The EPA is also requiring that the 2017 update include a 

commitment to the type of plan approach the state will take in 

the final plan submittal. During the public comment period, many 

commenters stated that legislative action would be required to 

enact this final rule at the state level, and that the proposal 

did not provide enough time for legislative action or other 

regulatory actions needed for a state to be granted an 

extension. In order to respond to these comments, the EPA 

clarified that proposed or passed legislation or regulations are 

not required in the initial plan submittal. While a state may 

pursue multiple types of state plans in the initial plan5

submittal, the EPA is requiring that the state commit to one 

approach in the 2017 update. This commitment must include draft 

or proposed legislation or regulations that must become final at 

the state level prior to submitting a final plan submittal to 

the EPA. While commenters expressed concern with not being able 

to have legislation enacted in time to receive an extension 
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until 2018, the EPA has determined that 2 years is a reasonable 

timeframe for a state to decide on the type of approach it will 

take in the final plan submittal and to draft legislation or 

regulations for this approach. 

Finally, the EPA is requiring that the 2017 update include 

an updated comprehensive roadmap with a schedule and milestones 

for completing the plan. Similar to the requirement that the 

2017 update must include all components of a final plan, the 

update must include a demonstration that the state met the 

milestones for submitting a final plan that were outlined in the 

initial plan submittal. For any milestones that were not met, 

the state must provide a justification for not meeting the 

milestone and an updated schedule that demonstrates that the 

state is still on pace to meet the 2018 final plan submittal 

deadline. 

The EPA will assess a state’s 2017 update and, similar to 

the process for the initial plan submittal, notify the state 

within 90 days if the EPA determines that the state is not 

likely or able to meet the 2018 final plan submittal deadline. 

In the event that the EPA makes this determination for a state, 

the EPA will begin the federal plan development process to 

enforce and implement in the state. 

4. Process for EPA review of state plans 
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Our proposal laid out the basic steps for the EPA’s review 

and action on submitted state plans and, at some length, 

discussed the required components of state plans, as further 

described in the preceding sections. We received a number of 

thoughtful and helpful comments on these issues. We are 

finalizing the basic requirements in this rule and are 

proposing, in the companion proposed federal plan under section 

111d,111(d), some additional procedural elements we believe will 

be helpful to states, stakeholders and the EPA moving forward. 

Following the August 31September 6, 2016 deadline for state 

plan submittals, the EPA will review plan submittals for 

approvability.. For a state that submits an initial plan 

submittal by August 31September 6, 2016, and requests an 

extension of the deadline for the submission of a final state 

plan submittal, the EPA will determine if the initial plan 

submittal meets the minimum requirements for an initial plan 

submittal. If the state does not submit an initial plansubmittal 

by September 6, 2016, that contains the three required 

components, the EPA will notify the state by letter, within 90 

days, that the agency cannot grant the extension request based 

the state’s initial submittal. If the initial submittal meets 

the minimum requirements specified in the emission guidelines, 

the state’s request for a deadline extension to submit a final 
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plan submittal will be deemed granted, and the final plan 

submittal must be submitted to the EPA by no later than August 

31September 6, 2018. 

After receipt of a final plan submittal, the EPA will 

review the plan submittal and, within 12 months, approve or 

disapprove the plan through a notice-and-comment rulemaking 

process publicized in the Federal Register, similar to that used 

for approvingacting upon SIP submittals under section 110 of the 

CAA. The implementing regulations currently provide for the EPA 

to act on a final plan within 4 months after the deadline for 

submission, which is consistent with versions of section 110 

prior to the 1990 Amendments to the CAA. 40 CFR 60.27(b). To be 

consistent with the current version of section 110, the EPA 

intends to adopt a timeline of 12 months to review final plan 

submittals upon receipt of complete submittals, as is generally 

consistent with the timing requirements of section 110 with 

respect to complete SIP submittals. Such a timeline would also 

provide the EPA with adequate time for review and rulemaking 

procedures, and ensuring an opportunity for public notice and 

opportunity for comment. We note, however, that we did not 

proposeproposed this timeline for review and action on state 

plans in our proposal, and, in particular, starting but our 

proposal was specific to the 12 month review period fromtimeline 
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for state plans submitted pursuant to this rule rather than for 

state plans submitted under 111(d) generally.1089 We are 

finalizing as part of this rule that state plans submitted to 

meet the date of receiptrequirements of a complete this rule 

will be reviewed and acted upon by the EPA within 12 months of 

submission.1090 Therefore Because such timeline would be 

appropriate to be made to 111(d) state plans more generally, we 

intend to proposeare also proposing the appropriate revisions to 

the implementing regulations as part of the upcoming federal 

plan proposal for section 111(d). 

 In addition, while the CPP proposal and this final rule 

lay out in considerable detail the required components of a 

state plan, the EPA believes that it would also be helpful to 

include in the rule a completeness determination process, 

similar to that used for SIP submittals inunder section 110, 

which will allow the EPA to determine whether a final plan 

submittal contains the components necessary to enable the EPA to 

determine through notice and comment rulemaking whether such 

submittal complies with the requirements of section 111(d). This 

 

1089 The EPA proposed 12 months after the date required for 

submission of a plan or plan revision to approve or disapprove 

such plan or revision or each portion thereof. 

1090 The EPA proposed 12 months after the date required for 

submission of a plan or plan revision to approve or disapprove 

such plan or revision or each portion thereof. 
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is a procedural requirement under CAA section 110(k)(1),) for 

state implementation plans, and the EPA believes this 

requirement is appropriate to establish under section 111(d)’s 

direction ofto the EPA to prescribe through regulations a 

procedure similar to that provided by section 110. However, 

because the EPA did not propose such regulations as part of the 

proposal for this action, the EPA intends to do sois proposing 

such regulations as part of the upcoming Federal Plan federal 

plan proposal for section 111(d). The EPA notes the components 

of state plans as laid out that this preamble (in section 

VIII.D) and the final rule arelay out required components of 

state plans and all the requirements for a state plan submittal, 

and therefore states have the necessary information at this time 

to develop state plans. The upcoming completeness criteria will 

not add to or change these required components, but only 

allowadd a procedural step that allows the EPA to identify 

whether there are absent or insufficient components in the plan 

submittal that would render the EPA unable to act on such 

submittal because it is incomplete. As will bewe further 

explainedexplain in the upcoming Federal Planfederal plan

proposal, a determination by the EPA that a plan submittal is 

incomplete has the effect of a state having a still-pending 

statutory obligation to submit a plan that meets the 
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requirements of section 111(d). 

The EPA is planning to propose an amendment to the section 

111(d) implementing regulations that will add the partial 

approval/disapproval and conditional approval mechanisms in 

section 110(k)(3) and (4) to the procedure for acting on section 

111(d) plans. The input the agency gotreceived in response to 

the proposal for these guidelines indicated that the flexibility 

provided by these mechanisms could be useful getting state plans 

in place. So, theThe EPA expects to proposeagrees, and is 

proposing to amend the implementing regulations as part of the 

rulemaking for the federal 111(d) plan. The EPA is not taking 

final action on these changes in this action. 

 Deferring The later timing for our action on partial 

approval/disapproval and conditional procedures does not create 

any issue with finalizing this rule. These procedural 

adjustments will only come into play after states have submitted 

their plans and the EPA is required to act on them., and we 

intend to finalize these procedural changes prior to September 

6, 2016, when the first plan submittals would occur. Until then, 

the EPA believes that every plan is submitted with the intent to 

be fully approvable and there is no need for states to rely on 

the possibility of these procedures when developing their plans. 

Conditional approval and partial approval/disapproval should be 
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used to deal with approvability issues that arise despite the 

best efforts of states and the EPA to work together to make sure 

a submittal in the first instance is fully approvable. The EPA 

plans to finalize any changes in the implementing regulations 

before the EPA is required to act on state submittals, so that 

the EPA and states will have appropriate flexibility in the plan 

approval process. 

56. Failure to submit a plan 

If a state fails todoes not submit a final plan submittal 

by the applicable deadline, or submits a final plan the EPA 

determines to be incomplete, the EPA will notify the state by 

letter of its failure to submit. The EPA will publish a Federal 

Register notice informing the public of its finding of failure 

to submit. Upon a finding of failure to submit for a state, a 

statutory clock will run requiring the EPA to promulgate a 

federal plan for such state no later than 2 years1 year after 

the EPA makes the finding unless the state submits, and the EPA 

approves, a state plan during this time. Refer to the federal 

plan proposal for more details on how and when a federal plan 

would be triggered.

67. State plan modifications 

a. Modifications to an approved state plan. During the course of 

implementation of an approved state plan, a state may wish to 
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update or alter one or more of the enforceable measures in the 

state plan, or replace certain existing enforceable measures 

with new measures. The EPA received broad support for allowing 

states to submit modifications to approved state plans., and we 

agree that this is an important aspect of this program. In this 

rulemaking, therefore, the EPA is finalizing that a state or 

states may revise its state plan., and states in a multi-state 

plan may revise their joint plan. Consistent with the timing for 

final plan submittals originally submitted by states, the EPA 

will act on state plan revisions within 12 months of a complete 

submittal. The EPA expects that the long complianceplan 

performance timeframes in this final rule and flexibility 

provided to states in developing state plans will lessen the 

need for modifications to approved state plans. 

 A state may enter or exit a multi-state plan through a plan 

modification, with certain limitations. Multiple commenters 

stated that the EPA should clarify the plan modification process 

in such instances. 

 Where a state with a single-state approved plan seeks to 

join a multi-state plan, the state may submit a modification of 

its plan indicating that it is joining the multi-state plan and 

including the necessary plan components under the multi-state 

plan. The current participants of the multi-state plan will also 
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need to submit a plan modification, to acknowledge the new state 

participant and to recalculate the multi-state rate-based or 

mass-based CO2 goal. Functionally, both the modification of the 

single-state plan of the new participant and the multi-state 

plan of the current plan participants could be addressed through 

the same plan modification submittal or addressed under a plan 

modification submittal comparable to the alternate formats for 

multi-state plan submittals addressed in section VIII.E.4. 

 The entry or exit of a state to/from a multi-state plan 

involves the recalculation of the multi-state rate-based or 

mass-based CO2 goal for affected EGUs in the participating 

states. The recalculated multi-state rate-based or mass-based CO2

goal must take into account and ensure achievement of the 

individual state rate-based or mass-based CO2 goal for any state 

that is joining the multi-state plan. If implementation of the 

individual state plan has triggered corrective measures or 

backstop emission standards prior to the plan modification, as 

described in Section VIII.F.3, the modification must take into 

account the need to make up for any shortfall in CO2 emission 

performance in the individual state plan prior to joining the 

multi-state plan. Where one or more states are leaving a multistate plan through a plan modification, the process is similar 

and the same considerations must be taken into account in 
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connection with the states that are leaving the multi-state 

plan. 

 As a result of these requirements and considerations, the 

EPA is finalizing certain requirements for multi-state plan 

modifications. A multi-state plan modification may be submitted 

to the EPA at any time. However, an approved multi-state plan 

modification may only take effect at the beginning of a new 

interim or final plan performance period. These requirements are 

necessary to ensure that state rate-based or mass-based CO2 goals 

in the emission guidelines are achieved. In addition, such 

requirements for the timing of the effective date of multi-state 

plan modifications are necessary for coordination of the 

implementation of multi-state plans, especially where such plans 

include a multi-state emission trading approach. This approach 

is also consistent with the approach the EPA is proposing for 

the implementation of federal plan, where relevant for a 

state(s). 

The EPA solicited comment on whether, for new projections 

of emission performance included in a submitted plan 

modification, the projection methods, tools, and assumptions 

used should match those used for the projection in the original 

demonstration of plan performance, or should be updated to 

reflect the latest data and assumptions, such as assumptions for 
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current and future economic conditions and technology cost and 

performance. Comments received on this topic were generally 

supportive of allowing the use of updated data in state plan 

modifications, citing that states should have the ability to 

determine whether the original data and assumptions or updated 

data and assumptions are appropriate. The EPA is finalizing that 

new projections of emission performance, the projection methods, 

tools, and assumptions do not have to match those used for the 

projection in the original demonstration of plan performance; 

they can be updated to reflect the latest data and assumptions, 

such as assumptions for current and future economic conditions 

and technology cost and performance. 

As discussed in more detail in section VIII.G.2, the final 

rule has several measures to ensure that it does not interfere 

with the industry’s ability to maintain reliability. One such 

measure is that if a state cannot address a reliability issue in 

accordance with an approved state plan, the state can submit a 

request to the EPA to modify the state plan. See section 

VIII.G.2 for a more detailed discussion of this issue. 

The EPA is not finalizing any circumstances under which a 

state may or may not revise its state plan, with the exception 

that a state may not revise its state plan in a way that results 

in the affected EGU or EGUs not meeting the requisite CO2
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emission performance levels. 

b. Modifications to interim and final CO2 emission goals. As 

discussed in section VII, the final rule specifies that the 

state interim and final CO2 emission goals for affected EGUs in a 

state may be adjusted to address inventory changes within a 

state’s fleet. of affected EGUs. If these changes occur before a 

state submits its initial submittal or final plan, the state 

should indicate in its submittal the circumstance that 

necessitates the goal adjustment and the revised interim or 

final CO2 emission goal. If the circumstances occur after a state 

has an approved plan, a state must submit a modification to its 

approved plan. The plan revision submittal must indicate the 

circumstance that necessitates the goal adjustment, the revised 

interim and/or final CO2 emission goal, and the adjustments to 

the enforceable measures in the plan. 

As discussed in more detail in section VIII.H, the final 

rule has several measures to ensure reliability. One such 

measure is that if a state cannot address a reliability issue 

within the boundaries of an approved state plan and the built-in 

reliability contingencies are not adequate to address 

reliability related issues that arise, the state can submit a 

request to the EPA to amend the timeframe over which reductions 

must be made in its plan. See section VIII.H for a more detailed 
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discussion of this issue. 

78. Plan templates and electronic submittal 

The EPA is finalizing the requirement for states tothat 

submissions related to this program be submitted electronically

submit a. Specifically, that includes negative 

declarationdeclarations, state plan submittals, (including any 

supporting materials that are part of a state plan submittal

and), any stateplan revisions, and all reports required by the 

state plan. The rule provides that files that are submitted to 

the EPA in an electronic format may be maintained by states in 

an electronic format. The submission of the information by the 

authorized official must be in a non-editable format. In 

addition to the non-editable version, the EPA is also requiring 

that all plan components designated as federally enforceable 

must be submitted in an editable version as well, as discussed 

below. 

a. Submittal of an editable version of federally enforceable 

plan components. To ensure that the EPA has the ability to 

identify, evaluate, merge, update and track federally 

enforceable plan components in a timely and comprehensive 

manner, the EPA is requiring states to submit an editable copy 

of the specific plan components in their submittalsubmittals

that are designated as federally enforceable, either effective 
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upon the EPA plan approval or as a state plan backstop measure. 

The editable version is in addition to the non-editable version. 

Examples of editable file formats include Microsoft Word, Apple 

Pages and WordPerfect.

b. Plan revisions. Following initial plan approval, 

statesRevisions to an approved plan. States shall provide the 

EPA with both a non-editable and editable copy of any submitted 

revision to existing approved federally enforceable plan 

components, including state plan backstop measures. The editable 

copy of any such submitted plan revision must indicate the 

changes made, if any, to the existing approved federally 

enforceable plan components, using a mechanism such as 

redline/strikethrough. This approach to identifying the changes 

made to the existing federally enforceable plan components is 

consistent with the criteria for determining the completeness of 

SIP submissions set forth in Section 2.1(d) of Appendix V to 40 

CFR part 51. 

c. Electronic submittal. It is the EPA’s experience that 

electronic submittal of information has increased the ease and 

efficiency of data submittal and data accessibility. The EPA is 

developing the SPeCS, a web accessible electronic system to 

support this requirement that will be accessed at the EPA’s 

Central Data Exchange (CDX) (http://www.epa.gov/cdx/). The EPA 
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will pre-register authorized officials and plan preparers in 

CDX. See section VIII.E.2 for additional information on the preregistration process for authorized officials and plan 

preparers. Detailed instructions for accessing CDX and SPeCS 

will be outlined in the “111(d) SPeCS User Guide: How to submit 

state 111(d) plan material to EPA” which will be available on 

the EPA’s Clean Power Plan Toolbox for States. The EPA will 

provide SPeCS training for states prior to the state plan 

submittal due date. 

Once in CDX, SPeCS can be selected from the Active Program 

Service List. The preparer (e.g., state representative compiling 

a state plan submittal) assembles the submission package. The 

preparer can upload files and complete electronic forms. 

However, the preparer may not formally submit and sign packages. 

Only registered authorized officials may submit and sign for the 

state with the exception of draft submittals. The EPA’s intent 

is to allow submittal of draft plans or parts of plans for early 

EPA review prior to formal submission by the authorized official 

and will allow preparers, as well as authorized officials, to 

submit draft documents. The authorized official will be able to 

assemble submission packages and will be able to modify 

submission packages that a preparer has assembled. The key 

difference between the preparer and the authorized official is 
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that the authorized official can submit and sign a package for 

formal EPA review using an electronic signature. In the case of 

a multi-state plan, each participating state’s authorized 

official must provide an electronic signature. 

The process has been designed to be compliant with the 

Cross-Media Electronic Reporting Rule (CROMERR), under 40 CFR 

part 3, which provides the legal framework for electronic 

reporting under all of the EPA’s environmental regulations. The 

framework includes criteria for assuring that the electronic 

signature is legally associated with an electronic document for 

the purpose of expressing the same meaning and intention as 

would a handwritten signature if affixed to an equivalent paper 

document. In other words, the electronic signature is as equally 

enforceable as a paper signature. For more information on 

CROMERR, see the Web site: http://www.epa.gov/cromerr/. IfStates 

who claim that a state plan submittal or supporting 

documentation includes confidential business information (CBI) 

it will also be required to be electronically submitted. 

Although the likelihood that CBI will be submitted as part of 

the state plan submittal is low, the EPA intends to ensuremust 

submit that the system is capable of supporting submittal of all 

the types of information that may be associated withon a state 

plan. Material claimed as CBI will be flagged by the state in 
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thecompact disc, flash drive, or other commonly used electronic 

system as such, then uploaded and stored separately in the 

encrypted CROMMERR archive. Authorized staff will retrieve CBI 

for storage and management at the EPA’smedia to the EPA. The 

electronic media must be clearly marked as CBI and mailed to 

U.S. EPA/OAQPS/CORE CBI Office, Attention: State and Local 

Programs Group, MD C539-01, 4930 Old Page Rd., Durham, NC 27703. 

The EPA received a number of comments on the electronic 

submittal of state plans. Some commenters preferred the option 

to submit electronically rather than the requirement to do so. 

In the final rule, for the reasons discussed below, the EPA is 

requiring electronic submittal of state plans and not allowing 

alternate options for plan submittal (e.g. paper submittal). 

Requiring electronic submittal is in keeping with current 

trends in data availability and will result in less burden on 

the regulated community. Electronic submittal will facilitate 

two-way business communication between states and the EPA, will 

guide states through the submittal process to ensure submission 

of all required plan components, and will enable states to 

submit proposed plans to the EPA electronically for early EPA 

comments. Electronic submittal will also facilitate, expedite 

and promote national consistency in the EPA’s review of state 

plans and promote transparency by providing stakeholder-specific 
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access to updated information on state plan status and posting 

of plan requirements for viewing by the public, government 

regulators and regulated entities. The EPA recently implemented 

an electronic submittal process for SIPs under CAA section 110 

and continues to explore opportunities to increase the ease and 

efficiency with which states and the regulated community can 

meet regulatory data submittal requirements. In summary, the EPA 

believes electronic submittal will be enormously beneficial in 

terms of improving coordination and cooperation between the EPA 

and its state partners in developing approvable state plans. We 

note, however, that there may be some circumstances where having 

paper copies of the plan is needed to facilitate public 

engagement, and encourage states to take those considerations 

into account.

d. Plan templates. In the proposal, the EPA requested comment on 

the creation of templates for initial and final state plan 

submittals. and final state plan submittals. Multiple commenters 

requested the EPA provide state plan templates. One commenter 

requested templates for different plan designs (e.g. a massbased trading framework, a rate-based trading framework, multistate compliance and a utility-based portfolio approach) and for 

specific plan components (e.g. how to incorporate a state RE 

standard and an EE program into a state plan, how to assess the 
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emission reductions delivered by RE and EE). The EPA has decided 

not to develop templates for state plan submittals at this time 

givenThe EPA has determined that the broad range of approaches 

states may take in preparing individual or multi-state plans. 

makes the development of specific templates challenging and 

likely not useful to states. However, concurrent with this final 

rule, the EPA does believe that states may use the Federal Plan 

is proposing model rules for both rate- and mass-based programs 

in conjunction with the proposed federal plan. These effectively 

can serve as a template for states when preparing their state 

plan submittals. The EPA will continue extensive outreach to 

states and work closely with statesthem on the need for 

additional tools and guidance to facilitate the development of 

approvable state plans. 

89. Legal issuesbasis regarding state plan process 

Section 111(d)(1) requires the EPA to promulgate procedures 

“similar” to those in section 110 under which states adopt and 

submit 111(d) plans. The EPA has interpreted this provision 

previously in the implementing regulations found in 40 CFR part 

60 subpart B. As discussed above, the EPA intends that planned 

revisions to the part 60 implementing regulations will clarify 

(among other things) whether certain procedures are appropriate 

for the EPA’s action on 111(d) state plans, and if so, precisely 
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how those procedures should apply. The EPA is proposing these 

revisions to the 111(d) implementing regulations in the notice 

of proposed rulemaking for the federal plan being issued 

concurrentconcurrently with this final rule. In this section we 

discuss the legal basis for procedures that the EPA is 

finalizing in this action: initial plan submittals, extensions, 

and plan revisions. 

 First, we generally discussby using the ambiguous word 

“similar.”,” Congress delegated authority to the EPA to 

determine precisely what procedures would govern 111(d) plans.

“Similar” does not have an identical meaning as the word “same.” 

Webster’s Third New InternationalOne definition of “similar” is 

“having likeness or resemblance, especially in a general way.” 

The American College Dictionary defines “similar” as “having 

characteristics in common, very much alike” or “alike in 

substance or essentials.” Webster’s Third New International 

Dictionary 2120 (1993).1127 (C.L. Barnhart, ed. 1970). On the 

other hand, “same” is defined as “resemblingalike in every way, 

not differentkind, degree, quality; that is, identical” or 

“unchanged in relevant essentials,” “conforming in every 

respect,” or “corresponding so closely as to be 

indistinguishable.”character.” Id. at 2007. 1073.

Thus, hadHad Congress intended that the procedures for 
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section 111(d) plans be indistinguishable from those in section 

110, Congress knew how to say so. See, e.g., 36 U.S.C. § 

2352(b)(2)(B) (“same procedures”). And had Congress intended 

that the procedures for section 111(d) plans be as close as 

possible to those in section 110, Congress knew how to say that. 

See, e.g., 38 U.S.C. § 4325(c) (agency “shall ensure, to the 

maximum extent practicable, that the procedures are similar to” 

certain other procedures). Therefore, Congress must have 

intended to give the EPA leeway to create procedures for section 

111(d) state plans that somewhat vary from those in section 110, 

so long as the section 111(d) procedures are reasonably tied to 

the purpose and text of section 111(d). In other words, 

“similar” creates a gap in the statute that the EPA may 

reasonably fill. 

a. Initial plan submittals and extensions. SectionInitial 

submittals in this instance are a reasonable gap-filling 

procedural step. As explained in our proposal, certain aspects 

of section 111(d) plan development for these particular 

guidelines warrant our creation of this procedural step, even 

though section 110 does not provide for initial plan submittals. 

As explained above, though, we are not bound under section 

111(d)(1) to follow exactly the same procedures. Initial plan 

submittals in this instance are a reasonable gap-filling device. 
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As explained in our proposal, certain aspects of section 111(d) 

plan development for these particular guidelines warrant our 

creation of this device. 

 With respect to the timing of initial plan submittals, 

final submittals, and extensions, we note that section 111 does 

not prescribe any particular deadlines, instead leaving it to 

EPA’s discretion to establish “similar” procedures to section 

110. The implementing regulations for section 111(d) plans 

require state plans to be submitted within 9 months of 

finalization of emission guidelines. Section 110(a)(1) provides 

that states should adopt and submit SIPs that provide for 

implementation, maintenance, and enforcement of the NAAQS within 

3 years, or such shorter period as the Administrator may 

prescribe.1091 As further explained in Section VIII.E., the EPA is 

providing states with up to 3 years to submit a final plan under 

this rule, contingent upon the grant of an extension through an 

initial submittal due by September 6, 2016. Section 110(a)(1) 

does not provide any particular factors for the Administrator to 

consider in prescribing a shorter period. Thus, the EPA’s 

prescription of a shorter period for either an initial plan 

 

1091 Under this grant of authority to prescribe shorter deadlines, 

the EPA has in a number of occasions required SIPs to be 

submitted in 1 year. 
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submittal or a final plan submittal is consistent with the 

discretion granted in section 110(a)(1). We further discuss why 

the September 6, 2016 initial submittal deadline is reasonable 

in Section VIII.E., and such deadline is achievable by states 

seeking to submit a final plan within 3 years. We also note that 

section 110(b) provides for extensions of up to 2 years for 

plans to implement secondary NAAQS, that other provisions in 

part D provide for extensions of due dates of attainment plans 

in certain circumstances, and that the section 111(d) 

implementing regulations provide for extensions generally. We 

conclude, in view of the above discussion of “similar,” that the 

deviceapproach of initial plan submittals and extensions of due 

dates as proposed is aare reasonable procedureprocedures that, 

while not identical to the procedures in section 110, isare

still similar. 

 Some commenters argued that the 1-year period for initial 

plan submittals and, even assuming an extension, the additional 

1- to 2-year period for final submittals were 

unreasonableunreasonably short, particularly in light of the 

possibility that some state legislatures might need to act to 

provide adequate legal authority for these particular plans. We 

are not finalizing the 1-year extension for single state 

submittals, and we have addressed concerns about legal authority 
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for the initial plan submittals by allowing states to identify 

remaining legislative action in those submittals. 

 With respect to the overall period of up to 3 years for 

submittals, we continue to find it reasonable and consistent 

with other deadlines in the CAA. First, section 110(a)(1) 

requires states to submit a plan for implementation, 

maintenance, and enforcement of new NAAQS within 3 years of 

promulgation of that NAAQS. This is true even if the EPA 

promulgates a NAAQS for a previously non-criteria pollutant. In 

that case, it is possible and even likely that at least some 

state agencies will lack statutory authority to regulate the new 

pollutant. Nonetheless, Congress dictated that states should 

submit section 110(a)(1) plans within 3 years. 

 Furthermore, we note that under subpart 1 of Part D of 

Title 1, attainment plans are generally due no later than 3 

years after designation of a nonattainment area, and under other 

subparts of Part D, plans are due even more quickly. For 

example, under subpart 4, attainment plans for particulate 

matter are generally due 18 months after designation, and under 

subpart 5, the same deadline applies for attainment plans for 

sulfur oxides, nitrogen dioxide and lead. While 

developingDeveloping attainment plans may or may not require 

states to seek additional legislative authority, but certainly 
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in terms of complexity they are similar to section 111(d) plans 

for this guideline. In general, attainment plans must contain 

(among other things) a comprehensive inventory of sources of the 

relevant pollutant and its precursors (which in populated areas 

can be very numerous), control measures for those sources 

(including individualized control measures for the larger 

sources), and modelledmodeled demonstrations of attainment 

(which in some instances requires photochemical grid modeling). 

Thus, it is reasonable to have the same timeline for these 

section 111(d) plans as Congress generally provided for 

attainment plans in section 172(b). 

b. State plan modifications. Section 110(l) provides for states 

to revise their SIPs, as does 40 CFR 60.28 for section 111(d) 

plans. Section 110(l) also sets out a standard for revisions: it 

prohibits the EPA from approving a SIP revision that would 

interfere with any applicable requirement concerning attainment 

or reasonable further progress, or any other applicable 

requirement of the CAA. Under the existing section 111(d) 

implementing regulations, the Administrator will disapprove 

section 111(d) plan revisions as unsatisfactory when they do not 

meet the requirements of subpart B to part 60. See 40 CFR 

60.27(c)(3). However, the implementing regulations do not set 

forth a substantive standard like that in section 110(l). 
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Section 111(d)(1) does not mention revisions (except 

indirectly through the reference to section 110) and, therefore, 

does not explicitly provide any substantive requirements for 

them. There is, therefore, a gap in the statute that the EPA may 

reasonably fill, since many stakeholders commented on the 

desirability of states being able to modify their plans, and the 

EPA agrees. It is reasonable, at a minimum, that the state plan 

as revised should continue to provide for implementation and 

enforcement of the standards of performance, and to achieve the 

CO2 emission performance rates or state CO2 emission performance 

goal. This is analogous to the substantive requirements of 

section 110(l), which as explained above for section 110(a)(2), 

we may consider in determining how to reasonably fill statutory 

gaps for section 111(d) plans. 

In our proposal, we proposedstated that certain revisions 

to state plans under these emission guidelines, those that 

revised enforceable measures for affected EGUs, should satisfy 

some additional conditions. First, the state should demonstrate 

that the plan continues to achieve the CO2 emission performance 

rates or state CO2 emission performance goal. We proposed that 

this demonstration might be simple for minor revisions, but for 

major revisions a more complete demonstration may be required. 

We are finalizing this proposal. As legal basis for this 
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position, we note that a demonstration is necessary to show that 

a state plan provides for implementation of standards of 

performance that achieve the CO2 emission performance rates or 

state CO2 emission performance goal, and as explained above we 

can reasonably require the same of revisions. 

It is also reasonable to tailor the requirements of the 

demonstration to the magnitude of the revision. The EPA has 

taken a similar approach to tailoring the requirements for a 

technical demonstration that, under section 110(l), a SIP 

revision does not interfere with any applicable requirement 

concerning attainment of the NAAQS. If a SIP revision does not 

relax the stringency of any SIP measure, then the demonstration 

is simple. If the SIP revision does relax the stringency of SIP 

measures, then a qualitative or quantitative analysis may be 

necessary to show non-interference, depending on the nature of 

the revision, the current air quality in the area, and other 

factors. 

Finally, we proposed that revisions “should not result in 

reducing the required emission performance for affected EGUs 

specified in the original approved plan. In other words, no 

‘backsliding’ on overall plan emission performance through a 

plan modification would be allowed.” 79 FR 34917/1. We received 

adverse comments that this standard did not have a basis in 
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section 111(d). According to commenters, since the standard for 

EPA approval of a section 111(d) plan is whether the plan is 

satisfactory in establishing and providing for implementation 

and enforcement of standards of performance that achieve the 

emission performance emission rates or goal, the same standard 

should apply to revisions. In other words, the standard for 

revisions should be whether the plan as revised is satisfactory. 

We believe that our proposal was unclear as to this point, and 

we agree that the same standard for revisions should be the same 

as for submittals. We have finalized this position. 

F. State Plan Performance Demonstrations 

This section describes state plan requirements related to 

compliance periods, monitoring and reporting for affected EGUs; 

plan performance demonstrations; and consequences if the CO2

emission performance rates or state CO2 emission goals are not 

met; and out-year requirements. 

1. Compliance periods, monitoring and reporting requirements for 

affected EGUs 

For plans that include emission standards on affected EGUs, 

the EGU emission standards for the interim period must have 

schedules of compliance for each interim step 1, 2 and 3 for the 

calendar years 2022-2024, 2025-2027 and 2028-2029, respectively. 

For the final period, EGUs must have emission standards that 
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have schedules of compliance for each 2 calendar years starting 

in 2030 (i.e., 2030-2031, 2032-2033, 2034-2035, etc.). If a 

backstop is triggered for a state measures plan, the schedule of 

compliance for the federally enforceable emission standards must 

begin no later than 18 months after the backstop is triggered 

and end at the end of the same compliance period. For example, 

if a backstop is triggered on July 1, 2025, the compliance 

period for the backstop emission standards must begin no later 

than January 1, 2027, and end on December 31, 2027. The next 

compliance period for the backstop emission standards would be 

January 1, 2028-December 31, 2029. 

In the June 2014 proposal, the EPA proposed that the 

appropriate averaging time for any rate-based emission standard 

for affected EGUs be no longer than 12 months within a plan 

performance period and no longer than 3 years for a mass-based 

standard. The EPA solicited comments on longer and shorter 

averaging times for emission standards included in state plans. 

The EPA received comments stating that the proposed 12 -month 

averaging was too short and that there was no reason why the 

compliance period under a rate-based plan should be different 

from a mass-based plan. Comments stated that a multi-year 

averaging period is appropriate for rate-based and mass-based 

plans to account for variations that can occur in a single year, 
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allowing operators the flexibility they need to manage 

unforeseen events. The commenters also recommended that the 

final rule use discrete 3-year periods for compliance 

reconciliation instead of the rolling-average approach proposed. 

The EPA has considered all comments received on this matter 

and is finalizing the compliance periods indicatedspecified

above, which respond to the comments by applying to both rateand mass-based programs, providing compliance periods longer 

than one1 year, and establishing block compliance periods rather 

than a rolling average approach. We agree with comments that 

longer averaging periods allow for operational and seasonal 

variability to even out and provide a basis for emissions 

reductions that are more realistic than short term averaging 

might otherwise demonstrate.. The EPA finalizes that states can 

choose to set shorter compliance periods for their emission 

standards but no none that are longer than the compliance 

periods the EPA is finalizing in this rulemaking. If a state 

chooses to set shorter compliance periods, we urge them to make 

efforts to be cognizant of other deadlines facing EGUs to assure 

that there will not be conflicts. The EPA recognizes that the 

compliance periods provided for in this rulemaking are longer 

than those historically and typically specified in CAA 

rulemakings. As reflected in long-standing CAA precedent, 
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“[t]he“The time over which [the compliance standards] extend 

should be as short term as possible and should generally not 

exceed one month.” See e.g., June 13, 1989 “Guidance on Limiting 

Potential to Emit in New Source Permitting” and January 25, 1995 

“Guidance on Enforceability Requirements for Limiting Potential 

to Emit through SIP and §112 Rules and General Permits.” 

TheHowever, the EPA has determined that the longer compliance 

periods provided for in this rulemaking are acceptable in the 

context of this specific rulemaking because of the unique 

characteristics of this rulemaking, including that CO2 is longlived in the atmosphere, and this rulemaking is focused on 

performance standards related to those long-term impacts. The 

distinction between these unique characteristics and the EPA’s 

long-standinggeneral practice regarding compliance periods is 

bolstered by the EPA guidance on appropriate averaging periods 

for emission limitations in NAAQS implementation. For example, 

the EPA guidance has stated that in implementation of the ozone 

standards, which have a short averaging period, the averaging 

period for VOC emission limitations should be correspondingly 

short. See 51 FR 43857. A longer averaging period for VOC 

emission limitations (VOCs are one of the key precursors to 

ozone formation) can allow spikes in emissions that adversely 

impact ambient air and violate the short term ozone standards. 
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This is precisely the opposite of the unique characteristics 

cited above: the long-lived persistence of CO2 in the 

stratosphere and the intent of these guidelines to address the 

long-term impacts. 

State plans must contain requirements for tracking and 

reporting actual plan performance during implementation, which 

includes reporting of CO2 emissions from affected EGUs. Affected 

EGUs must comply with emissions monitoring and reporting 

requirements that are largely incorporated from 40 CFR part 75 

monitoring and reporting requirements. The majority of affected 

EGUs are already familiar with the reporting requirements of 

part 75, and because of this, the EPA has chosen to streamline 

the applicable reporting requirements for sourcesaffected EGUs

under the state plans in the final rule. States must require all 

affected EGUs to monitor and report hourly CO2 emissions and net 

energy output (including total net MWh output that is comprised 

of generation, and where applicable, useful thermal output 

converted to net MWhs) to the EPA on a quarterly basis in 

accordance with 40 CFR part 75. Note that this requirement 

applies for all types of state plans, regardless of whether the 

state chooses the option of the CO2 emission performance rates, a 

state rate-based CO2 emission goal, or a state mass-based CO2

emission goal. 
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In the June 2014 proposal, the EPA proposed that state 

plans must include monitoring, reporting and recordkeeping 

requirements for useful energy output from affected EGUs. 

Multiple commenters questioned whether gross rather than net 

electrical production should be reported by affected EGUs and 

recommended that the EPA should utilize gross rather than net 

generation. Many commenters recommended electricity to be 

reported in the form used in the 111(b) rules for consistency 

between reporting requirements and simplification of calculation 

of emission limitations between new and old sources. Commenters 

also stated that to the extent the EPA seeks to provide guidance 

to states regarding its preferred monitoring and reporting 

procedures, the EPA should encourage states to avoid imposing 

additional monitoring and reporting burdens by taking advantage 

of the monitoring requirements that already exist to the 

greatest extent possible. For example, the commenters noted that 

the 40 CFR part 75 monitoring procedures used to comply with 

other programs, such as the Title IV Acid Rain Program, provide 

much of the data that would be needed to demonstrate compliance 

under the rule. Comments stated that the June 2014 proposal 

appeared to mandate a monitoring approach that would eliminate 

key flexibilities provided in the part 75 regulations, thus 

requiring utilities to maintain separate document collection and 
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reporting procedures and potentially eliminating important 

alternative monitoring options intended to ensure 

representative, cost-effective monitoring approaches are 

available. The commenters asked the EPA to revise its proposal 

to make clear that the procedures established under part 75 will 

suffice or explain the need for any exceptions. Commenters 

indicated that the rule should require all affected EGUs to 

monitor CO2 emissions and net hourly electric output under 40 CFR 

part 75, and report the data using the EPA's Emission Collection 

and Monitoring Plan System (ECMPS) assuring a more uniform 

monitoring and reporting process for all EGUs. The EPA believes 

that the final monitoring and reporting requirements (via ECMPS) 

address the issue of duplicative requirements and alleviate 

concern about lost flexibiltyflexibility raised by commenters. 

2. Plan performance demonstrations 

The state plan must include emission performance checks, 

and for state measures plans, periodic program implementation 

milestones. The state plan must provide for tracking of emission 

performance, and for measures to be implemented if the emission 

performance of affected EGUs in the state does not meet the 

applicable CO2 emission performance rates or state CO2 emission 

goal during a performance period. 

 As discussed previouslyabove in section VII, the agency is 
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finalizing CO2 emission performance rates or state-specific CO2

emission goals that represent emission levels to be achieved by 

2030 and emission levels to be achieved on average over the 

2022-2029 interim period, and over three interim steps of 2022-

2024, 2025-2027 and 2028-2029. A state may choose to define 

different interim step emission levels for achieving its 

required 2022-2029 average performance rate. The EPA recognizes 

the importance of ensuring that, during the 8-year interim 

period (2022-2029) for the interim performance rates or interim 

state goal, a state is making steady progress toward achieving 

the required level of emission performance. For both emission 

standards plans and state measures plans, the final rule 

requires periodic checks on overall emission performance leading 

to corrective measures or implementation of the backstop, if 

necessary, as described in section VIII.F.3 below. States must 

demonstrate that the interim steps were achieved, on average 

during at the end of the first two interim step periods, at the 

end of each interim step. 

 In 2032 and every 2 years thereafter, states must 

demonstrate that affected EGUs achieved the final performance 

rates or state goal on average or cumulatively, as appropriate, 

during each 2-year reporting period (i.e., 2030-31, 2032-33, 

2034-2035 etc.). The multi-year performance periods for 
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measuring actual plan performance against the performance rates 

or state goals allow states some flexibility that accounts for 

seasonal operation of affected EGUs, and inclusion of RE and 

demand-side EE efforts. 

 For a rate-based plan, emission performance is an average 

CO2 emission rate for affected EGUs representing cumulative CO2 

emissions for affected EGUs over the course of each reporting 

period divided by cumulative MWh energy output1092 from affected 

EGUs over the reporting period, with rate adjustments for 

qualifying measures, such as RE and demand-side EE measures. For 

a mass-based plan, emission performance is total tons of CO2

emitted by affected EGUs over the reporting period. 

 For emission standards plans, as discussed in section 

VIII.D, the state must submit a report to the EPA ofcontaining

the emissions performance comparison for each reporting period 

no later than the July 1 following the end of each reporting 

period (i.e., by July 1, 2025; July 1, 2028; July 1, 2030; July 

1, 2032; and so on). As discussed in section VIII.D, the 

emission comparison required in the July 1, 2030 report must 

compare the actual emissions from affected EGUs over the interim 

 

1092 For EGUs that produce both electric energy output and other 

useful energy output, there would also be a credit for nonelectric output, expressed in MWh.
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period (2022-2029) with the interim CO2 emission performance 

rates or state CO2 emission goal. The report is not required to 

include a comparison for the interim step 3 period, but must 

include the actual emissions from affected EGUs during the 

interim step 3 period. 

 The EPA notes that for certain types of emission standards 

plans, with mass-based emission standards in the form of an 

emission budget trading program, achievement of a state’s massbased CO2 goal (including interim step goals and final goal) will 

be assessed by the EPA based on compliance by affected EGUs with 

their emission standards under the program, rather than CO2

emissions during a specific interim step period or final period. 

As discussed in section VIII.C.3.b.(2)(a), thisThis approach is 

limited to plans with emission budget trading programs where 

compliance by affected EGUs with the emission standards will 

ensure that, on a cumulative basis, the state interim and final 

mass-based CO2 goals are achieved.1093 This approach allows for 

CO2 allowance banking across plan performance periods, including 

from the interim period to the final period. As a result, CO2

 

1093 Emission budget trading programs in such plans establish CO2 

emission budgets equal to or less than the state mass CO2 goal, 

as specified for the interim plan performance period (including 

specified levels in interim steps 1 through 3) and the final 

two2-year plan performance periods. 
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emissions by affected EGUs could differ from the state massbased CO2 goal during an individual plan performance period, but 

on a cumulative basis CO2 emissions from affected EGUs would not 

exceed what is allowable if the interim and final CO2 goals are 

achieved. 

 Also as discussed in section VIII.D, states that choose a 

state measures plan must submit an annual report no later than 

July 1 following the end of each calendar year in the interim 

period. This annual report must include the status of the 

implementation of programmatic milestones identified in the 

state plan submittal. The annual report that follows the end of 

each reporting period (i.e., 2022-2024, 2025-2027, and 2028-

2029) must also include an emissions performance comparison for 

the reporting period, as described above for the 

emissionsemission standards plan. As discussed in section 

VIII.D, the emission comparison required in the July 1, 2030 

report must compare the actual emissions from affected EGUs over 

the interim period (2022-2029) with the interim CO2 emission 

performance rates or state CO2 emission goal. The report is not 

required to include a comparison for the interim step 3 period, 

but must include the actual emissions from affected EGUs during 

the interim step 3 period. Beginning with the final period of 

2030 and onward, states using a state measures plan must submit 
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a biannualbiennial report no later than July 1 following the end 

of each reporting period with an emission performance comparison 

for each reporting period, consistent with the reporting 

requirements for emission standards plans. 

In the June 2014 proposal, the EPA proposed that a state 

report is due to the EPA no later than July 1 of the July 1year 

immediately following the end of each reporting period. The EPA 

requested comment on the appropriate frequency of reporting of 

the different proposed reporting elements, considering both the 

goals of minimizing unnecessary burdens on states and ensuring 

program effectiveness. In particular, the agency requested 

comment on whether full reports containing all of the elements 

should only be required every 2 years rather than annually and 

whether these reports should be submitted electronically, to 

streamline transmission. 

The EPA mainly received adverse comments for requiring 

annual state reporting; commenters stated that this requirement 

was too burdensome for both states and the EPA. Commenters also 

requested that the EPA extend the due date of the annual report 

from July 1 to at least December 31. Commenters stated that 

because of the timing of current data collection, and the need 

to leave time to organize and submit the reports, allowing only 

6 months after the close of the year is problematic. Commenters 
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asked that the EPA consider reducing the amount of data required 

if annual reporting was required. 

 Considering the comments received and the goals of 

minimizing unnecessary burdens on states and ensuring program 

effectiveness, the EPA has reduced the frequency of reporting of 

emissions data to every 3 years for the first two interim steps 

and every 2 years thereafter. However, the EPA is finalizing 

that state reports are due to the EPA no later than July 1 

following the end of each reporting period. The EPA believes 

states can design their state plans to receive the data and 

information needed for these reports in a timely manner so that 

this requirement can be met. Furthermore, some of the state 

reporting requirements, such as reporting of EGU emissions, can 

be met through existing reporting mechanisms (ECMPS) and would 

not place additional burdens on states. 

3. Consequences if actual emission performance does not meet the 

CO2 emission performance rates or state CO2 emission goal 

The EPA recognizes that, under certain scenarios, an 

approved state plan might fail to achieve a level of emission 

performance that meets the emission guidelines or the level of 

performance established in a state plan for an interim 

milestone. Despite successful implementation of certain types of 

plans, emissions under the plan could turn out to be higher than 
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projected at the time of plan approval because actual conditions 

vary from assumptions used when projecting emission performance. 

Emissions also could theoretically exceed projections because 

affected entities under a state plan did not fulfill their 

responsibilities, or because the state did not fulfill its 

responsibilities. 

The final rule specifies the consequences in the event that 

actual emission performance under a state plan does not meet, or 

is not on track to meet, the applicable interim and interim step 

CO2 emission performance rates or state goals in 2022–2029, or 

does not meet the applicable final CO2 emission performance rates 

or state CO2 emission goal in 2030–2031 or later. For emission 

standards plans, the final rule specifies that corrective 

measures must be enacted once triggered.1094 The determination 

that a state is not on track to meet the applicable interim goal 

or interim step goals in 2022–2029 or the applicable final goal 

 

1094 As in the proposal preamble, the EPA continues to note that 

some types of plans are “self-correcting” in that they 

inherently would assure interim performance and full achievement 

of the state plan’s required level of emission performance 

through requirements that are enforceable against affected EGUs. 

One example is a state plan with a rate-based emission 

performance level that requires affected EGUs collectively to 

meet an emission rate consistent with the state’s required 

emission performance level, and allows EGUs to comply through an 

emission trading program. Such plans presumably would not 

trigger or require corrective measures. 
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in 2030–2031 or later, or the CO2 emission performance rates, 

will be made through the actual performance checks to be 

included in state reports of performance data described in 

section VIII.D.2.a above. 

For emission standards plans, the final rule specifies that 

corrective measures must be enacted once triggered.For states 

using the Corrective measures apply only to emission standard 

approach,plans in which full compliance by affected EGUs would 

not necessarily lead to achievement of the emission performance 

rates or CO2 emission goals.1095 For such plans, corrective 

measures are triggered if actual CO2 emission performance by 

affected EGUs exceedsis deficient by 10 percent or more relative 

to the specified level of emission performance in the state plan 

by 10 percent or more during any of the specified for the step 1 

or step 2 interim step reportingperformance periods or during a 

final. Corrective measures also are triggered if actual emission 

performance fails to meet the specified level in the plan 

 

1095 To be specific, corrective measures requirements apply to all 

emission standard plan designs that do not mathematically assure 

that the plan performance level will be achieved when all 

affected EGUs are in compliance with their emission standards, 

regardless of electricity production and electricity 

mix. Corrective measures requirements apply, for example, to 

emission standards plans that include standards on affected EGUs 

that differ from the emission performance rates in the 

guidelines. Backstop requirements apply to state measures plans. 
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reportingfor the 8-year interim period (after2022-2029, or for 

any 2-year final goal performance period (beginning in 2030),). 

In such cases, the state report must include a notification to 

the EPA that corrective measures have been triggered. If, in the 

event of such an exceedance, the EPA determines that corrective 

measures have been triggered and the state has failed to notify 

the EPA, the EPA will inform the affected EGUs that corrective 

measures have been triggered.1096 

After an exceedance by 10 percent or moreWhen corrective 

measures are triggered, if the state plan does not already 

contain corrective measures, the state must submit to the EPA a 

plan revision including corrective measures that adjust 

requirements or add new measures. The corrective measures must 

both ensure future achievement of the CO2 emission performance 

rates or state CO2 emission goal and achieve additional emission 

reductions to offset any emission performance 

deficiencyshortfall that occurred during a performance period. 

The shortfall must be made up as expeditiously as practicable. 

The state plan revision submission must explain how the 

corrective measures both make up for the shortfall and address 

 

1096 The EPA notes that as part of the proposed federal plan 

rulemaking, it is proposing a regulatory mechanism to call plans 

in the instances of substantial inadequacy to meet applicable 

requirements or failure to implement an approved plan. 
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the state plan deficiency that caused the shortfall. The state 

must submit the revised plan to the EPA as expeditiously as 

practicable and within 24 months after submitting the state 

report indicating the exceedance. The 24-month time period 

allows time to identify corrective measures and make rule 

changes through state regulatory processes. The EPA will then 

act on the plan revision within 12 months, consistent with other 

plan revisions and with the timing for final plan submittals 

originally submitted by states. The state must implement 

corrective measures within 6 months of the EPA’s approval of a 

plan revision adding them.

For states using the state measures approach, the EPA is 

finalizing the backstop requirement as described in section 

VIII.C.4.b3 of this preamble. As discussed in section VIII.D.2, 

the determination that a state using the state measures approach 

is not on track to meet the applicable interim goal or interim 

step goals in 2022–2029, or the applicable final goal in 2030–

2031 or later, or the CO2 emission performance rates, is based on 

checks that must be included in state reports that must be 

submitted annually during the interim period and 

biannuallybiennially during the final period. The state must 

annually report any failure to meeton its progress in meeting 

its programmatic milestones during the interim period. In 
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addition, the state must report actual emission performance 

checks, similar to the requirements discussed above for emission 

standards plans., in 2025, 2028, 2030, and every 2 years 

thereafter. If, at the time of the state report to the EPA, the 

state did not meet the programmatic milestones for the reporting 

period, or the performance check shows that the plan’s actual CO2

emission performance by affected EGUs exceeds the specified 

levelwarrants implementation of emission performance in the 

state plan submittal by 10 percent or more,backstop 

requirements,1097 the state must include in the state report a 

notification to the EPA that the backstop has been triggered. 

If, in the event of such an exceedance, the EPA determines that 

the backstop has been triggered and the state has failed to 

notify the EPA, the EPA will inform the affected EGUs that the 

backstop has been triggered.1098

 

1097 As explained in section VIII.C.3.b., state measures plans must 

require the backstop to take effect if actual CO2 emission 

performance fails to meet the level of emission performance 

specified in the plan over the 8-year interim performance period 

(2022-2029), or for any 2-year final goal performance period. 

The plan also must require the backstop to take effect if actual 

emission performance is deficient by 10 percent or more relative 

to the performance levels that the state has chosen to specify 

in its plan for the interim step 1 period (2022-2024) or the 

interim step 2 period (2025-2027).

1098 The EPA notes that as part of the proposed federal plan 

rulemaking, it is proposing a regulatory mechanism to call plans 

in the instances of substantial inadequacy to meet applicable 

requirements or failure to implement an approved plan.
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For multi-state plans, corrective measure or backstop 

provisions would be required for the same plan approaches for 

which those provisions are required in individual state plans. 

For multi-state plans using plan approaches to which corrective 

measures or backstop requirements apply, all states that are 

party to the multi-state plan would be subject to corrective 

action or backstop requirements, and requirements to make up the 

past CO2 emission performance shortfall, if those requirements 

were triggered. This is because multi-state plans are joint 

plans (even if created through separate state submittals). That 

would not be the case for coordinated individual state plans 

linked through interstate ERC or emission allowance trading. In 

the case of coordinated individual state plans, for plan types 

subject to corrective measure or backstop requirements, the 

state where the CO2 emission performance deficiency occurs would 

be required to implement corrective measures or backstop 

requirements for affected EGUs, as applicable, and remedy the 

past CO2 emission performance shortfall. 

Multiple commenters requested that corrective measures not 

be required in the case of a catastrophic, uncontrollable event. 

We recognize the possibility that an un-anticipatablethere are 

potential system emergencyemergencies that cannot be anticipated 

that could cause a severe stress on the electricity system for a 
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length of time such that the multi-year requirements in a state 

plan may not be achievable by givencertain affected EGUs without 

posing an otherwise unmanageable risk to reliability. We are 

finalizing a reliability safety valve that , which includes an 

initial period of up to 90 days during which a reliabilitycritical affected EGU or EGUs will allow a statenot be required

to modifymeet the emission standardsstandard established for 

such EGUs for a maximum of 90 days. The reliability safety valve 

will allow such EGUs to operate under the modified emission 

standardsit under the state plan but rather than the emission 

standards specified in the relevantwill meet an alternative 

standard. While the initial 90-day period is in use, the 

emissions of the affected EGU or EGUs that exceed their 

obligations under the approved state plan for that time period 

(includingwill not be counted against the state’s overall goal 

or emission performance rate for affected EGUs and will not be 

counted as an exceedance that would otherwise trigger corrective 

measures under an emission standard plan type or an exceedance 

that would trigger a backstop under a state measures plan type), 

while still requiring the CO2 emission performance rates or the 

state CO2 emission goal to be met. While use. Use of the 

reliability safety valve would preclude anwill not alter or 

abrogate any other obligations under the approved state plan. 
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After the initial period of up to 90 days, the reliabilitycritical affected EGU is required to continue to operate under 

the original state plan emission standard or an alternative 

standard as part of the reliability safety valve, and the state 

must revise its plan to accommodate changes needed to respond to 

ongoing reliability requirements and to ensure than any 

emissions excess of the applicable event from triggering 

corrective measures or a backstop during the safety valve 

period, the state must still make up for any emission reductions 

that were lost during the safety valve period.state goals or 

performance rates occurring after the initial period of up to 90 

days are accounted for and offset. See section VIII.HG.2.e of 

this preamble. 

Multiple commenters supported the inclusion of strong 

enforcement measures for ensuring the interim and final goals 

are met, including the required use of corrective measures when 

triggered. Other commenters provided feedback as to the 

percentage that actual emission performance would need to exceed 

the level of emission performance specified in the statewide 

plan to trigger corrective measures. Some commenters supported 

the proposed trigger that we are finalizing (actual emissions or 

emission rate performance that is not within 10 percent of the 

projected performance) that we are finalizing, while some 
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recommended a lower trigger and others recommended a trigger 

higher or more than 10 percent exceedance. We have decided to 

finalize the trigger at 10 percent exceedance because we view 10 

percent as both low enough to ensure that states that need 

corrective measures implement them before they exceed theirthe

specified level of emission performance to a degree that might 

be irreversible, and high enough that corrective measures are 

not triggered by fluctuations in emissions that do not indicate 

that a state may not be able to achieve its projected goalin the 

state plan for the interim step 1 or step 2 performance 

periods), while some recommended a lower or higher trigger. 

 The agency is finalizing the trigger at the level of 10 

percent for the interim step 1 or step 2 performance periods. 

Ten percent is a reasonable level to ensure that when 

deficiencies in state plan performance begin to emerge, 

corrective measures (or backstop requirements) will be 

implemented promptly to avoid emissions shortfalls (or minimize 

the extent of shortfalls) relative to the 8-year interim goal 

and the final goal, which reflect the BSER. The 10 percent 

figure also provides latitude for a state’s emission improvement 

trajectory during the interim period to deviate a bit from its 

planned path without triggering these requirements, as the state 

initiates or ramps up programs to meet the 8-year interim goal 
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and final goal. 

The EPA requested comment on whether the agency should 

promulgate a mechanism under CAA section 111(d) similar to the 

SIP call mechanism in CAA section 110. Under this approach, 

after the agency makes a finding of the plan’s failure to 

achieve the CO2 emission performance rates or state CO2 emission 

goal during a performance period, the EPA would require the 

state to cure the deficiency with a new plan within a specified 

period of time. If the state still lacked an approved plan by 

the end of that time period, the EPA would have the authority to 

promulgate a federal plan under CAA section 111(d)(2)(A). 79 FR 

34830, 34908/1-2 (June 18, 2014). 

The EPA intends that planned revisions to the part 60 

implementing regulations will clarify (among other things) 

whether the EPA has authority to call for plan revisions under 

section 111(d) when a state’s plan is not complying with the 

requirements of this guideline, and if so, precisely what 

procedures should apply. The EPA plans to proposeis proposing

these revisions to the 111(d) implementing regulations in the 

forthcoming notice of proposed rulemaking for the federal plan. 

The EPA is not taking final action now on this issue or the 

related change to the implementing regulations. 

a. Legal basis for corrective measures. The EPA discussed the 
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concept of corrective measures in our 1992 General Preamble for 

the Implementation of Title I of the CAA Amendments of 1990. 57 

FR 13498 (Apr. 16, 1992). The General Preamble sets out four 

general principles that apply to all SIPs, “including those 

involving emissions trading, marketable permits and allowances.” 

Id. at 13568. The fourth principle, accountability, means (among 

other things) that “the SIP must contain means ... to track 

emission changes at sources and provide for corrective action if 

emissions reductions are not achieved according to the plan.” In 

the General Preamble, we noted that Part D of Title I explicitly 

provided for this in certain instances by requiring milestones 

and contingency measures. 

Some commenters noted that the contingency measures 

explicitly required by part D are required to be adopted in the 

attainment plan and ready to implement when a milestone is not 

achieved or the area fails to attain the relevant NAAQS. These 

commenters therefore concluded that corrective measures for 

111(d) plans should likewise already be adopted in the 111(d) 

plan and ready to implement. We disagree. Under Part D, 

contingency measures are not expected to fully bring the area 

into attainment. In fact, this would not be possible given the 

difficulty of predicting in advance exactly what measures would 

be needed to fully attain. A better analogue in Part D for the 
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corrective measures in these guidelines is the primary way Part 

D addresses failure to attain: the state is required to revise 

its plan in various ways within a certain time in order to bring 

about attainment. See, e.g., section 179(d). This is analogous 

to what we are requiring for corrective measures. Thus, part D 

contingency measures are unlike the corrective measures in this 

rule. 

However, the requirement to revise an attainment plan in 

response to failure to attain differs somewhat from the 

corrective measures in these guidelines in one important 

respect. Under these guidelines, the corrective measures must 

make up the difference by which the plan fell short of the 

goal., including any prior shortfall that had accumulated if the 

plan fell short of the goal in prior years. There is no 

corresponding requirement in attainment planning to increase the 

stringency of the plan by an amount that somehow matches an 

amount by which the area failed to attainmakes up for any 

shortfall in attainment from prior years; instead the revised 

plan must demonstrate attainment going forward, and other more 

stringent requirements (such as requirements for best available 

control measures) may be triggered. 

 This distinction is the natural result of the difference 

between these guidelines and NAAQS attainment planning. In this 
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case, we are finalizing guidelines representing technology-based 

standards for a pollutant with cumulative and long-lasting 

effects. If a plan falls short of a performance goal, then in 

effect the standards of performance in the plan have failed to 

reflect the BSER over the corresponding period. Due to the 

cumulative effects of CO2, it is possible to remedy this failure 

by requiring the plan to be revised in such a way that the 

standards of performance in the revised plan will reflect the 

BSER over the cumulative plan period, and this can be done by 

requiring the revised plan to make up the shortfall from the 

previous period. In short, the flexibility that these guidelines 

provide should not come at the cost of allowing the standards of 

performance to reflect less than the BSER over the long run.1099 

Some commenters noted that 111(d) does not contain explicit 

provisions regarding corrective measures, and they therefore 

inferred that the EPA is not authorized to require them. That 

inference is mistaken. The requirement for 111(d) plans to 

“provide for implementation and enforcement” of the standards of 

performance is ambiguous and does not directly speak to whether 

corrective measures should or should not be required. There is 

 

1099 Similar considerations apply to the requirement under the 

state measures approach to revise the plan to make up the 

shortfall. 
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therefore a gap for the EPA to fill. While the discussion above 

about Part D does not independently provide any authority to 

fill this gap, the fact that Congress created a scheme with 

stages of planning in Part D suggests that it would be 

reasonable, if appropriate, to fill this gap in 111(d) in a 

similar way. 

In this guideline, it is appropriate for certain types of 

emission standards plans to fill this gap with corrective 

measures. if triggered. There are two ways an emission standards 

plan can provide for implementation of standards of performance 

that achieve the CO2 emission performance rates or requisite 

state CO2 emission performance goal. First, the state can set 

emission standards that necessarily achieve the performance 

rates or goal, even if the affected EGUs in the future vary in 

their relative amounts of electricity generated. Second, the 

state can set emission standards that are demonstrated to 

achieve the performance rates or goal based on assumptions about 

the relative amounts of electricity generated, but which may 

turn out to not actually achieve the goal even if all affected 

EGUs comply. This is analogous to an attainment plan that 

demonstrated attainment by the applicable attainment date, but 

due to unpredicted economic changes actually failed to attain. 

In this second case, the EPA interprets the ambiguous language 
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“provide for implementation . . . of standards of performance” 

in the context of achieving the performance rate or emissions 

goal, to mean that at the time the plan is submitted it must 

contain some mechanism to check the progress of the plan and 

correct course. The EPA has determined that, for this particular 

rule, the minimum mechanism is the set of milestones and 

provisions for corrective measures specified in this rule.

Indeed, not requiring corrective measures in the case of 

deficient plan performance would undercut the viability of state 

plan options other than emission standard plans with uniform 

rates applied to all affected EGUs within the state.

4. Out-year requirements: Maintaining or improving the level of 

emission performance required by the emission guidelines 

 The agency is determining CO2 emission performance rates and 

state CO2 emission goals for affected EGU emission performance 

based on application of the BSER during specified time periods. 

This raises the question of whether affected EGU emission 

performance should be maintained at the 2030 level – or instead 

should be further improved - once the final CO2 emission 

performance rate or state CO2 emission goal is met in 2030. This 

involves questions of performance rate and goal-setting as well 

as questions about state planning. The EPA believes that 

Congress either intended the emission performance improvements 
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required under CAA section 111(d) to be permanentmaintained or, 

through silence, authorized the EPA to reasonably require 

permanencemaintenance. Other CAA section 111(d) emission 

guidelines set emission limits that do not expire. Therefore, 

the EPA is finalizing that the level of emission performance for 

affected EGUs represented by the final CO2 emission performance 

rates or state CO2 emission goal shouldmust continue to be 

maintained in the years after 2030. 

 As noted above, the state plan must demonstrate that plan 

measures are projected to achieve the final emission performance 

level by 2030. In addition, the state plan must identify 

requirements that continue to apply after 2030 and are likely to 

maintain affected EGU emission performance meeting the final 

goal. The state plan would be considered to provide for 

maintenance of emission performance consistent with the final 

goal if the plan measures used to demonstrate projected 

achievement of the final goal by 2030 will continue in force and 

not sunset. After implementation, the state is required to 

compare actual plan performance against the final goal on a 2-

year average basis starting in 2030, and to implement corrective 

measures or a backstop if triggered. 

 In the proposal, the EPA noted that “CAA section 

111(b)(1)(B) calls for the EPA, at least every eight years, to 
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review and, if appropriate, revise federal standards of 

performance for new sources” in order to assure regular updating 

of performance standards as technical advances provide 

technologies that are cleaner or less costly. The proposal 

“requests comment on the implications of this concept, if any, 

for CAA section 111(d).” 79 FR 34830, 34908/3 (June 18, 2014). 

 We acknowledge the obligation to review section 111(b) 

standards as stated. The EPA is not finalizing any position with 

respect to any implications of this concept for section 111(d). 

We are promulgating rules for section 111(d) state plans that 

will establish standards of performance for existing sources to 

which a section 111(b) standard of performance would apply if 

such sources were new sources, within the definition in section 

111(a)(2) of “new source.” It is not necessary to address at 

this time whether subsequent review and/or appropriate revision 

of the corresponding section 111(b) standard of performance have 

any implications for review and/or revision of this rule. 

a. Legal basis for maintaining emission performance. In the 

proposal, the EPA proposed “that the level of emission 

performance for affected EGUs represented by the final goal 

should continue to be maintained.” The EPA explained that 

“Congress either intended the emission performance improvements 

required under CAA section 111(d) to be permanent or, through 
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silence, authorized the EPA to reasonably require permanence. 

Other CAA section 111(d) emission guidelines set emission limits 

to be met permanently.” 79 FR 34830, 34908/2 (June 18, 2014). We 

also requested comment on whether “we should establish BSERbased state performance goals that extend further into the 

future (e.g. beyond the proposed planning period), and if so, 

what those levels of improved performance should be.” Id. at 

34908/3. 

 We received adverse comment on establishing BSER-based 

state performance goals beyond the proposed planning period. 

Commenters argued that we did not have a sufficient basis at 

this time to determine what those future goals should be. We 

agree and have decided not to establish such goals. We are 

finalizing, though, that the level of emission performance for 

affected EGUs represented by the final goal should continue to 

be maintained, for the reasons given in our proposal and quoted 

above. 

 The general structure of the CAA supports our 

interpretation. Section 111(d) plans establish standards of 

performance that reflect the BSER, a technology-based standard. 

Generally speaking, in the future technology will only improve, 

and correspondingly the CAA does not provide explicit processes 

to relax technology-based standards. In contrast, the provisions 
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in Part D of title I that address attainment of health-based 

standards, the NAAQS, explicitly provide that once the NAAQS are 

attained, emission reduction measures may be relaxes so long as 

the NAAQS are maintained. The absence in section 111(d) of 

explicit provisions for future relaxation of emission reduction 

measures, as compared to Part D, supports our interpretation 

that the emission reductions continue to be on-going after the 

CO2 emission performance rates or state CO2 emission goals are 

achieved in 2030. This is consistent with our past practice for 

section 111(d) rules, which do not contain any provision that in 

the future removes or relaxes the promulgated guidelines. In 

light of the persistence of CO2 as a pollutant and its long-term 

impacts, it is particularly critical in these guidelines to 

explicitly provide for continuing emission reductions. 

G. Additional Considerations for State Plans 

1. Consideration of a facility’s “remaining useful life” and 

“other factors” 

This section discusses the way in which the final emission 

guidelines address the CAA section 111(d)(1) provision requiring 

the Administrator, in promulgating 111(d) regulations, to 

“permit the State in applying a standard of performance to any 

particular source under a [111(d)] plan . . . to take into 

consideration, among other factors, the remaining useful life of 
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the existing source to which such standard applies.” 

The final guidelines permit a state, in developing its 

state plan, to fully consider and take into account the 

remaining useful life of an affected EGU and other factors in 

establishing the requirements that apply to that EGU, as 

discussed further below. Therefore, consideration of facilityspecific factors and in particular, remaining useful life, does 

not justify a state making further adjustments to the 

performance rates or aggregate emission goal that the guidelines 

define for affected EGUs in a state and that must be achieved by 

the state plan. Thus, these guidelines do not provide for states 

to make additional goal adjustments based on remaining useful 

life and other facility-specific factors because they can fully 

consider these factors in designing their plans. 

a. Statutory and regulatory backdrop. This section describes the 

statutory and existing regulatory background concerning 

facility-specific considerations in implementation of section 

111(d). 

Section 111(d)(1)(A) requires states to submit a plan that 

“establishes standards of performance” for existing sources. 

Under section 111(d)(1)(B), the plan must also “provide for 

implementation and enforcement of such standards of 

performance.” Finally, the last sentence of section 111(d)(1) 
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provides: “Regulations of the Administrator under this paragraph 

shall permit the State in applying a standard of performance to 

any particular source under a plan submitted under this 

paragraph to take into consideration, among other factors, the 

remaining useful life of the existing source to which such 

standard applies.” 

The EPA’s 1975 implementing regulations1100 addressed a 

number of facility-specific factors that might affect 

requirements for an existing source under section 111(d). Those 

regulations provide that for designated pollutants, standards of 

performance in state plans must be as stringent as the EPA’s 

emission guidelines. Deviation from the standard might be 

appropriate where the state demonstrates with respect to a 

specific facility (or class of facilities): 

(1) Unreasonable cost of control resulting from plant 

age, location, or basic process design; 

(2) Physical impossibility of installing necessary 

control equipment; or 

(3) Other factors specific to the facility (or class 

of facilities) that make application of a less stringent 

standard or final compliance time significantly more 

reasonable. 

This provision was amended in 1995 (60 FR 65387, December 

19, 1995), and is now prefaced with the language “Unless 

 

1100 40 FR 53340 (Nov. 17, 1975). 
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otherwise specified in the applicable subpart on a case-bycase basis for particular designated facilities or classes 

of facilities.” 40 CFR 60.24(f). 

b. Our proposal regarding the implementing regulations. Our 

proposal stated that the reference to “[u]nreasonable cost 

of control resulting from plant age” in 60.24(f) 

“implements” the statutory provision on remaining useful 

life. We also stated that the implementing regulations 

“provide the EPA’s default structure for implementing the 

remaining useful life provision of CAA section 111(d).” We 

noted that the prefatory language “unless otherwise 

specified in the applicable subpart” gives the EPA 

discretion to alter the extent to which the implementing 

rules applied if appropriate for a particular source 

category and guidelines. We requested comment on our 

analysis of the existing implementing regulations and any 

implications for our regulatory text in respect to how 

these guidelines relate to those regulations. 

 Commenters stated, among other things, that the sentence 

concerning “remaining useful life” was added in the 1977 CAA 

Amendments and that therefore it could not be said that 

provisions from the 1975 implementing regulations “implement” 

the sentence. The EPA does not think as a general matter that it 
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is necessarily impossible that a pre-statutory amendment rule 

could continue to serve as a reasonable implementation of a 

post-statutory amendment provision. However, we also think it is 

appropriate, as we suggested in the June 2014 proposal, to 

specify in the applicable subpart for these guidelines that the 

provisions in 60.24(f) should not apply to the class of 

facilities covered by these guidelines. As a result, regardless 

of whether the implementing regulations appropriately implement 

the “remaining useful life” provision in general, the relevant 

consideration is that, as we now explain, these particular 

guidelines “permit the State in applying a standard of 

performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other 

factors, the remaining useful life of the existing source to 

which such standard applies.”

c. How these emission guidelines permit states to consider 

remaining useful life and other facility-specific factors. The 

EPA notes that, in general, the implementing regulation 

provisions for remaining useful life and other facility-specific 

factors are relevant for emission guidelines in which the EPA 

specifies a presumptive standard of performance that must be 

fully and directly implemented by each individual existing 

source within a specified source category. Such guidelines are 
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similar to a CAA section 111(b) standard in their form. For 

example, the EPA emission guidelines for sulfuric acid plants, 

phosphate fertilizer plants, primary aluminum plants, Kraft pulp 

plants, and municipal solid waste landfills specify emission 

limits for sources.1101 In the case of such emission guidelines, 

some individual sources, by virtue of their age or other unique 

circumstances, may warrant special accommodation. 

In these final guidelines for state plans to limit CO2 from 

affected EGUs, however, the agency does not specify presumptive 

performance rates that each individual EGU is to achieve in the 

absence of trading. Instead, these guidelines provide collective 

performance rates for two classes of affected EGUs (steam 

generating units and stationary combustion turbines), and give 

states the alternative of developing plans to achieve a state 

emission goal for the collective group of all affected EGUs in a 

state. Providing states with the ability to consider facility-

 

1101 See “Phosphate Fertilizer Plants; Final Guideline Document 

Availability,” 42 Fed. Reg.FR 12022 (Mar. 1, 1977); “Standards 

of Performance for New Stationary Sources; Emission Guideline 

for Sulfuric Acid Mist,” 42 Fed. Reg.FR 55796 (Oct. 18, 1977); 

“Kraft Pulp Mills, Notice of Availability of Final Guideline 

Document,” 44 Fed. Reg.FR 29828 (May 22, 1979); “Primary 

Aluminum Plants; Availability of Final Guideline Document,” 45 

Fed. Reg. 26,294FR 26294 (Apr. 17, 1980); “Standards of 

Performance for New Stationary Sources and Guidelines for 

Control of Existing Sources: Municipal Solid Waste Landfills, 

Final Rule,” 61 Fed. Reg.FR 9905 (Mar. 12, 1996). 

 
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specific factors such as remaining useful life in designing 

their state plans is one of the fundamental reasons that the EPA 

designed the final rule in this way. In addition, the 

significant revisions since proposal to address achievability 

concerns (e.g., moving the start date from 2020 to 2022, and 

other changes in interim and final state goals summarized in the 

next section) will help to ensure that states in practice can 

consider remaining useful life and other facility-specific 

factors in setting EGU requirements. Of course, EGUs vary 

considerably in age, so remaining useful life is potentially 

relevant to regulation of some units and not others. 

The guidelines capitalize on the inherent flexibility 

offered by the CO2 emission performance rates and by the state 

CO2 emission goals approach, allowing states flexibility on the 

form of the EGU standards that they include in CAA section 

111(d) plans. A state could select a form of standards (e.g., 

marketable credits or permits, retirement of certain older 

facilities after their useful life, etc.) that avoids or 

diminishes concerns about facility-specific factors such as 

remaining useful life. If a state adopted the CO2 emission 

performance rates for fossil fuel-fired electric utility steam 

generating units and stationary combustion turbines in 

conjunction with rate-based trading, though, the state would be 
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taking remaining useful life into consideration by allowing 

affected EGUs to comply using ERCs. In effect, under a trading 

program with repeating compliance periods, a facility with a 

short remaining useful life has a total outlay that is 

proportionately smaller than a facility with a long remaining 

useful life, simply because the first facility would need to 

comply for fewer compliance periods and would need 

proportionately fewer ERCs than the second facility. Buying ERCs 

would avoid excessive up-front capital expenditures that might 

be unreasonable for a facility with a short remaining useful 

life, and would reduce the potential for stranded assets. 

In addition to providing states with flexibility on the 

form of the standards of performance in their plans, the 

guidelines leave to each state the design of the specific 

requirements that fall on each affected EGU in applying those 

standards. To the extent that an emission standard that a state 

may wish to adopt for affected EGUs raises facility-specific 

issues, the state may make adjustments to a particular 

facility’s requirements on facility-specific grounds, so long as 

any such adjustments are reflected (along with any necessary 

compensating emission reductions to meet the state goal) in the 

state’s CAA section 111(d) plan submission. 

Finally, we note that these guidelines permit states to use 
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a rate or mass CO2 emission goal, and that each of these pathways 

allow states multiple design choices. Under either pathway 

states can take into consideration remaining useful life and 

seek to avoid stranded assets.

 The EPA believes that this approach to permitting states to 

consider remaining useful life is appropriate because it 

reflects, and is compatible with, the interconnected nature of 

the electricity system. 

Although this discussion emphasizes state flexibility on 

plan design, it is important to note that the main intended 

beneficiaries of state flexibility are the affected EGUs 

themselves. As a key case in point, the EPA has endeavored to 

craft the final guidelines to support and facilitate state plans 

that include trading systems, including interstate trading 

systems that can help EGUs continue to operate with the 

flexibility that they currently enjoy on regional grid levels. 

Trading can provide affected EGUs that have a limited 

remaining useful life with the flexibility to comply through 

purchasing allowances or ERCs, thereby avoiding major capital 

expenditures that would create long-term debt. By buying 

allowances or ERCs, affected EGUs with a limited remaining 

useful life contribute to achieving emission reductions from the 

source category during the years that they operate. During its 
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lifetime, a facility with a short remaining useful life will 

need fewer total credits or allowances than an otherwise 

comparable facility with a long remaining useful life, but the 

annualized cost to the two facilities is the same.1102 

In part to help states address remaining useful life 

considerations, the final guidelines facilitate state plans that 

employ trading in multiple ways: 

 By allowing trading under emission standards plans and 

state measures plans, and under rate-based plans and 

mass-based plans; 

 By defining national EGU performance rates that make it 

easier for states to set up rate-based trading regimes 

that allow for interstate trading of ERCs; 

 By clearly defining the requirements for mass-based and 

rate-based trading systems to ensure their integrity; and 

 By providing information on potential allocation 

approaches for mass-based trading. 

In addition, the EPA is separately proposing model trading rules 

for rate-based and mass-based trading to assist states with 

 

1102 Trading of course has other benefits beyond helping to 

address remaining useful life concerns. For example, trading can 

lower costs of achieving a given level of emission reduction and 

can provide economic incentives for innovation and development 

of cleaner technologies. 

 
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design of these programs in the section 111(d) context. 

d. Why remaining useful life and other facility-specific factors 

do not warrant adjustments in the guidelines’ performance rates 

and state goals. Under the final guidelines, remaining useful 

life and other facility-specific considerations do not provide a 

basis for adjusting the CO2 emission performance rates, or the 

state’s rate-based or mass-based CO2 emission goals, nor do they 

affect the state’s obligation to develop and submit an 

approvable CAA section 111(d) plan that adopts the CO2 emission 

performance rates or achieves the goal by the applicable 

deadline. After considering public comments discussed below and 

in the response to comments document, the EPA has retained this 

aspect of the proposed rule for the reasons described below. 

As noted above, the final guidelines provide aggregate 

emission goals for affected EGUs in each state, in addition to 

the CO2 emission performance rates. The guidelines also reflect a 

number of changes from proposal to address concerns about 

achievability of proposed state goals that were raised in public 

comments, many of which were explicitly prompted by 

consideration of the remaining useful life issue. The result is 

to afford states with broad flexibility to design requirements 

for affected EGUs to achieve the CO2 emission performance rates 

or state CO2 emission goals in ways that avoid requiring major 
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capital expenditures, or imposing unreasonable costs, on those 

affected EGUs that have a limited remaining useful life. State 

plans may use any combination of the emissions reduction methods 

represented by the building blocks, and may also choose to 

employ emission reduction methods that were not assumed in 

calculating state goals. 

To be more specific, the EPA notes that a state is not 

required to achieve the same level of emission reductions with 

respect to any one building block as assumed in the EPA’s BSER 

analysis. A state may use any combination of measures, including 

those not specifically factored into the BSER by the EPA. The 

EPA has estimated reasonable rather than maximum possible 

implementation levels for each building block in order to 

establish EGU emission rates and state goals that are achievable 

while allowing states to take advantage of the flexibility to 

pursue some building blocks more aggressively, and others less 

aggressively, than is reflected in the agency’s computations, 

according to each state’s needs and preferences. The guidelines 

provide further flexibility by allowing state plans to use 

emission reduction methods not reflected in the BSER. A 

description of multiple emission reduction methods is provided 

in sections VIII.I-K. 

e. Response to key comments on remaining useful life. In 
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response to the proposed guidelines, some commenters said that 

the proposed state goals were unachievable and therefore too 

stringent to provide states, as a practical matter, with the 

flexibility to consider remaining useful life for individual 

units. These commenters said the result would be premature 

retirements and stranded assets. 

In the final guidelines, the EPA has addressed the comments 

about lack of practical flexibility to consider remaining useful 

life by revising key elements of the guidelines in ways that 

will ensure that the CO2 emission performance rates and state CO2

emission goals are achievable considering cost. At the same 

time, the final guidelines maintain the broad flexibility of 

each state to design its own compliance pathway, taking into 

account any facility-level concerns – including remaining useful 

life – in designing EGU requirements. 

The changes to the BSER and goal-setting methodologies 

include: 

 Starting the interim goal period in 2022 rather than 

2020, which allows more lead time for states and 

regulated entities and helps to ensure that the interim 

goal is achievable 

 Revising the goal-setting formula and the state goals 

themselves 
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 Updating analyses of achievable levels of improvement 

through the building blocks that together represent the 

BSER, while keeping them at reasonable, rather than 

maximum, levels (thus creating headroom which can, and is 

intended to, help to accommodate the range of ages of 

different facilities) 

 Providing an explicit phase-in schedule for meeting the 

revised interim goals, while also allowing a state the 

option of choosing its own emission reduction trajectory 

The final guidelines also contain changes to avoid certain 

inconsistencies between the goal-setting methodology and 

accounting of reductions under state plans that could have made 

state goals less achievable for some states. 

Together, the changes described above help to ensure that 

the CO2 emission performance rates and state CO2 emission goals 

established in the final guidelines are achievable, and leave 

states with the practical ability to issue rules that take into 

account the remaining useful life of affected EGU. 

As explained in the Legal Memorandum accompanying this 

rule, the EPA believes that Congress intended the remaining 

useful life provision to provide a mechanism for states to avoid 

the imposition of unreasonable retrofit costs on existing 

sources with relatively short remaining useful lives, a scenario 
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that could result in stranded assets. However, commenters on the 

proposed rule raised a different stranded assets concern not 

primarily related to retrofit costs -- a concern that the 

proposed rule could cause changes in economic competitiveness of 

particular EGUs that would prompt their retirement before the 

end of their economically useful lives. These commenters said 

the proposed state goals were so stringent that states would 

have no choice but to adopt requirements that would result in 

retirements of coal-fired capacity that had been built 

relatively recently or had recently made pollution control 

investments. In response to these comments, the EPA has 

conducted a stranded assets analysis which demonstrates that the 

CO2 emission performance rates and state goals in the final 

guidelines provide sufficient flexibility to states to address 

stranded asset concerns. The EPA shares the goal of minimizing 

stranded assets. Although nothing in section 111(d) explicitly 

bars a guideline that results in some facilities becoming 

uneconomic before the end of their useful lives, the EPA 

nonetheless has striven to design the guidelines so as to give 

states flexibility to develop plans that include, for example, 

differential treatment of affected EGUs or opportunities to rely 

on emissions trading, to allow power companies to recover their 

investments in generation units. 
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For purposes of the stranded assets analysis, the EPA 

considered a potential “stranded asset” to be an investment in a 

coal-fired EGU (or in a capital-intensive pollution control 

installed at such an EGU) that retires before it is fully 

depreciated. Book life is the period over which long-lived 

assets are depreciated for financial reporting purposes. The 

agency estimated typical book life by researching financial 

statements of utility and merchant generation companies in 

filings to the Securities and Exchange Commission. The agency 

estimated the book life of coal-fired EGUs to be 40 years, and 

assumed a 20-year book life for pollution control retrofits. The 

book life of coal-fired EGUs (coal steam and IGCC) is twice as 

long as the debt life and the depreciation schedule used for 

federal tax purposes. Although the book life for environmental 

retrofits is often 15 years, the agency conservatively assumed 

20 years in this analysis. 

The analysis examined coal generation in the three large 

regional interconnections of the U.S. The analysis found that in 

both 2025 and 2030, for each region, the amount of 2012 coal 

generation included in the final guidelines’ emission 

performance rate calculation -- specifically, the generation 

remaining after the BSER calculation -- is greater than the 

amount of 2012 generation from coal-fired EGUs that are not 
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fully depreciated in those years under the book life assumptions 

described above. This shows that the final rule allows 

flexibility for states to preserve these units as part of their 

plans. 

To put this analysis in perspective: The EPA’s role is to 

set emission guidelines that meet the statutory requirements, 

which includes consideration of cost in identifying the BSER, as 

the EPA has done in these guidelines. States have a broad degree 

of flexibility to design plans to achieve the rates in the 

emission guidelines in a manner that meets their policy 

priorities, including ensuring cost-effective compliance. 

Although not a required component of the EPA’s consideration of 

cost, this analysis shows that the CO2 emission performance rates 

in the final guidelines can be met without the retirement of 

affected EGUs before the end of their book life, and without the 

retirement of affected EGUs before the end of the book life of 

capital-intensive pollution control retrofits installed on those 

EGUs. Thus, according to this analysis, the CO2 emission 

performance rates and state CO2 emission goals need not result in 

stranded assets. The EPA recognizes that power plant economics 

are determined by many aspects of markets that are outside of 

the EPA’s control, such as wholesale power prices and capacity 

prices, and that the compliance path of least cost may involve 
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retiring assets that have not fully depreciated. Nonetheless, 

this analysis further demonstrates the extent of flexibility 

available to states in designing their plans to best serve the 

policy priorities of the state. Details are available in a memo 

to the docket.1103

Several commenters said that the statute does not authorize 

the EPA to require other facilities to achieve greater 

reductions to compensate for a facility that warrants relief 

based on remaining useful life. One said that consideration of 

remaining useful life and other relevant factors is a one-way 

ratchet that provides relief to sources that cannot achieve the 

BSER, and that the EPA turns that approach on its head by 

prohibiting a state from providing such relief to a specific 

facility unless it can identify another facility to “punish” by 

requiring additional emissions reductions to offset that relief. 

The EPA disagrees with these comments, which proceed from 

an incorrect premise. The EPA is not determining a BSER-based 

emission level achievable by each individual facility without 

trading, and then requiring better-than-BSER from some 

facilities to make up to worse-than-BSER performance that a 

state authorizes for other facilities because of a short 

 

1103 Memorandum to Clean Power Plan Docket titled “Stranded Assets 

Analysis” dated July 2015. 
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remaining useful life. Rather, as previously noted, the 

guidelines set CO2 emission performance rates and state CO2

emission goals that represent the average or aggregate emission 

level achievable by affected EGUs based on regional average 

estimates of the impact of applying the BSER to collective 

groupings of affected EGUs.1104 In estimating the amount of 

improvement achievable through each building block (e.g., 

improvement in heat rate or amount of generation shift to loweremitting EGUs), the EPA has estimated the average level 

achievable by EGUs in a region rather than attempting to 

estimate the level achievable by each and every affected EGU in 

the absence of trading. Thus, the fact that an individual 

facility may be unable, for example, to achieve the average 

level of heat rate improvement assumed in goal-setting is 

consistent with the EPA’s analysis, and does not undermine the 

EPA’s determination of CO2 emission performance rates and state 

CO2 emission goals. The Legal Memorandum discusses additional 

reasons that the agency disagrees with comments that the 

 

1104 The EPA expects that states that choose to adopt the national 

CO2 emission performance rates for all of their EGUs would permit 

ERC trading, rather than requiring each facility to meet the 

applicable rate without trading. In effect, the presence of 

trading means that the EGU performance rates will be achieved on 

average by the EGUs involved in trading, rather than be achieved 

by each facility in the absence of trading. 
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guideline must permit adjustments in the guidelines’ CO2 emission 

performance rates and state CO2 emission goals based on remaining 

useful life considerations. 

An additional reason that the EPA believes that 

consideration of remaining useful life and other facilityspecific factors does not warrant adjustments to state goals is 

that the design of the guidelines does not mandate that states 

impose requirements that would call for substantial capital 

investments at affected EGUs late in their useful life. Multiple 

methods are available for reducing emissions from affected EGUs 

that do not involve capital investments by the owner/operator of 

an affected EGU. For example, generation shifts among affected 

EGUs, and addition of new RE generating capacity do not 

generally involve capital investments by the owner/operator at 

an affected EGU. Additional emission reduction methods available 

to states that do not entail significant capital costs at 

affected EGUs are discussed elsewhere in this preamble. 

Heat rate improvements at affected EGUs do require capital 

investments. However, states have flexibility to design their 

plan requirements; they are not required to mandate heat rate 

improvements at plants that have limited remaining useful life. 

In fact, a state can choose whether or not to require heat rate 

improvements at all. The agency also notes that capital 
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expenditures for heat rate improvements would be much smaller 

than capital expenditures required for example, for purchase and 

installation of scrubbers to remove sulfur dioxide; a fleet-wide 

average cost for heat rate improvements based primarily on best 

practices at coal-fired generating units would not likely exceed 

$100/kW, compared with a typical SO2 wet scrubber cost of $500/kW 

(costs vary with unit size).1105 Even if a state did choose to 

adopt requirements for heat rate improvements, the proposed 

guidelines would allow states to regulate affected EGUs through 

flexible regulatory approaches that do not require affected EGUs 

to incur large capital costs (e.g., averaging and trading 

programs). Under the EPA’s final approach - establishing state 

goals and providing states with flexibility in plan design – 

states have flexibility to make exactly the kind of judgments 

necessary to avoid requiring capital investments that would 

result in stranded assets. 

Remaining useful life and other factors, because of their 

facility-specific nature, are potentially relevant as states 

determine requirements that are directly applicable to affected 

 

1105 Heat rate improvement methods and related capital costs are 

discussed in the GHG Mitigation Measures TSD; SO2 scrubber 

capital costs are from the documentation for the EPA’s IPM Base 

Case v5.13, Chapter 5, Table 5-3, available at 

http://www.epa.gov/airmarkets/documents/ipm/Chapter_5.pdf. 
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EGUs. If relief is due a particular facility, the state has an 

available toolbox of emission reduction methods that it can use 

to develop a section 111(d) plan that will achieve the CO2

emission performance rates or state CO2 emission goals on time. 

The EPA therefore concludes that the remaining useful life of 

affected EGUs, and the other facility-specific factors 

identified in the existing implementing regulations, should not 

be regarded as a basis for adjusting the CO2 emission performance 

rates or a state CO2 emission goal, and should not relieve a 

state of its obligation to develop and submit an approvable plan 

that achieves that goal on time. 

f. Legal considerations regarding remaining useful life. Section 

111(d)(1) requires the EPA in promulgating section 111(d) 

regulations to “permit the State in applying a standard of 

performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other 

factors, the remaining useful life of the existing source to 

which such standard applies.” Here, we discuss the legal basis 

for determining that the emission guidelines are consistent with 

this statutory requirement. For details, please see the Legal 

Memorandum. 

Section 111(d)(1) only requires that EPA emission 

guidelines permit states to take into account remaining useful 
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life (among other factors), but section 111(d)(1) does not 

specify how the EPA must permit that. In other words, the 

meaning of the provision and the way that the EPA is to 

implement it in promulgating guidelines are not specified 

further in the provision. The provision is ambiguous and capable 

of implementation in several ways, and therefore the EPA has 

discretion to interpret and apply it. Furthermore, section 

111(d)(1) does not suggest that states must be given carte 

blanche to consider remaining useful life in any way that can be 

imagined. As detailed above in sections VIII.G.1.c-e, these 

guidelines permit states to take into account remaining useful 

life in a number of reasonable ways and thus the guidelines 

satisfy the statutory obligation. 

The phrase “remaining useful life” also appears in the 

visibility provisions of section 169A. There, in determining 

best available retrofit technology (BART), the state (or the 

EPA) must take into consideration (among other factors) “the 

remaining useful life of the source.” 42 USC 7491(g)(2); see 

also id. (g)(1) (reasonable progress). In the context of the 

visibility program, we have interpreted this provision to mean 

that the remaining useful life should be considered when 

calculating the annualized costs of retrofit controls. See 40 

CFR Pt. 51, App. Y, IV.D.4.k.1. This annualized cost is then 
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used to determine a cost effectiveness, in dollars per ton of 

pollutant removed on an annual basis. As a result, a technology 

with a large initial capital cost that might have a reasonable 

cost-effectiveness for a facility with a long remaining useful 

life would have a much higher and possibly unreasonable costeffectiveness for a facility with a short remaining useful life. 

 Although section 111(d)(1) is different than section 

169A(g)(2) and need not be interpreted in the same way, we would 

note (as discussed in detail in sections VIII.G.1.c-e, section 

5.11 of the Response to Comments document, and the Legal 

Memorandum) that (for example) a trading program under these 

section 111(d) guidelines only requires compliance on a periodic 

basis and does not require any initial capital expenditures.

Thus, over the life of the facility, a facility with a short 

remaining useful life will need fewer total credits or 

allowances than an otherwise comparable facility with a long 

remaining useful life, but the annualized cost to the two 

facilities is the same. In other words, under a trading program 

remaining useful life of a source is automatically accounted for 

in the way it is accounted for under the visibility program. 

 Some commenters stated that the EPA’s interpretation of 

remaining useful life is impermissible. These commenters claimed 

that states, if they wish to take into account remaining useful 
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life at one affected EGU, must relax the stringency of the 

emission standard for that EGU. Then, the state would be 

compelled to increase the stringency of emission standards at 

other affected EGUs in order to achieve the state performance 

goal. According to these commenters, section 111(d) does not 

allow this outcome. 

 First, the commenters are mistaken in their premise. As 

discussed in section VIII.G.1, section 5.11 of the Response to 

Comments document, the Legal Memorandum, and in the example 

immediately above, states can impose the exact same emission 

standards on two affected EGUs and still take into account 

remaining useful life through the availability of trading. In 

other words, states need not relax an emission standard here and 

strengthen an emission standard there in order to take into 

account remaining useful life. Thus, these guidelines permit 

states to take into account remaining useful life without any of 

the effects commenters are concerned about. 

 Second, even if states decide to relax emission standards 

at one EGU, on the basis of remaining useful life or any other 

factor, nothing in the last sentence of section 111(d)(1) 

prohibits these guidelines from requiring the state plan to 

still meet the CO2 emission performance rates or state CO2

emission goal. In fact, that sentence is completely silent on 
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the issue. Thus, the EPA has the discretion to determine what 

should be the concomitant effects if a state chooses to consider 

remaining useful life in a particular way. In this case the 

concomitant effect of a state relaxing one emission standard may 

be that the state must make up for it elsewhere in order to meet 

the goal, but nothing in section 111(d)(1), including the 

statutory requirement to permit consideration of remaining 

useful life, prohibits that outcome. 

2. Electric reliability

The final rule features overall flexibility, a long 

planning and implementation horizon, and a wide range of options 

for states and affected EGUs to achieve the CO2 emission 

performance rates or state CO2 emission goal. This design 

reflects, among other things, the EPA’s commitment to ensuring 

that compliance with the final rule does not interfere with the 

industry’s ability to maintain the reliability of the nation’s 

electricity supply. Comments from state, regional and federal 

reliability entities, power companies and others, as well as 

consultation with the Department of Energy (DOE) and Federal 

Energy Regulatory Commission (FERC), helped inform a number of 

changes made in this final rule to address reliability. In 

addition, FERC conducted one national and three regional 

technical conferences on the proposed rule in which the EPA 
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participated and at which the issue of reliability was raised by 

numerous participants. 

 As discussed throughout the preamble and TSDs, the 

electricity sector is undergoing a period of intense change. 

While the change in the resource mix has accelerated in recent 

years, wind, solar, other RE, and EE resources have been 

reliably participating in the electric sector for a number of 

years. Many of the potential changes to the electric system that 

the final rule may encourage, such as shifts to cleaner sources 

of power and efforts to reduce electricity demand, are already 

well underway in the electric industry. To the extent that the 

final rule accelerates these changes, there are multiple 

features well embedded in the electricity system that ensure 

that electric system reliability will be maintained. Electric 

system reliability is continually being considered and planned 

for. For example, in the Energy Policy Act of 2005, Congress 

added a section to the Federal Power Act to make reliability 

standards mandatory and enforceable by FERC and the North 

American Electric Reliability Corporation (NERC), the Electric 

Reliability Organization which FERC designated and oversees. 

Along with its standards development work, NERC conducts annual 

reliability assessments via a 10-year forecast and winter and 

summer forecasts; audits owners, operators, and users for 
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preparedness; and educates and trains industry personnel.

Numerous other entities such as FERC, DOE, state PUCs, 

ISOs/RTOs, and other planning authorities also consider the 

reliability of the electric system. There are also numerous 

remedies that are routinely employed when there is a specific 

local or regional reliability issue. These include transmission 

system upgrades, installation of new generating capacity, 

calling on demand response, and other demand-side actions. 

Additionally, planning authorities and system operators 

constantly consider, plan for, and monitor the reliability of 

the electricity system with both a long-term and short-term 

perspective. Over the last century, the electric industry’s 

efforts regarding electric system reliability have become 

multidimensional, comprehensive, and sophisticated. Under this 

approach, planning authorities plan the system to assure the 

availability of sufficient generation, transmission, and 

distribution capacity to meet system needs in a way that 

minimizes the likelihood of equipment failure.1106 Long-term 

system planning happens at both the local and regional levels 

with all segments of the electric system needing to operate 

 

1106 Casazza, J. and Delea, F., Understanding Electric Power 

Systems: An Overview of the Technology, the Marketplace, and 

Government Regulations, IEEE Press, at 160 (2010).
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together in an efficient and reliable manner. In the short-term, 

electric system operators operate the system within safe 

operating margins and work to restore the system quickly if a 

disruption occurs.1107 Mandatory reliability standards apply to 

how the bulk electric system is planned and operated. For 

example, transmission operators and balancing authorities have 

to develop, maintain, and implement a set of plans to mitigate 

operating emergencies.1108 

As the electricity market changes and new challenges 

emerge, electric system regulators and industry participants 

make changes to how the electric system is designed and operated 

to respond to these challenges. For example, expressing 

reliability and rate concerns about fuel assurance issues, FERC 

recently issued an order requiring ISOs/RTOs to report on the 

status of their efforts to address market and system performance 

associated with fuel assurance.1109 In February of 2015, 

Midcontinent Independent System Operator (MISO), California 

 

1107 Id. 1108 NERC Reliability Standard EOP-001-2.1b — Emergency Operations 

Planning, available at 

http://www.nerc.net/standardsreports/standardssummary.aspx. 

1109 Centralized Capacity Markets in Regional Transmission 

Organizations and Independent System Operators, 149 FERC ¶ 

61,145 (2014). FERC generally defines fuel assurance as 

“generator access to sufficient fuel supplies and the firmness 

of generator fuel arrangements”. Id. P 5. 
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Independent System Operator Corporation (CAISO), New York 

Independent System Operator (NYISO), Southwest Power Pool (SPP), 

ISO New England (ISO-NE), and PJM Interconnection (PJM) each 

filed a report with FERC highlighting their efforts to respond 

to fuel assurance concerns.1110 This is just one of many examples 

where electric system regulators and industry participants 

recognize a potential reliability issue and are proactively 

searching for solutions. 

The EPA’s approach in this final rule is consistent with 

our commitment to ensuring that compliance with the final rule 

does not interfere with the industry’s ability to maintain the 

reliability of the nation’s electricity supply. Many aspects of 

the final rule’s design are intended to support system 

reliability, especially the long compliance period and the basic 

design that allows states and affected EGUs flexibility to 

include a large variety of approaches and measures to achieve 

 

1110 For example, ISO-NE and PJM each filed “pay-for-performance” 

proposals to address fuel assurance in their regions. FERC 

recently acted on ISO-NE market rule changes providing increased 

market incentives in capacity, energy, and ancillary services 

markets for generators to be available to meet their obligations 

during reserve shortages. ISO New England Inc., 147 FERC ¶ 

61,172 (2014). Additionally, FERC conditionally approved a PJM 

“pay-for-performance” proposal that creates a new capacity 

product to provide greater assurance of delivery of energy and 

reserves during emergency conditions, establishing credits for 

superior performance and charges for poor performance. PJM 

Interconnection, L.L.C., 151 FERC ¶ 61,208 (2015). 
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the environmental goals in a way that is tailored to each 

state’s and utility’s energy resources and policies. Despite the 

flexibility built into the design of the proposal, and the long 

emission reduction trajectory, many commenters expressed 

concerns that the proposed rule could jeopardize electric system 

reliability. We note that the EPA has received similar comments 

in EPA rulemakings dating as far back as the 1970s. The EPA has 

always taken and continues to take electric system reliability 

comments very seriously. These reoccurring comments with regard 

to reliability notwithstanding, the electric industry has done 

an excellent job of maintaining reliability, including when it 

has had to comply with environmental rules with much shorter 

compliance periods and much less flexibility than this final 

rule provides. Now, more than ever, the electric industry has 

tools available to maintain reliability, including mandatory and 

enforceable reliability standards.1111 

 

1111For example, Andrew Ott, then Executive Vice President-Markets 

and current President of PJM, an RTO with a substantial amount 

of coal-fired capacity and generation, discussed the success of 

PJM’s market design in assuring that PJM met and exceeded target 

reserve margins while MATS was being implemented. See Statement 

of Andrew Ott, PJM Executive Vice President-Markets, FERC 

Technical Conference on Centralized Capacity Markets in Regional 

Transmission Organizations and Independent System Operators, 

AD13-7-000, at 3, 7 (Sept. 25, 2013), available at 

http://www.ferc.gov/EventCalendar/EventDetails.aspx?ID=6944&CalT

ype= &CalendarID=116&Date=09/25/2013&View=Listview. At the FERC 
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As with numerous prior CAA regulations affecting the 

electric power sector, environmental requirements for this 

industry are accommodated within the existing extensive 

framework established by federal and state law to ensure that 

electricity production and delivery are balanced on an ongoing 

basis and planned sufficiently to ensure reliability and 

affordability into the future. In addition, changes that the EPA 

is making in this final rule respond directly to the comments 

and the suggestions that we received on reliability and provide 

further assurance that implementation of the final rule will not 

create reliability concerns. 

First, the final rule allows significant flexibility in how 

the applicable CO2 emission performance rates or the statewide 

CO2 goals are met. Given the differing characteristics of the 

electric grid within each state and region, there are many paths 

 

national Clean Power Plan Technical Conference, Michael J. 

Kormos, PJM Executive Vice President-Operations, said that PJM’s

markets have proven, “resilient enough to respond to different 

policy initiatives. . . Whether it is the Sulfur Dioxide Trading 

Program of the 1990s, the MATS rule or individual state RPS 

initiatives, the markets have been able to send the appropriate 

price signals that produce competitive outcomes.” See Michael J. 

Kormos, PJM Executive Vice President, Statement at FERC 

Technical Conference on EPA’s Clean Power Plan, AD15-4-000, at 3 

(Feb. 19, 2015), available at 

http://www.ferc.gov/CalendarFiles/20150213081650-

Kormos,%20PJM.pdf. 
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to meeting the final rule’s requirements that can be taken while 

continuing to maintain a reliable electricity supply. As further 

described elsewhere in section VIII, states can develop plans to 

meet the CO2 emission performance rates or state CO2 emission 

goals by choosing from a variety of state plan types and 

approaches that afford states and affected EGUs appropriate 

flexibility. EE and other measures that were not included in the 

determination of the BSER can strengthen a state’s ability to 

establish a plan to meet the CO2 emission performance rates or 

state CO2 emission goals by providing a considerable amount of 

headroom above the levels of the rates and goals. EE especially, 

because it reduces load, can provide assurance that reliability 

can and will be maintained. Additionally, the final rule offers 

opportunities for trading among affected EGUs within and between 

states, and other multi-state approaches that will further 

support electric system reliability. 

Second, the final rule provides sufficient time to ensure 

system reliability. The final rule retains the 2030 date for the 

final period, which commenters largely supported as reasonable 

and not a concern for reliability, and addresses one of the key 

issues that commenters pointed to as a reliability-related 

concern by both moving the start of the interim period from 2020 

to 2022 and adjusting the interim goals to provide a more 
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gradual phasing-in of the initial reduction requirement and thus 

a more gradual emissions reduction trajectory or glide path to 

the final 2030 goals. These changes deliver on the intent of the 

proposal to afford states and affected EGUs the latitude to 

determine their own emissions reduction schedules over the 

interim period. Both FERC’s May 15, 2015 letter1112 and the 

comment record made it clear that providing sufficient time for 

planning and implementation is essential to ensuring electric 

system reliability. The EPA has responded by providing 

additional time to allow for planning and implementation of the 

final rule requirements, while at the same time allowing enough 

time between the beginning of the interim period and 2030 to 

achieve state goals or emission performance rates. We note that 

the final rule does not require that all states have met their 

interim goal or performance rate by 2022 but rather that they 

meet it on average or cumulatively, as appropriate, during the 

2022 to 2029 period. 

As a result of these changes, the states themselves will 

have a meaningful opportunity – which, again, many commenters 

suggested the timing and stringency of the proposal failed to 

 

1112 On May 15, 2015, the five FERC Commissioners sent a letter to 

Acting Assistant Administrator Janet McCabe regarding the EPA’s 

Clean Power Plan proposal. See FERC letter, available at

http://ferc.gov/media/headlines/2015/ferc-letter-epa.pdf. 
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create despite our intent to do so – to determine the timing, 

cadence and sequence of actions needed for states and sources to 

meet final rule requirements while accommodating the ongoing 

activity needed to ensure system reliability. The final rule 

provides more than 6 years before reductions are required and an 

8-year period from 2022 to 2029 to meet interim goals. Moreover, 

while the final rule requires each state to submit a plan by 

September 6, 2016, we recognize that some states may need more 

than 1 year to complete all of the actions needed for their 

final state plans, including consideration of reliability. 

Therefore, states have the opportunity to receive an extension 

for submitting a final plan. If the state needs additional time 

to submit a final plan, then the state may submit an initial 

submittal by September 6, 2016, that must address three required 

components sufficiently to demonstrate that a state is able to 

undertake steps and processes necessary to timely submit a final 

plan by the extended date of September 6, 2018. 

Third, we are including in the final rule a requirement 

that each state demonstrate in its final state plan submittal 

that it has considered reliability issues in developing its 

plan. This was suggested by a number of commenters, and we agree 

that it is a useful element to state plan development. 

Fourth, the final rule provides a mechanism for a state to 
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seek a revision to its plan in order to address changes in 

circumstances that could have reliability impacts if not 

accommodated in the plan. The long compliance timeframe, with 

several interim steps, naturally provides opportunities for 

states, working with their utilities and reliability entities, 

to assess how implementation is proceeding, identify unforeseen 

changes that may warrant plan revisions, and work with the EPA 

to make necessary revisions. Similarly, the ready availability 

of emissions trading as a compliance tool affords EGUs ample 

flexibility to integrate compliance with both routine and 

critical reliability needs. 

Fifth, in response to a variety of comments, we are 

providing a reliability safety mechanism that provides a path 

for a state to come to the EPA during an immediate, unforeseen, 

emergency situation that threatens reliability to notify the EPA 

that an affected EGU or EGUs may need to temporarily comply with 

modified emission standards to respond to this kind of 

reliability concern. 

Sixth and finally we are committed to maintaining an 

ongoing relationship with FERC and DOE as this final rule is 

implemented to help ensure continued reliable electric 

generation and transmission. 

We provide more details about these various elements of the 
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final rule, as well as other features of the rule that support 

system reliability, below. 

a. Summary of key comments. The EPA received a number of 

comments regarding the proposed rule and electric reliability. 

Many commenters provided specific, useful ideas regarding 

changes that could be made to the proposal to specifically 

address their reliability concerns. For example, many commenters 

state that allowing additional time to comply could help in 

meeting the final rule requirements while addressing their 

reliability concerns. Some commenters suggest that additional 

time would allow them to evaluate potential reliability impacts 

and system changes that need to be made to comply with final 

rule requirements while allowing affected EGUs time to meet 

interim CO2 emissions goals. The EPA also received comment that 

market-based approaches have features that could help support 

reliability, and therefore we should encourage states to join or 

form regional market-based programs. Commenters also stated that 

the EPA should require states to consult with grid operators who 

would analyze the impact of state plans on reliability. A number 

of commenters also suggested that the EPA should include some 

sort of reliability safety valve in the final rule. We note that 

many participants at the FERC technical conferences on the 

proposed rule also discussed a reliability safety valve in great 
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detail with many suggestions for how such a reliability 

mechanism could be designed. The EPA appreciates these and all 

the comments we received regarding the interaction of the 

proposal and electric reliability. We have carefully considered 

all comments, consulted further with FERC and incorporated many 

of the suggested changes in this final rule. 

b. Final rule flexibility. In issuing this final rule, the EPA 

considered public comments on the potential interaction between 

the proposal and electric reliability. While we have made every 

effort to develop guidelines that would allow states and 

utilities to steer clear of potential reliability disruptions, a 

number of commenters argued that the possibility of an 

unanticipated reliability event cannot be entirely eliminated. 

It is important to note that there are many factors that 

influence system reliability and, given the complexity of the 

electric grid, electric system planners and operators likely 

will not completely avoid reliability issues, even in the 

absence of these guidelines. The EPA designed the final rule to 

ensure to the greatest extent possible that actions taken by 

states and affected EGUs to comply with the final rule do not 

increase potential reliability issues or complicate their 

resolution. In fact, to the extent that meeting final rule 

requirements results in the reduction of demand, upgrades in 
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transmission efficiency and infrastructure, and investment in 

new, more efficient technologies, the outcome could be that the 

system is more robust and faces fewer risks to electric 

reliability. 

One specific concern raised by many commenters is that the 

proposed plan development schedule may not leave sufficient time 

to conduct reliability planning between the development of state 

plans and the proposed start of the interim period in 2020. To 

address these concerns and to support a more effective 

reliability planning process, the EPA is moving the start of the 

interim period from 2020 to 2022 and adjusting the interim goals 

to provide a gradually phased-in initial reduction requirement 

and a more gradual glide path to the final 2030 goals. This more 

gradual application of the BSER over the 2022-2029 interim 

period provides the state with substantial latitude in selecting 

the emission reduction glide path for affected EGUs over that 

period. As noted above, the final rule also provides states with 

up to 3 years to adopt and submit their final state plans, and 

afterwards states can, if necessary, revise their plans, as 

discussed in section VIII.E.7. This timing gives system planners 

and operators the opportunity to do what they have already been 

doing; looking ahead to forecast potential contingencies that 

pose reliability risks and identifying those actions needed to 
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mitigate those risks. The final rule allows states to develop a 

pathway over the interim period that reflects their own 

circumstances, such as reflecting planned additions and changes 

in generation mix and potentially taking advantage of 

opportunities for trading of credits or allowances by affected 

EGUs within and between states. Because achievement of the 

emission rates or goals can be demonstrated over several years, 

state plans can accommodate situations where, for example, it 

may take time to develop new generation, pipelines, or 

transmission while still providing many options for meeting the 

final rule requirements and planning for the reliability of the 

system. 

c. Considering reliability during state plan development 

process. Under CAA section 111(d)(1)(B), state plans must 

provide for the implementation and enforcement of standards of 

performance for affected EGUs. The EPA does not believe a state 

that establishes standards of performance for affected EGUs 

without taking reliability concerns into consideration 

satisfactorily provides for the implementation of such standards 

of performance as required by CAA section 111(d)(1)(B), as a 

serious reliability issue would disrupt the state's 

implementation of the state plan. Therefore, the EPA is 

requiring that each state demonstrate as part of its final state 
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plan submission that it has considered reliability issues while 

developing its plan in order to ensure that standards of 

performance can be implemented and enforced as required by the 

CAA. If system reliability is threatened, the ability of 

affected EGUs to meet the requirements of this final rule could 

be compromised if they are required to operate beyond the 

emission standards established in state plans in order to 

maintain the reliability of the electric grid. The requirement 

that states consider reliability as part of the development of 

state plans is therefore designed to ensure that state plans are 

flexible enough to avoid this kind of potential conflict between 

maintaining reliability and providing for the implementation of 

emission standards for affected EGUs as required by the CAA. 

A number of commenters, notably ISOs and RTOs, also 

discussed reliability concerns in the context of state plans and

pointed out that planning and anticipation of change are among 

the essential ingredients of ensuring the ongoing reliability of 

the electricity system. To that end, they recommended that as 

states are developing state plans, their activity include the 

consideration of the reliability needs of the region in which 

affected EGUs operate and of the potential impact of actions to 

be taken in compliance with state plans. Therefore, we are 

requiring that each state demonstrate in its final state plan 
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submittal that it has considered reliability issues in 

developing its plan. One particularly effective way in which 

states can make this demonstration is by consulting with the 

relevant ISOs/RTOs or other planning authorities as they develop 

their plans and documenting this consultation process in their 

state plan submissions. If a state chooses to consider 

reliability through consultation with the ISO/RTO or other 

planning authority, the EPA recommends that the state request 

that the planning authority review the state plan at least once 

during the plan development stage and provide its assessment of 

any reliability implications of the plan. Additionally, we 

encourage states that are considering reliability through an 

ISO/RTO or other planning authority consultation process to have 

a continuing dialogue with those entities during development of 

their final state plan. While following the recommendations of 

the planning authority would not be mandatory, the state should 

document its consultation process, any response and 

recommendations from the planning authority, and the state’s 

response to those recommendations in its final state plan 

submittal to the EPA. This consultation is designed to inform 

how the state might adjust its plan for meeting the CO2 reduction 

requirements under this guideline; the consultation is not a 

basis for relaxing that requirement. While we consider this 
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process to be an effective way for a state to demonstrate that 

it considered reliability in developing its final state plan, a 

state may provide other comparable support for a demonstration 

that it has considered reliability during the state plan 

development process.1113 Also as discussed elsewhere in this 

preamble, the EPA encourages states to include state utility 

regulators and the state energy offices in the development of 

the state plan. These agencies have expertise that can help to 

assure that state plans complement the state’s power sector. The 

EPA believes that this requirement to demonstrate consideration 

of reliability will provide an effective reliability evaluation 

in the state plan development process. It should further help 

states avoid any conflicts between state plans and the 

maintenance of reliability during implementation of the state 

plan and associated emission standards. Finally, we also 

encourage states as they develop their plans to consider, to the 

extent possible, other potential issues that may impact affected 

EGUs. For example, an affected EGU may be in an ISO/RTO that 

puts certain deadlines on generators that may not line up 

perfectly with state plan deadlines. 

 

1113 While the EPA is requiring that the states demonstrate that 

they have considered reliability in developing their plans, 

state plan submissions will not be evaluated substantively 

regarding reliability impacts. 
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d. State plan modifications. If, during the implementation of a 

state plan, a reliability issue cannot be addressed within the 

range of actions or mechanisms encompassed in an approved state 

plan, the state can submit a plan revision to the EPA to amend 

its plan. In such a circumstance, the state plan may need to be 

adjusted to enable affected EGUs to continue to meet final rule 

requirements without causing an otherwise unmanageable 

reliability threat. In all cases the plan revision must still 

ensure the affected EGUs meet the emission performance level set 

out in the 111(d) final rule. Whether or not these circumstances 

occur will depend in part upon how each state designs its state 

plan. States that design plans with a high level of flexibility, 

such as market-based plans or multi-state plans, are less likely 

to face a potential conflict between state plan requirements and 

the maintenance of reliability. States that participate in 

multi-state programs will be better able to weather unexpected 

reliability risks. 

Events not anticipated at the time of the final plan 

submittal - such as the retirement of a large low- or zeroemitting unit - may trigger the request for state plan 

revisions. It may also be the case that affected EGU-specific 

emission standards in a state plan are proving to be too 

inflexible to allow the plan to accommodate market or other 
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changes in the power sector. In such instances, there should be 

a lead time between the announced retirement of the unit and the 

need to amend the state plan. Therefore, the state should be 

able to utilize the revisions process that the EPA provides. 

The EPA will review a plan revision per the implementing 

regulation requirements of 40 CFR part 60.28. If the state’s 

request for a state plan revision must be addressed in an 

expedited manner to assure a reliable supply of electricity, the 

state must document the risks to reliability that would be 

addressed by the plan revision by providing the EPA with a 

separate analysis of the reliability risk from the ISO/RTO or 

other planning authority. This analysis should be accompanied by 

a statement from the ISO/RTO or other planning/reliability 

authority that there are no practicable alternative resolutions 

to the reliability risk. In this case, the EPA will conduct an 

expedited review of the state plan revision.1114 

e. Reliability safety valve. In this section we describe a 

reliability safety valve, available to states with affected EGUs 

providing reliability-critical generation in emergency 

circumstances. Specifically and as discussed below the 

 

1114 The EPA will still undertake notice and comment rulemaking 

per the requirements of the Administrative Procedures Act when 

acting on such state plan revision, but intends to prioritize 

review of plan revisions needed to address reliability concerns. 
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reliability safety valve provides i) a 90-day period during 

which the affected EGU will not be required to meet the emission 

standard established for it under the state plan but rather will 

meet an alternative standard, and ii) a period beginning after 

the initial 90 days during which the reliability-critical 

affected EGU may be required to continue to operate under an 

alternative standard rather than under the original state plan 

emission standard, as needed in light of the emergency 

circumstances, and the state must during this period revise its 

plan to accommodate changes needed to respond to ongoing 

reliability requirements. Any emissions in excess of the 

applicable state goals or performance rates occurring after the 

initial 90-day period must be accounted for and offset. 

Many commenters expressed concerns that a serious, 

unforeseen event could occur during the final rule 

implementation period that would require immediate reliabilitycritical responses by system operators and affected EGUs that 

would result in unplanned or unauthorized emissions increases. 

After reviewing the comments, we believe that it is highly 

unlikely that there would be a conflict between activities 

undertaken under an approved state plan and the maintenance of 

electric reliability, except in the case of a state plan that 

puts relatively inflexible requirements on specific EGUs. While 
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some have pointed out that severe weather or other short-term 

events could potentially conflict with state plans, we note that 

most of those events are of short duration and would not require 

major – if any - adjustments to emission standards for affected 

EGUs or to state plans. For example, during an event like the 

extreme cold experienced in periods of the winter of 2013-2014, 

affected EGUs may need to run at a higher level for a short 

period of time to accommodate increased demand and/or short-term 

unavailability of other generators. However, because compliance 

by affected EGUs will be demonstrated over 2-3 years, such a 

short-term event would not cause affected EGUs to be out of 

compliance with their applicable emission standards. States can 

also ensure that this is true by developing plans that allow 

adequate compliance flexibility to accommodate such short-term 

events. We note that we have included in this final rule a 

number of different features designed to facilitate emissions 

trading between and among EGUs on an interstate basis – and have 

done so, in no small part, in response to comments from states 

and stakeholders seeking to put in place or operate under statelevel and interstate emissions trading regimes. Affected EGUs 

operating in those circumstances and operating, in addition, 

subject to state plans that incorporate flexible glide paths and 

trading would be able to accommodate an unanticipated 
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reliability event. 

We recognize, however, that affected EGUs operating in a 

state with a relatively inflexible state plan could face 

unanticipated system emergencies that could cause a severe 

stress on the electricity system for a length of time such that 

the requirements in that state’s plan may not be achievable by 

certain affected EGUs without posing an otherwise unmanageable 

risk to reliability. In particular, there could be extremely 

serious events, outside the control of affected EGUs, that would 

require an affected EGU or EGUs operating under an inflexible 

state plan to temporarily operate under modified emission 

standards to respond to this kind of reliability concern. 

Examples of such an event could include, a catastrophic event 

that damages critical or vulnerable equipment necessary for 

reliable grid operation; a major storm that floods and causes 

severe damage to a large NGCC plant so that it must shut down; 

or a nuclear unit that must cease generating unexpectedly and 

therefore other affected EGUs need to run so as to exceed their 

requirements under the approved state plan. This is not an allinclusive list, but the examples illustrate several key 

attributes of the kinds of circumstances in which the 

reliability safety valve would apply. First, the event creating 

the reliability emergency would be unforeseeable, brought about 
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by an extraordinary, unanticipated, potentially catastrophic 

event. Second, the relief provided would be for EGUs compelled 

to operate for purposes of providing generation without which 

the affected electricity grid would face some form of failure. 

Third, the EGU or EGUs in question would be subject to the 

requirements of a state plan that imposes emissions constraints 

such that the EGU or EGUs’ operation in response to the 

reliability emergency resulted in levels of emissions that 

violated those constraints. We do not anticipate that EGUs 

operating under a plan that permitted emissions trading would 

meet these criteria. 

The final guidelines provide a reliability safety valve for 

these types of situations. If an emergency situation arises, the 

state must submit an initial notification to the appropriate EPA 

regional office within 48 hours that it is necessary to modify 

the emission standards for a reliability-critical affected EGU 

or EGUs for up to an initial 90 days. The notification must 

include a full description, to the extent it is known at the 

time, of the emergency situation that is being addressed. It 

must also identify with particularity the affected EGU or EGUs 

that are required to run to assure reliability. It must also 

specify the modified emission standards at which the affected 

EGU or EGUs will operate. The EPA will consider this 
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notification to be an approved short–term modification to the 

state plan, allowing the EGU to operate at an emission standard 

that is an alternative to the emission standard originally 

specified in the relevant state plan, subject to confirmation by 

the further documentation described below.1115 

Within 7 days of submitting the initial notification, the 

state must submit a second notification providing documentation 

to the appropriate EPA regional office that includes a full 

description of the reliability concern and why an unforeseen, 

emergency situation that threatens reliability requires the 

affected EGU or EGUs to operate under modified emission 

standards (including discussion of why the flexibilities 

provided under the state’s plan are insufficient to address the 

concern). The state must also describe in its documentation how 

it is coordinating or will coordinate with relevant reliability 

coordinators and planning authorities to alleviate the problem 

in an expedited manner, and indicate the maximum time that the 

state anticipates the affected EGU or EGUs will need to operate 

in a manner inconsistent with its or their obligations under the 

 

1115 The EPA reserves the right to review such notification, and 

in the event that the EPA finds such notification is improper, 

the EPA may disallow the short-term modification and affected 

EGUs must continue to operate under the original approved state 

plan emission standards. 
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state’s approved plan, and the modified emission standards or 

levels at which the affected EGU or EGUs will be operating at 

during this period if it has changed from the initial 

notification. The documentation must also include a written 

concurrence from the relevant reliability coordinator and/or 

planning authority confirming the existence of the imminent 

reliability threat and supporting the temporary modification 

request or an explanation of why this kind of concurrence cannot 

be provided. Additionally, if the relevant planning authority 

has conducted a system-wide or other analysis of the reliability 

concern, the state must include that information in its request. 

If the state fails to submit this documentation on a timely 

basis, the EPA will notify the state, which must then notify the 

affected EGU(s) that they must operate or resume operations 

under the original approved state plan emission standards. 

It is important to note that the affected EGUs must 

continue to monitor and report their emissions and generation 

pursuant to requirements in this final rule and under the state 

plan during any short-term modification. For the duration of the 

up to 90 day short-term modification, the emissions of the 

affected EGU or EGUs that exceed their obligations under the 

approved state plan will not be counted against the state’s 

overall goal or emission performance rate for affected EGUs. 
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Such a modification will not alter or abrogate any other 

obligations under the approved state plan. 

During this short term modification period, the EPA expects 

that the source, the state and the relevant reliability 

coordinator and/or planning authority will assess whether the 

reliability issue can be addressed in a way that would allow the 

EGU or EGUs to resume operating under the original approved 

state plan within the 90 day period or whether revisions to the 

state plan need to be made to address the unexpected 

circumstances for the longer term (the unexpected unavailability 

of a nuclear unit, for example). 

The EPA recognizes that an emergency may persist past 90 

days. At least 7 days before the end of the initial 90 day 

reliability safety valve period, the state must notify the 

appropriate EPA regional office whether the reliability concern 

has been addressed and that the EGU or EGUs can resume meeting 

the original emission standards established in the state plan 

prior to the short-term modification. 

If there still is a serious, ongoing reliability issue at 

the end of the short-term modification period that necessitates 

the EGU or EGUs to emit beyond the amount allowed under the 

state plan, the state must provide to the EPA a notification 

that it will be submitting a state plan revision and submit the 
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plan revision as expeditiously as possible, specifying in the 

notice the date by which the revision will be submitted. The 

state must document the ongoing emergency with a second written 

concurrence from the relevant reliability coordinator and/or 

planning authority confirming the continuing urgent need for the 

EGU or EGUs to operate beyond the requirements of the state plan 

and that there is no other reasonable way of addressing the 

ongoing reliability emergency but for the EGU or EGUs to operate 

under an alternative emission standard than originally approved 

under the state plan. In this event, the EPA will work with the 

state on a case-by-case basis to identify an emission standard 

for the affected EGU or EGUs for the period before a new state 

plan revision is approved. After the initial 90 day period, any 

excess emissions beyond what is authorized in the original 

approved state plan will count against the state’s overall goal 

or emission performance rate for affected EGUs. 

The EPA intends for this reliability safety valve to be 

used only in exceptional situations. In addition, this 

reliability safety valve applies only to this final rule and has 

no effect on CAA requirements to which the state or the affected 

EGUs are otherwise subject. As discussed earlier, we are 

providing states with the flexibility to design programs that 

incorporate the level of flexibility that allow affected EGUs to 
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meet compliance obligations while responding to reliability 

needs, even in emergency situations. This flexibility means that 

a conflict between the requirements of the state plan and 

maintenance of reliability should be extremely rare. We 

recognize, however, that a state with an inflexible plan could 

be faced with more than one emergency and in this case the 

reliability safety valve may be used more than once. If the 

state finds that a second reliability emergency arises that 

conflicts with the state plan, the state must submit a revision 

to its state plan so that the state plan is flexible enough to 

assure that such conflicts do not recur and that the state is 

providing for the implementation of the standards of performance 

for affected EGUs as required by the CAA. 

f. Coordination among federal partners. The EPA, DOE, and FERC 

have agreed to coordinate efforts to help ensure continued 

reliable electricity generation and transmission during the 

implementation of the final rule. The three agencies have 

developed a coordination strategy that reflects their joint 

understanding of how they will work together to monitor final 

rule implementation, share information, and resolve any 

difficulties that may be encountered. This strategy is based on 

the successful working relationship that the three agencies 

established in their joint effort to work together to monitor 
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reliability during MATS implementation. 

g. Analyses of the reliability impacts of the proposal. The EPA 

appreciates that a large number of entities from many different 

industry perspectives have published reports and analysis with 

respect to electric reliability and the 111(d) proposed rule. We 

take concerns about reliability very seriously, and we 

appreciate the attention given to this issue in the comments and 

shared with us in public forums. It is important to note that 

these studies were conducted prior to promulgation of this final 

rule, and thus were only able to consider electric reliability 

with respect to the proposal. The EPA has made changes and 

improvements to the proposal in response to comments and new 

information, and some of the changes are relevant to the final 

rule’s potential effect on electric reliability. One notable 

change pertains to the start of the interim period, which is now 

2022 rather than 2020. Another important change to the final 

rule is a more gradual phase-in of the BSER for affected EGUs 

over the interim period (from 2022 through 2029). The final rule 

also provides considerable flexibility and multiple pathways to 

states, including allowing their EGUs to use multi-state trading 

and other approaches, which would allow essential units to 

continue to meet their compliance obligation while generating 

even at unplanned but reliability-critical levels. In addition, 
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we have included in the final rule a reliability safety valve 

provision that can be utilized in certain emergency situations. 

These changes, in addition to already existing industry 

mechanisms and planning requirements, will help to ensure that 

industry will be able to maintain electric reliability. The EPA 

is confident that the final rule will cut harmful electric power 

plant pollution while maintaining a reliable electric grid 

because the final rule provides industry with the time and 

flexibility needed to continue its current and ongoing planning 

and investing to modernize and upgrade the electric power 

system. 

 In June of 2015, M.J. Bradley & Associates issued a report 

that enumerated a set of useful guiding principles for studying 

and evaluating the reliability impacts of the final rule.1116 The 

report enumerated six principles: (1) a study should be 

transparent about the assumptions and data used; (2) a study 

should accurately reflect the existing status of the grid in its 

modeling assumptions; (3) a study should clearly identify the 

base case and not confuse what will happen as a result of the 

final rule with what would have happened anyway; (4) where 

 

1116 M.J. Bradley & Associates, Guiding Principles for Reliability 

Assessments Under EPA’s Clean Power Plan (June 3, 2015), 

available at http://www.mjbradley.com/node/295. 
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possible, a study should contain sensitivities and probabilities 

as they are looking into the future which is necessarily 

uncertain; (5) a study should reflect the flexibility provided 

to states to allow them to design compliance approaches to 

maximize reliability; and (6) a study should provide realistic 

and reliability-focused results. These principles are helpful to 

keep in mind when reviewing recent studies. 

 NERC published its analyses of the proposed rule in 

November 2014 and again in April 2015.1117 The EPA appreciates 

NERC’s attention to, and interest in, the proposed rule. 

However, we note that like some other studies, NERC assumes 

considerably less flexibility than actually is provided to 

states and EGUs in this final rule. The final rule provides 

states with considerable time and latitude in designing plans 

that are tailored to the system in which their EGUs operate, 

which should be reflected in any reliability analysis. Also, the 

 

1117 North American Electric Reliability Corporation, Potential 

Reliability Impacts of EPA’s Proposed Clean Power Plan (Nov. 5, 

2014), available at http://www.nerc.com/news/Pages/ReliabilityReview-of-Proposed-Clean-Power-Plan-Identifies-Areas-forFurther-Study,-Makes-Recommendations-for-Stakeholders.aspx; 

North American Electric Reliability Corporation, Potential 

Reliability Impact of EPA’s Proposed Clean Power Plan: Phase 1

(Apr. 21, 2015), available at

http://www.nerc.com/news/Pages/Assessment-Uses-ScenarioAnalysis-to-Identify-Potential-Reliability-Risks-from-ProposedClean-Power-Plan.aspx. 
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NERC study does not fully reflect the current electric grid. For 

example, the amount of RE generation that NERC assumes for 2020 

is similar to levels of generation that we see today whereas 

projections for 2020 are considerably higher.1118 Further, NERC 

conflates retirements that may happen as a result of the rule 

with those that are already planned. The Brattle Group has also 

reviewed NERC’s November 2014 initial analysis of the proposed 

rule, noting that it is important to distinguish between 

concerns about the building blocks and reliability concerns 

about compliance with state plans.1119 The Brattle Group concluded 

that there are real world solutions to NERC’s concerns. These 

include making use of the many flexible options available to 

states under the rule to mitigate reliability risks. 

 Multiple ISOs/RTOs also provided analyses of the proposed 

rule, including MISO, PJM, ERCOT, and SPP.1120 For example, MISO 

 

1118 EIA, Annual Energy Outlook 2015, PRIL 2015. 1119 Brattle Group, EPA’s Clean Power Plan and Reliability, 

Assessing NERC’s Initial Reliability Review (Feb. 2015), 

available at http://info.aee.net/hs-fs/hub/211732/file2486162659-pdf/PDF/EPAs-Clean-Power-Plan--ReliabilityBrattle.pdf?t=1434398407867. 

1120 See MISO, Analysis of EPA’s Proposal to Reduce CO2 Emissions 

from Existing Units (Nov. 12, 2014), available at

https://www.misoenergy.org/Library/Repository/Communication%20Ma

terial/EPA%20Regulations/AnalysisofEPAProposalReduceCO2Emissions

.pdf; PJM, PJM Interconnection Economic Analysis of the EPA 

Clean Power Plan Proposal (Mar. 2, 2015), report listed at

http://www.pjm.com/documents/reports.aspx; SPP, SPP’s 
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conducted an analysis of coal units at risk for retirement, 

finding that 14 GW of coal may be at risk.1121 SPP performed a 

resource adequacy analysis that assumes planned retirements plus 

the EPA’s projected retirements, but did not similarly account 

for the building of new generation capacity.1122 While we 

appreciate MISO’s and SPP’s concerns regarding retirements and 

the potential that reserves will fall below reserve requirement 

levels, it is important to consider the many ways in which 

states can develop plans that account for their potential 

reliability concerns. The final rule continues to give states 

significant flexibility in how they comply with requirements, 

including both BSER measures and measures that were not included 

in the determination of the BSER as a means to comply. For 

 

Reliability Impact Assessment of the EPA’s Proposed Clean Power 

Plan, (Oct. 8, 2014), available at

http://www.spp.org/publications/CPP%20Reliability%20Analysis%20R

esults%20Final%20Version.pdf; ERCOT, ERCOT Analysis of the Clean 

Power Plan (Nov. 17, 2014), available at

http://www.ercot.com/content/news/presentations/2014/ERCOTAnalys

is-ImpactsCleanPowerPlan.pdf; and 

1121 MISO, Analysis of EPA’s Proposal to Reduce CO2 Emissions from 

Existing Units, at 14 (Nov. 12, 2014), available at

https://www.misoenergy.org/Library/Repository/Communication%20Ma

terial/EPA%20Regulations/AnalysisofEPAProposalReduceCO2Emissions

.pdf.

1122 SPP, SPP’s Reliability Impact Assessment of the EPA’s 

Proposed Clean Power Plan, (Oct. 8, 2014), available at

http://www.spp.org/publications/CPP%20Reliability%20Analysis%20R

esults%20Final%20Version.pdf. 
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example, demand-side EE measures can greatly assist states and 

affected EGUs in meeting the standards and/or state plan. Many 

studies assume that state plans will simply apply the BSER and 

do not recognize the large number of compliance approaches and 

opportunities that states and affected EGUs have available to 

them. The Analysis Group recently analyzed reliability 

considerations in MISO as the region considers how to comply 

with the final rule.1123 The Analysis Group found that despite the 

large amount of coal-fired generating capacity that will likely 

be retired in MISO in the coming years, the entities responsible 

for electric system reliability in MISO are prepared to 

collaboratively address any reliability issues that arise and 

that there is a “strong tool kit for managing ‘Essential 

Reliability Services’ needed to assure high-quality electric 

service.”1124 

ERCOT also performed an analysis, modeling numerous 

 

1123 Analysis Group, Electric System Reliability and EPA’s Clean 

Power Plan: The Case of MISO (June 8, 2015), available at

http://www.analysisgroup.com/uploadedfiles/content/insights/publ

ishing/analysis_group_clean_power_plan_miso_reliability.pdf. 

1124 Analysis Group, Electric System Reliability and EPA’s Clean 

Power Plan: The Case of MISO, at 2 (June 8, 2015), available at

http://www.analysisgroup.com/uploadedfiles/content/insights/publ

ishing/analysis_group_clean_power_plan_miso_reliability.pdf. 
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scenarios.1125 ERCOT stated that its modeling identified two 

potential reliability problems – impacts of units retiring and 

increased levels of renewable generation on the ERCOT grid.1126 As 

noted above, the final rule gives additional time for 

compliance, providing needed time to obtain new or replacement 

generation necessary as some existing generators retire. 

Moreover, affected EGUs needed for reliability should be able to 

employ the flexibilities afforded to them as they seek lower and 

zero-emitting generation. Finally, we note that ERCOT has a 

history of notable success in integrating RE into its electric 

grid, giving ERCOT significant expertise regarding challenges 

that may arise with the addition of new RE in order to comply 

with the final rule. In fact, a recent Brattle Group report used 

ERCOT as a case study for how to effectively integrate a large 

number of RE into the electric grid.1127 

 

1125 ERCOT, ERCOT Analysis of the Clean Power Plan (Nov. 17, 

2014), available at

http://www.ercot.com/content/news/presentations/2014/ERCOTAnalys

is-ImpactsCleanPowerPlan.pdf. 

1126 ERCOT, ERCOT Analysis of the Clean Power Plan, at 9 (Nov. 17, 

2014), available at

http://www.ercot.com/content/news/presentations/2014/ERCOTAnalys

is-ImpactsCleanPowerPlan.pdf.

1127 Brattle Group, Integrating Renewable Energy Into the 

Electricity Grid: Case Studies Showing How System Operators are 

Maintaining Reliability (June 2015), available at

http://info.aee.net/integrating-renewable-energy-into-theelectricity-grid. 
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 PJM conducted its own analysis at the request of the 

Organization of PJM States (OPSI).1128 This analysis is consistent 

with many of the M.J. Bradley guiding principles. PJM designed 

various scenarios to capture the impact of the proposed rule 

under a series of assumptions. Because the EPA had not yet 

issued the final rule, PJM cautioned against using the report as 

a reliability analysis or predictor of the future. PJM stated 

that, since 2007, PJM’s capacity markets have helped to attract 

35,000 MWs of additional generation. Even though 26,000 MWs will 

retire between 2009 and 2016, the PJM capacity market has 

procured sufficient resources to maintain reliability. 

 WECC also produced a study which is part of a longer-term, 

phased effort.1129 The assumptions, methodology, and limitations 

were all clearly presented, and there was extensive involvement 

by a range of stakeholders. WECC stated that it is embarking on 

a phased-study process that seeks to “provide the industry with 

 

1128 PJM, PJM Interconnection Economic Analysis of the EPA Clean 

Power Plan Proposal (Mar. 2, 2015), report listed at

http://www.pjm.com/documents/reports.aspx. 

1129 WECC, EPA Clean Power Plan: Phase I – Preliminary Technical 

Report (Sept. 19, 2014), available at

https://www.wecc.biz/_layouts/15/WopiFrame.aspx?sourcedoc=/Relia

bility/140912_EPA-111(d)_PhaseI_TechFinal.pdf&action=default&DefaultItemOpen=1. 
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unbiased and independent analysis of this issue.”1130 WECC 

concluded that the effects of the proposal on resource adequacy 

may be minimal but that resource adequacy cannot be fully 

assessed without realistic and/or proposed compliance 

scenarios.1131 

 Analysis Group analyzed the proposed rule, finding that it 

provides states and affected EGUs with a wide range of options 

and operational discretion that can prevent reliability issues 

while also reducing carbon pollution and costs.1132 Analysis Group 

noted that some of the concerns raised by stakeholders about the 

proposed rule assume “inflexible implementation, are based upon 

worst-case scenarios, and assume that policy makers, regulators, 

and market participants will stand on the sidelines until it is 

 

1130 WECC, EPA Clean Power Plan: Phase I – Preliminary Technical 

Report, at 1 (Sept. 19, 2014), available at

https://www.wecc.biz/_layouts/15/WopiFrame.aspx?sourcedoc=/Relia

bility/140912_EPA-111(d)_PhaseI_TechFinal.pdf&action=default&DefaultItemOpen=1. 

1131 WECC, EPA Clean Power Plan: Phase I – Preliminary Technical 

Report, at 30 (Sept. 19, 2014), available at

https://www.wecc.biz/_layouts/15/WopiFrame.aspx?sourcedoc=/Relia

bility/140912_EPA-111(d)_PhaseI_TechFinal.pdf&action=default&DefaultItemOpen=1. 

1132 Analysis Group, Electric System Reliability and EPA’s Clean 

Power Plan Tools and Practices (Feb. 2015), available at

http://www.analysisgroup.com/uploadedfiles/content/insights/publ

ishing/electric_system_reliability_and_epas_clean_power_plan_too

ls_and_practices.pdf. 
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far too late to act” to ensure reliability.1133 It stated that 

these assumptions are not consistent with past actions. 

 We appreciate the time that multiple entities took to 

analyze and consider the potential impacts of the proposed rule. 

As we issue the final rule and states draft plans to implement 

the rule, we look forward to further analysis by these and other 

groups. Such analysis can provide states with needed resources 

to help them design state plans that will augment the efforts of 

the industry to maintain electric reliability. 

3. Consideration of effects on employment and economic 

development 

States in designing their state plans should consider the 

effects of their plans on employment and overall economic 

development to assure that the opportunities for economic growth 

and jobs that the plans offer are manifest. To the extent 

possible, states should try to assure that any communities that 

can be expected to experience job losses can also take advantage 

of the opportunities for job growth or otherwise transition to 

healthy, sustainable economic growth. The EPA’s illustrative 

 

1133 Analysis Group, Electric System Reliability and EPA’s Clean 

Power Plan Tools and Practices, at ES-3 (Feb. 2015), available 

at

http://www.analysisgroup.com/uploadedfiles/content/insights/publ

ishing/electric_system_reliability_and_epas_clean_power_plan_too

ls_and_practices.pdf.
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analysis indicates that there may be some additional job losses 

in sectors related to coal extraction and generation that are 

attributable to implementation of this rule. At the same time, 

the EPA’s illustrative analysis indicates that there may be new 

jobs in the utility power sector associated with both improving 

the efficiency of fossil fuel-fired power plants, construction 

and operation of new natural gas-fired and RE production, and 

actions to increase demand-side EE. Consideration of these 

effects in the context of the particulars of the state plan can 

help states craft plans that, to the extent possible, meet 

multiple environmental, economic, and workforce development 

goals. 

The Partnerships for Opportunity and Workforce and 

Economic Revitalization (POWER) Initiative is a new interagency 

effort led by the Economic Development Administration in the 

Department of Commerce. POWER was launched to respond to current 

trends in the power sector: “The United States is undergoing a 

rapid energy transformation, particularly in the power sector. 

This transformation is producing cleaner air and healthier 

communities, and spurring new jobs and industries. At the same 

time, it is impacting workers and communities who have relied on 

the coal industry as a source of good jobs and economic 

prosperity, particularly in Appalachia, where competition with 
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other coal basins provides additional pressure.” 1134 The POWER 

Initiative aligns, leverages, and targets economic and workforce 

development assistance to communities and workers affected by 

changes in the coal industry and the utility power sector. The 

POWER Initiative is competitively awarding planning assistance 

and implementation grants with funding from the Department of 

Commerce, Department of Labor, Small Business Administration, 

and the Appalachian Regional Commission to partnerships anchored 

in impacted communities. These grants will help communities 

organize themselves, develop comprehensive strategic plans that 

chart their economic future, and execute coordinated economic 

and workforce development activities based on their strategic 

plans.1135 

In addition to POWER, however, the EPA encourages states to 

use economic and labor market analysis to identify where they 

can deploy strategies to: 1) provide a range of employment and 

training assistance to workers, and economic development 

assistance to communities affected by the rapid changes underway 

in the power sector and closely related industries, to diversify 

their economies, attract new sources of investment, and create 

 

1134 http://www.eda.gov/power/. 1135 https://www.whitehouse.gov/the-press-office/2015/03/27/factsheet-partnerships-opportunity-and-workforce-and-economicrevitaliz. 
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new jobs; and 2) mobilize existing education and training 

resources, including those of community and technical colleges 

and registered apprenticeship programs, to ensure that both 

incumbent and new workers are trained for the skills necessary 

to meet employer demand for new workers in the utility, 

construction and related sectors, that such training includes 

career pathways for members of low-income communities and other 

vulnerable communities to attain employment in these sectors, 

and that such training results in validated skill certifications 

for workers. 

4. Workforce considerations 

Some stakeholders commented that, to ensure that emission 

reductions are realized, it is important that construction, 

operations and other skilled work undertaken pursuant to state 

plans is performed to specifications, and is effective, safe, 

and timely. A good way to ensure a highly proficient workforce 

is to require that workers have been certified by: 1) an 

apprenticeship program that is registered with the U.S. DOL, 

Office of Apprenticeship or a state apprenticeship program 

approved by the DOL; 2) a skill certification aligned with the 

U.S. DOE Better Building Workforce Guidelines and validated by a 

third party accrediting body recognized by DOE; or 3) other 

skill certification validated by a third party accrediting 
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body. 

5. Tenth Amendment legal considerations 

Some commenters have raised concerns that the emission 

guidelines and requirements for 111(d) state plans violate 

principles of federalism embodied in the U.S. Constitution, 

particularly the Tenth Amendment. These commenters claim that 

states will be unconstitutionally “coerced” or “commandeered” 

into taking certain actions in order to avoid the prospect of 

either a federal 111(d) plan applying to sources in the state, 

or of losing federal funds. 

 We disagree on both fronts. First, the prospect of a 

federal plan applying to sources in a state does not “coerce” or 

“commandeer” that state into submitting its own satisfactory 

plan. Far from violating principles of federalism, this rule 

provides states with the initial opportunity to submit a 

satisfactory state plan, and provides states flexibility in 

developing that plan. If a state declines to take advantage of 

that opportunity, affected EGUs in that state will instead be 

subject to a federal plan that satisfies statutory 

requirements.1136 This approach is consistent with ordinary 

 

1136 Among other things, a federal plan will implement standards 

of performance subject to specific statutory requirements. See 

42 U.S.C. § 7411(a)(1). The APA and CAA would prohibit the 
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cooperative federalism regimes that federal courts have 

routinely upheld against Tenth Amendment challenges.1137 

 Second, states that decline to take certain actions under 

this rule will not face the prospect of sanctions, such as 

withdrawn federal highway funds. CAA section 111 does not 

contain sanctions provisions, and we are finalizing revisions to 

these emission guidelines making explicit that the EPA will not 

withhold federal funds from a state on account of that state’s 

failure to submit or implement an approvable 111(d) state plan. 

Some commenters pointed to section 110(m) as a possible 

source of the EPA’s sanction authority.1138 Section 110(m) grants 

the EPA discretionary authority to withhold some federal highway 

 

imposition of any federal plan that is “arbitrary, capricious, 

an abuse of discretion, or otherwise not in accordance with 

law.” 5 U.S.C. § 706(2)(a). Particularly given these independent 

constraints on the EPA’s authority with respect to any potential 

federal plan, the prospect of any such plan would not commandeer 

states or coerce them into submitting their own state plans. 

1137 See, e.g., Hodel v. Va. Surface Mining & Reclamation Ass’n, 

Inc., 452 U.S. 264, 283–93 (1981); Texas v. EPA, 726 F.3d 180, 

196–97 (D.C. Cir. 2013) (noting that “Supreme Court precedent 

repeatedly affirm[s] the constitutionality of federal statutes 

that allow States to administer federal programs but provide for 

direct federal administration if a State chooses not to 

administer it”). 

1138 Other commenters point to CAA section 179 as a possible 

direct source of this sanctions authority. However, the 

mandatory sanctions outlined in section 179 clearly apply only 

in the contextcontexts of nonattainment SIPs. and responses to 

SIP Calls made under CAA section 110(k)(5). See 42 U.S.C. 

§ 7509(a). 
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funds under certain conditions. However, section 110(m) requires 

the EPA to adopt regulations to “establish criteria for 

exercising” this discretionary authority, and the only EPA 

regulations implementing section 110(m) apply to SIPs submitted 

under section 110.1139

The EPA never intended to even imply that we would 

contemplate using this authority to encourage state 

participation in this rule under section 111. To the contrary, 

we believe that imposition of a federal plan rather than 

sanctions is the appropriate path in the context of this 

program. Accordingly, regardless of whether the EPA could 

theoretically apply discretionary sanctions against states in 

the section 111(d) context, the final rule forbids the agency 

from exercising any such authority. We have included in this 

rule a provision that prohibits the agency from imposing 

sanctions in the event that a state fails to submit or implement 

a satisfactory plan under this rule. As states consider whether 

to take advantage of the opportunity to develop state plans, 

they can be assured that the EPA will not withdraw federal 

funding should they decline to participate. 

6. Title VI 

 

1139 40 CFR 52.30 (defining “plan or plan item”). 
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 States that are recipients of EPA financial assistance must 

comply with all federal nondiscrimination statutes that together 

prohibit discrimination on the bases of race, color, national 

origin (including limited-English proficiency), disability, sex 

and age. These laws include: Title VI of the Civil Rights Act of 

1964; Section 504 of the Rehabilitation Act of 1973; Section 13 

of the Federal Water Pollution Control Act Amendments of 1972; 

Title IX of the Education Act Amendments of 1972; and the Age 

Discrimination Act of 1975. Compliance with these 

nondiscrimination statutes is a recipient’s separate and 

distinct obligation from compliance with environmental 

regulations. In other words, all recipients are required to 

ensure that all aspects of their state plans do not violate any 

of the federal nondiscrimination statutes, including Title VI. 

The EPA’s Office of Civil Rights (OCR) is responsible for 

carrying out compliance with these federal nondiscrimination 

statutes and does so through a variety of means including: 

complaint investigation; agency-initiated compliance reviews; 

pre-grant award assurances and audits; and technical assistance 

and outreach activities. Anyone who believes that any of the 

federal nondiscrimination laws enforced by OCR have been 

violated by a recipient of EPA financial assistance may file an 

administrative complaint with the EPA’s OCR. 
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H. Resources for States to Consider in Developing Plans 

 As part of the stakeholder outreach and comment processes, 

the EPA asked states what the agency could do to facilitate 

state plan development and implementation. In addition, after 

the comment period closed, the EPA continued to consult with 

state organizations including the Association of Air Pollution 

Control Agencies (AAPCA), Environmental Council of the States 

(ECOS), National Association of Clean Air Agencies (NACAA), 

National Association of Regulatory Utility Commissioners 

(NARUC), National Association of State Energy Officials (NASEO) 

and the National Governors Association (NGA). 

Some states indicated that they wanted the EPA to create 

resources to assist with state plan development, especially 

resources related to accounting for RE and demand-side EE in 

state plans. They requested clear methodologies for estimating 

emission reductions from RE and demand-side EE policies and 

programs so that these could be included as part of their 

compliance strategies. Stakeholders said that these tools and 

metrics should build upon the EPA’s “Roadmap for Incorporating 

Energy Efficiency/Renewable Energy Policies and Programs into 

State and Tribal Implementation Plans,” as well as the State 

Energy Efficiency Action Network’s “Energy Efficiency Program 

Impact Evaluation Guide.” In addition, stakeholders requested 
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clear guidance on how to measure the impacts of RE and demandside EE programs using established EM&V protocols. 

The EPA also heard that states would like guidance on plan 

development to be released at the same time as this final rule. 

This guidance should include allowable programs and policies for 

compliance, examples of compliance pathways, clear information 

on multi-state plan development, and identification of tools. 

As a result of this feedback, in consultation with U.S. DOE 

and other federal agencies, the EPA continued to refine its 

toolbox of decision support resources at: http://www2.epa.gov/ 

www2.epa.gov/cleanpowerplantoolbox. The site includes 

information on regulatory requirements, including state plan 

guidance and state plan decision support. The state plan 

guidance section serves as a central repository for the final 

emission guidelines, RIA, guidance documents, TSDs and other 

supporting materials. The state plan decision support section 

includes information to help states evaluate different 

approaches and measures they might consider as they initiate 

plan development. This section includes, for example, a summary 

of existing state climate and RE and demand-side EE policies and 

programs, information on electric utility actions that reduce 

CO2, and tools and information to estimate the emissions impact 

of RE and demand-side EE programs. 
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The EPA notes that our inclusion of a measure in the 

toolbox does not mean that a state plan must include that 

measure. In fact, inclusion of measures provided at the website 

does not necessarily imply the approvability of an approach or 

method for use in a state plan. States will need to demonstrate 

that any measure included in a state plan meets all relevant 

criteria and adequately addresses elements of the plan 

components discussed in section VIII.D of this preamble. 

G. Considerations for Incorporating CO2 Emission Reduction 

Measures in State Plans 

1. Accounting for emission reduction measures in state plans 

This section describes how measures that reduce CO2

emissions from affected EGUs may be counted in state plans. This 

includes accounting for measures that occur directly at affected 

EGUs, as well as measures that provide substitute generation for 

affected EGUs or avoid the need for generation from affected 

EGUs. This latter category of measures may be used to adjust the 

CO2 emission rate of an affected EGU under a rate-based state 

plan. This adjustment may occur when an affected EGU is 

demonstrating compliance with a rate-based emission standard, or 

when a state is demonstrating achievement of the CO2 emission 

performance rates or applicable state CO2 emission goal in the 
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emission guidelines.1140 

It should be noted that under a mass-based plan, measures 

that provide substitute generation for affected EGUs or avoid 

the need for generation from affected EGUs are automatically 

accounted for to the extent that these measures reduce reported 

CO2 emissions from affected EGUs. Unlike under a rate-based plan, 

no additional accounting is necessary in order to recognize 

these emission reductions. 

Section VIII.G.1.a below addresses how emission reduction 

measures that occur at affected EGUs are counted in state plans. 

This includes measures that result in CO2 emissions reductions 

that are automatically accounted for in reported CO2 emissions 

and CO2 emission rates for affected EGUs, as well as other 

emission reduction measures, in particular the use of CCS, CCU 

and biomass, that require additional accounting and reporting. 

Section VIII.G.1.b below addresses how emission reduction 

measures that provide substitute generation for affected EGUs or 

avoid the need for generation from affected EGUs are counted in 

rate-based state plans. This section describes the basic 

 

1140 Under a state measures plan, as described in section 

VIII.C.4, a state may adjust the reported CO2 emission rate of 

affected EGUs when demonstrating achievement of the CO2 emission 

performance rates or applicable state CO2 emission goal in the 

emission guidelines. 
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accounting method for adjusting a CO2 emission rate. The section 

also describes general eligibility requirements for measures 

that may be used for adjusting a CO2 emission rate, such as the 

requirement that the emissions-reducing action occur after 2012, 

which is necessary to maintain the integrity of the performance 

rates and state emission goals established in the guidelines. In 

addition, this section clarifies the treatment of the following 

measures that may be used to adjust a CO2 emission rate: 

 RE, including electric generating technologies using RE 

resources, such as wind, solar, geothermal, hydropower, 

biomass and wave and tidal power. Additional requirements 

are specified for the following RE resources: 

o hydropower; 

o biomass; and 

o waste-to-energy 

 Demand-side EE 

 Demand-side management (DSM) 

 Transmission and distribution (T&D) measures that 

increase T&D efficiency or reduce electricity end-use 

 Energy storage 

 Water system efficiency 

 CHP 
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 Waste heat to power (WHP) 

 Nuclear power 

Where applicable, this section includes additional eligibility 

requirements and accounting methods that apply to specific 

categories of measures, in order to determine the MWh of 

electricity generation or electricity savings that may be used 

to adjust a CO2 emission rate. 

Section VIII.G.1.c addresses measures that may not be used 

to adjust the CO2 emission rate of an affected EGU in a state 

plan, and explains the basis for this exclusion. This includes 

new, modified, and reconstructed fossil fuel-fired EGUs subject 

to emission standards under CAA section 111(b) and other 

existing and new fossil fuel-fired EGUs that are not subject to 

emission standards under CAA section 111(b). Section VIII.G.1.d 

addresses measures that reduce CO2 emissions outside the electric 

power sector. Such measures may not be counted under either a 

rate-based or mass-based state plan. 

The categories of measures included in sections VIII.G.1.ab represent a wide range of actions that may be taken to reduce 

CO2 emissions at an affected EGU, as well as actions taken in the 

generation, transmission, distribution, and end-use of 

electricity that reduce CO2 emissions from affected EGUs. The EPA 

anticipates that the categories described, including their 
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eligibility requirements and accounting methods, represent the 

broad range of actions that states may seek to include in their 

state plans to meet the emission guidelines. However, it does 

not necessarily represent an exclusive list. A measure that is 

not specifically discussed in this section may be included in a 

state plan, provided the measure meets all requirements 

specified in the emission guidelines. This includes the 

requirements that a measure be quantifiable and verifiable, as 

described in section VIII.D.2.b. 

Affected EGU actions that reduce CO2 emissions. Multiple 

actionsI. Considerations for CO2 Emission Reduction Measures that 

Occur at Affected EGUs 

 This section describes a range of emission reduction 

actions that may be taken at affected EGUs that reduce CO2

emissions from an affected EGU and/or improve its CO2 emission 

rate. This section describes this range of emission reduction 

actions and their, and the accounting treatment for these 

actions in a state plan. Some of these actions do not 

necessitate additional accounting, monitoring or reporting 

requirements. Such actions are discussed in section 

VIII.GI.1.a.(1) below, and include heat rate improvements, fuel 

switching from one fossil fuel to another, integration of RE 

into EGU operations, and CHPcombined heat and power (CHP)
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expansion or retrofit. Other actions, however, do necessitate 

additional accounting, monitoring, or reporting requirements. 

These include use of CCS, CCU and biomass, as discussed in 

section VIII.G.1.a.(I.2) below.

 The discussion in this section applies for both rate-based 

and mass-based plans. Additional accounting considerations for 

mass-based plans are discussed in section VIII.J. Additional 

accounting considerations for rate-based plans, including how 

actions that substitute for generation from affected EGUs or 

avoid the need for generation from affected EGUs may be used in 

a state plan to adjust the CO2 emission rate of an affected EGU, 

are discussed in section VIII.K. 

1. Actions without additional accounting and reporting 

requirements 

 Many actions will reduce the reported CO2 emissions or CO2

emission rate of an affected EGU, without the need for 

additional accounting or monitoring and reporting requirements 

beyond the required CEMS tracking of actual stack CO2 emissions 

and tracking of actual energy output.1141 The effect of these 

actions will result in changes in reported CO2 emissions and/or 

 

1141 Monitoring and reporting requirements for affected EGU CO2 

emissions and useful energy output are addressed in section 

VIII.F.
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energy output by an affected EGU. These actions include: 

 heat rate improvements; 

 fuel switching to a fossil fuel with lower carbon content 

(e.g., from coal to natural gas); 

 integrated RE;1142 and 

 CHP, including retrofit of an affected EGU to a CHP 

configuration, or revising the useful energy outputs 

(electrical and thermal) at an affected EGU already 

operating in a CHP configuration.1143

 Heat rate improvements, fuel switching, integrating RE and 

CHP would not require any additional accounting or monitoring 

and reporting, because under the emission guidelines affected 

EGUs are already required to monitor and report CO2 emissions at 

 

1142 “Integrated RE” refers to RE that is directly incorporated 

into the mechanical systems and operation of the EGU. An example 

is a solar thermal energy system used to preheat boiler 

feedwater. Such approaches reduce the amount of fossil fuel heat 

input per unit of useful energy output. 

1143 The emission reduction potential from CHP stems from the unit 

using less fuel for producing useful electrical and thermal 

outputs than would be required to run separate electrical and 

thermal units. The emission reduction would depend on the type 

of affected EGU and available steam hosts in the vicinity of the 

affected EGU. A conventional combustion turbine generator, for 

example, converted into a CHP unit could effectively result in a 

reduction of 25 percent or more in the reported CO2 emission 

rate. The potential retrofitted EGU CHP market consists of 

converted simple cycle turbines, older steam plants in urban 

areas, and combined cycle units near beneficial thermal loads. 
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the stack level, and to monitor and report useful energy 

outputs. Stack monitoring would reflect reductions in CO2

emissions from efficiency improvements, changes in fuel use 

(including incorporation of RE), and other on-site changes. (1) 

Actions without additional accounting and reporting 

requirements. Many actions will reduce the reported CO2 emissions 

or CO2 emission rate of an affected EGU, without the need for 

additional accounting or monitoring and reporting requirements 

beyond the required CEMS tracking of actual stack CO2 emissions 

and tracking of actual energy output.1144 The effect of these 

actions will result in changes in reported CO2 emissions and/or 

energy output by an affected EGU. These actions include: 

 heat rate improvements; 

 fuel switching to a fossil fuel with lower carbon content 

(e.g., from coal to natural gas); 

 integrated RE;1145 and 

 CHP, including retrofit of an affected EGU to a CHP 

 

1144 Monitoring and reporting requirements for affected EGU CO2 

emissions and useful energy output are addressed in section 

VIII.F.

1145 “Integrated RE” refers to RE that is directly incorporated 

into the mechanical systems and operation of the EGU. An example 

is a solar thermal energy system used to preheat boiler 

feedwater. Such approaches reduce the amount of fossil fuel heat 

input per unit of useful energy output. 
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configuration, or revising the useful energy outputs 

(electrical and thermal) at an affected EGU already 

operating in a CHP configuration.1146

 Heat rate improvements, fuel switching, integrating RE and 

CHP would not require any additional accounting or monitoring 

and reporting, because under the emission guidelines affected 

EGUs are already required to monitor and report CO2 emissions at 

the stack level. Stack monitoring would reflect reductions in CO2

emissions from efficiency improvements, changes in fuel use 

(including incorporation of RE), and other on-site changes. 

Where states are implementing a rate-based plan, affected EGUs 

must also report useful energy output. 

( 

2). Actions with additional accounting and reporting 

requirements. 

 Certain actions that may be taken at an affected EGU to 

 

1146 The emission reduction potential from CHP stems from the unit 

using less fuel for producing useful electrical and thermal 

outputs than would be required to run separate electrical and 

thermal units. The emission reduction would depend on the type 

of affected EGU and available steam hosts in the vicinity of the 

affected EGU. A conventional combustion turbine generator, for 

example, converted into a CHP unit could effectively result in a 

reduction of 25 percent or more in the reported CO2 emission 

rate. The potential retrofitted EGU CHP market consists of 

converted simple cycle turbines, older steam plants in urban 

areas, and combined cycle units near beneficial thermal loads. 
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reduce CO2 emissions, specifically application of CCS and CCU, 

and use of biomass, require additional accounting and reporting. 

a. Application of CCS. (a) Application of CCS. Affected EGUs may 

utilize retrofit CCS technology to reduce reported stack CO2

emissions from the EGU.1147 Affected EGUs that apply CCS under a 

state plan must meet the same monitoring, recordkeeping and 

reporting and sequestration requirements for sequestered CO2 as 

new units that implement CCS to meet final standards of 

performance under CAA section 111(b) for new EGUs.1148

Specifically, the final CAA section 111(b) rule for new sources 

requires that, if a new affected EGU uses CCS to meet the 

applicable CO2 emission limit, the EGU must report in accordance 

with 40 CFR part 98 subpart PP (Suppliers of Carbon Dioxide), 

and the captured CO2 must be injected at a facility or facilities 

that report in accordance with 40 CFR part 98 subpart RR 

 

1147 Addition of retrofit CCS technology should not trigger CAA 

section 111(b) applicability for modified or reconstructed 

sources. Pollution control projects do not trigger NSPS 

modifications and addition of CCS technology does not count 

toward the capital costs of reconstruction for NSPS. 1148 Standards of Performance for Greenhouse Gas Emissions from 

New, Modified, and Reconstructed Stationary Sources: Electric 

Utility Generating Units. 
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(Geologic Sequestration of Carbon Dioxide).1149,1150 See 40 CFR 

part 60.46Da(h)(5) and part 60.5555(d). Taken together, these 

requirements ensure that the amount of captured and sequestered 

CO2 will be tracked as appropriate at project- and nationallevels, and that the status of the CO2 in its sequestration site 

will be monitored, including air-side monitoring and reporting. 

with CCS capability subject to the finalAs detailed in the 

preamble for the CAA section 111(b) rule for new EGUs.1151

Specifically, the final CAA section 111(b) rule for new sources 

requires that, if a new affected EGU uses CCS to meet the 

applicable CO2 emission limit, the EGU must report in accordance 

with 40 CFR part 98 subpart PP (Suppliers of Carbon Dioxide), 

 

1149 The final CAA section 111(b) rule finalizes amendments to 

subpart PP reporting requirements, specifically requiring that 

the following pieces of information be reported: (1) the 

electronic GHG Reporting Tool identification (e-GGRT ID) of the 

EGU facility from which CO2 was captured, and (2) the e-GGRT 

ID(s) for, and mass of CO2 transferred to, each GS site reporting 

under subpart RR. As noted, the final 111(b) rule also requires 

that any affected EGU unit that captures CO2 to meet the 

applicable emissionsemission limit must transfer the captured CO2

to a facility that reports under 40 CFR part 98 subpart RR. 

1150 Under final requirements in the CAA 111(b) NSPS, any well 

receiving CO2 captured from an affected sourceEGU, be it a Class 

VI or Class II well, must report under subpart RR. A UIC Class 

II well’s regulatory status does not change because it receives 

such CO2, nor does it change by virtue of reporting under subpart 

RR. 

1151 Standards of Performance for Greenhouse Gas Emissions from 

New, Modified, and Reconstructed Stationary Sources: Electric 

Utility Generating Units. 
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and the captured CO2 must be injected at a facility or facilities 

that report in accordance with 40 CFR part 98 subpart RR 

(Geologic Sequestration of Carbon Dioxide).1152,1153 See 40 CFR 

part 60.46Da(h)(5) and part 60.5555(d). Taken together, these 

requirements ensure that the amount of captured and sequestered 

CO2 will be tracked as appropriate at project- and nationallevels, and that the status of the CO2 in its sequestration site 

will be monitored, including air-side monitoring and reporting. 

As detailed in the preamble for the CAA section 111(b) standards 

for new EGUs, the EPA is convincedfound that there is ample 

evidence that CCS is technically feasible and that partial CCS 

can be implemented at a new fossil fuel-fired steam generating 

EGU at a cost that is reasonable and that is consistent with the 

cost of other dispatchable, non-NGCC generating options. In the 

 

1152 The final CAA section 111(b) rule finalizes amendments to 

subpart PP reporting requirements, specifically requiring that 

the following pieces of information be reported: (1) the 

electronic GHG Reporting Tool identification (e-GGRT ID) of the 

EGU facility from which CO2 was captured, and (2) the e-GGRT 

ID(s) for, and mass of CO2 transferred to, each GS site reporting 

under subpart RR. As noted, the final 111(b) rule also requires 

that any affected EGU unit that captures CO2 to meet the 

applicable emissionsemission limit must transfer the captured CO2

to a facility that reports under 40 CFR part 98 subpart RR. 

1153 Under final requirements in the CAA 111(b) NSPS, any well 

receiving CO2 captured from an affected sourceEGU, be it a Class 

VI or Class II well, must report under subpart RR. A UIC Class 

II well’s regulatory status does not change because it receives 

such CO2, nor does it change by virtue of reporting under subpart 

RR. 
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June 2014 proposal, the EPA noted that CCS technology at 

existing EGUs would entail additional considerations beyond 

those at issue for newly constructed EGUs. In the June 2014 

proposal, the EPA noted that CCS technology at existing EGUs 

would entail additional considerations beyond those at issue for 

newly constructed EGUs. Specifically, the cost of integrating a 

retrofit CCS system into an existing facility wouldmay be 

expected to be substantial, and some existing EGUs mightmay have 

space limitations and thus mightmay not be able to accommodate 

the expansion needed to install the equipment to implement CCS. 

Further, the EPA noted that aggregated costs of applying CCS as 

a component of the BSER for the large number of existing fossil 

fuel-fired steam EGUs would be substantial and would be expected 

to affect the cost and potentially the supply of electricity on 

a national basis. For those reasonsBecause there are lower-cost 

systems of emission reduction available to reduce emissions from 

existing plants, the EPA did not propose nor finalize CCS as a 

component of the BSER for existing EGUs. 

However, the EPA noted that CCS may be a viable CO2

mitigation technology at some existing sources and that it would 

be available to states and to sources as a compliance option. 

Numerous commenters agreed with the EPA’s proposed determination 

that CCS technology is not part of the BSER building blocks for 
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existing EGUs. Other commenters opposed inclusion of CCS 

requirements in state plans and provided specific reasons why 

CCS would not be applicable in certain states. Many commenters 

felt that CCS technology is not adequately demonstrated and is 

not economically practical at this time. Other commenters argued 

that CCS is an available technology and that it can be 

implemented at more EGUs than predicted by EPA modeling. 

Some commenters noted that there are opportunities to 

reduce the cost of CCS implementation by selling the captured CO2

for use in Enhanced Oil Recovery (EOR) operations. One commenter 

expressed concern that federal requirements under the Greenhouse 

Gas Reporting Program – specifically the requirement (mentioned 

above) to report under 40 CFR part 98 subpart RR – would 

foreclose, rather than encourage, the use of captured CO2 for 

EOR. However, the EPA noted that CCS may be a viable CO2

mitigation technology at some existing sources and that it would 

be available to states and to sources as a compliance option. 

Numerous commenters agreed with the EPA’s proposed determination 

that CCS technology is not part of the BSER building blocks for 

existing EGUs. Other commenters opposed inclusion of CCS 

requirements in state plans and provided specific reasons why 

CCS would not be applicable in certain states. Many commenters 

felt that CCS technology is not adequately demonstrated and is 
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not economically practical at this time. Other commenters argued 

that CCS is an available technology and that it can be 

implemented at more EGUs than predicted by EPA modelling. 

Some commenters noted that there are opportunities to 

reduce the cost of CCS implementation by selling the captured CO2

for use in Enhanced Oil Recovery (EOR) operations. One commenter 

expressed concern that federal requirements under the Greenhouse 

Gas Reporting Program – specifically the requirement (mentioned 

above) to report under 40 CFR part 98 subpart RR – would 

foreclose, rather than encourage, the use of captured CO2 for 

EOR. The EPA received similar public comments on the CAA 111(b) 

proposal for new EGUs and has. The EPA disagrees with the 

commenters’ assertions and addressed those in the preamble for 

the final standards of performance and in the Response-toComments (RTC) document for thatthe CAA 111(b) NSPS rulemaking. 

The EPA noted that the cost of compliance with subpart RR is not 

significant enough to offset the potential revenue for the EOR 

operator from the sale of produced oil for CCS projects that are 

reliant on EOR. The costs associated with subpart RR are 

relatively modest, especially in comparison with revenues from 

an EOR field.

After consideration of the variety of comments we received 

on this issue, we are confirming our proposal that CCS is not an 
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element of the BSER, but it is an available compliance measure 

for a state plan. EGUs implementing CCS would need to follow 

reporting requirements established in the final CAA section 

111(b) rule for new affected EGUs. 

b. Application of CCU. The EPA received comments suggesting that 

carbon capture and utilization (CCU) technologies should also be 

allowed as a CO2 emission rate adjustment measure for affected 

EGUs. 

(b) Application of CCU. The EPA received comments suggesting 

that carbon capture and utilization (CCU) technologies should 

also be allowed as a CO2 emission rate adjustment measure for 

affected EGUs. 

Potential alternatives to storing CO2 in geologic formations 

are emerging and these relatively new potential alternatives may 

offer the opportunity to offset the cost of CO2 capture. For 

example, captured anthropogenic CO2 may be stored in solid 

carbonate materials such as precipitated calcium carbonate (PCC) 

or magnesium or calcium carbonate, bauxite residue carbonation, 

and certain types of cement through mineralization. The 

carbonate materials produced can be tailored to optimize 

performance in specific industrial and commercial applications. 

For example, these carbonate materials have been used in the 

construction industry and, more recently and innovatively, in 
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cement production processes to replace Portland cement. 

The Skyonics Skymine® project, which opened its 

demonstration project in October 2014, is an example of captured 

CO2 being used in the production of carbonate products. This 

plant converts CO2 into commercial products. It captures over 

75,000 tons of CO2 annually from a San Antonio, Texas, cement 

plant and converts the CO2 into other products including sodium 

carbonate and sodium bicarbonate.1154 Other companies – including 

Calera1155 and New Sky1156 – also offer commercially available 

technology for the beneficial use of captured CO2. These 

processes can be utilized in a variety of industrial 

applications – including at fossil fuel-fired power plants. 

However, consideration of how these emerging alternatives 

could be used to meet CO2 emission performance rates or state CO2

emission goals would require a better understanding of the 

ultimate fate of the captured CO2 and the degree to which the 

method permanently isolates the captured CO2 or displaces other 

CO2 emissions from the atmosphere. 

Several commenters also suggested that algae-based CCU 

(i.e., the use of algae to convert captured CO2 to useful 

 

1154 http://skyonic.com/technologies/skymine. 1155 http://www.calera.com/beneficial-reuse-of-co2/process.html. 1156 http://www.newskyenergy.com/index.php/products/carboncycle. 
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products – especially biofuels) should be recognized for its 

potential to reduce emissions from existing fossil-fueled EGUs. 

Unlike geologic sequestration, there are currently no 

uniform monitoring and reporting mechanisms to demonstrate that 

these alternative end uses of captured CO2 result in overall 

reductions of CO2 emissions to the atmosphere. As these 

alternative technologies are developed, the EPA is committed to 

working collaboratively with stakeholders to evaluate the 

efficacy of alternative utilization technologies, to address any 

regulatory hurdles, and to develop appropriate monitoring and 

reporting protocols to demonstrate CO2 reductions. 

In the meantime, state plans may allow affected EGUs to use 

qualifying CCU technologies to reduce CO2 emissions that are 

subject to an emission standard, or those that are counted when 

demonstrating achievement of the CO2 emission performance rates 

or a state rate-based or mass-based CO2 emission. State plans 

must include analysis supporting how the proposed qualifying CCU 

technology results in CO2 emission mitigation from affected EGUs 

and provide monitoring, reporting, and verification requirements 

to demonstrate the reductions. The EPA would then review the 

appropriateness and basis for the analysis and the verification 

requirements in the course of its review of the state plan. 

 For example, captured anthropogenic CO2 may be stored in 
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solid carbonate materials such as precipitated calcium carbonate 

(PCC) or magnesium or calcium carbonate, bauxite residue 

carbonation, and certain types of cement through mineralization. 

The carbonate materials produced can be tailored to optimize 

performance in specific industrial and commercial applications. 

For example, these carbonate materials have been used in the 

construction industry and, more recently and innovatively, in 

cement production processes to replace Portland cement. 

The Skyonics Skymine® project, which opened its 

demonstration project in October 2014, is an example of captured 

CO2 being used in the production of carbonate products. This 

plant converts CO2 into commercial products. It captures over 

75,000 tons of CO2 annually from a San Antonio, Texas, cement 

plant and converts the CO2 into other products including sodium 

carbonate and sodium bicarbonate.1157 Other companies – including 

Calera1158 and New Sky1159 – also offer commercially available 

technology for the beneficial use of captured CO2. These 

processes can be utilized in a variety of industrial 

applications – including at fossil fuel-fired power plants. 

However, consideration of how these emerging alternatives 

 

1157 http://skyonic.com/technologies/skymine. 1158 http://www.calera.com/beneficial-reuse-of-co2/process.html. 1159 http://www.newskyenergy.com/index.php/products/carboncycle. 
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could be used to meet CO2 emission performance rates or state CO2

emission goals would require a better understanding of the 

ultimate fate of the captured CO2 and the degree to which the 

method permanently isolates the captured CO2 or displaces other 

CO2 emissions from the atmosphere. 

Several commenters also suggested that algae-based CCU 

(i.e., the use of algae to convert captured CO2 to useful 

products – especially biofuels) should be recognized for its 

potential to reduce emissions from existing fossil-fueled EGUs. 

Unlike geologic sequestration, there are currently no 

uniform monitoring and reporting mechanisms to demonstrate that 

these alternative end uses of captured CO2 result in overall 

reductions of CO2 emissions to the atmosphere. As these 

alternative technologies are developed, the EPA is committed to 

work collaboratively with stakeholders to evaluate the efficacy 

of alternative utilization technologies, to address any 

regulatory hurdles, and to develop appropriate monitoring and 

reporting protocols to demonstrate CO2 reductions. 

In the meantime, state plans may allow affected EGUs to use 

qualifying CCU technologies to reduce CO2 emissions that are 

subject to an emission standard, or those that are counted when 

demonstrating achievement of the CO2 emission performance rates 

or a state rate-based or mass-based CO2 emission. State plans 
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must include analysis supporting how the proposed qualifying CCU 

technology results in CO2 emission mitigation and provide 

monitoring, reporting, and verification requirements to 

demonstrate the reductions. The EPA would then review the 

appropriateness and basis for the analysis and the verification 

requirements in the course of its review of the state plan. 

(c) Biomassc. Application of biomass co-firing and repowering. 

The EPA received multiple comments supporting the use of biomass 

feedstocks as a means of reducing CO2 emissions within state 

plans. Several commenters also asserted that states should be 

able to determine how biomass can be used in their plans. 

Additionally, the EPA received a range of comments regarding the 

valuation of CO2 emissions from biomass combustion. Some argued 

that all biomass feedstocks should be considered “carbon 

neutral,” while others maintained that only the full stack 

emissions from biomass combustion should be counted. Affected 

EGUs may use qualifying biomass in order to reduce CO2 emissions 

that are subject to an emission standard requirement, or those 

that are counted when demonstrating achievement of the CO2

emission performance rates or a state rate-based or mass-based 

CO2 emission goal. Not all forms of biomass are expected to be 

approvable (see section below for considerations pertaining to 

biomass use in state plans). A state would propose qualifying 
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biomass feedstocks or categories of biomass feedstocks in its 

plan and the proposed treatment of biogenic CO2 emissions, 

including measures to ensure emission reduction benefits. State 

plans must include analysis supporting how proposed qualifying 

feedstocks or feedstock categories are considered appropriate as 

a CO2 emission mitigation approach as well as the proposed 

treatment of biogenic CO2 emissions (i.e., the proposed level of 

biogenic CO2 emissions from use of the biomass feedstock that 

would not be counted when demonstrating compliance with an 

emission standard, or when demonstrating achievement of the CO2

emission performance rates or a state rate-based or mass-based 

CO2 emission goal) and quality control measures. The EPA would 

review the appropriateness and basis for such determinations and 

accounting measures in the course of its review of a state plan. 

The EPA received multiple comments supporting the use of biomass 

feedstocks as a means of reducing CO2 emissions within state 

plans. Several commenters also asserted that states should be 

able to determine how biomass can be used in their plans. 

Additionally, the EPA received a range of comments regarding the 

valuation of CO2 emissions from biomass combustion. Some argued 

that all biomass feedstocks should be considered “carbon 

neutral,” while others maintained that only the full stack 

emissions from biomass combustion should be counted. As 
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discussed in the next section, the revised Framework for 

Assessing Biogenic Carbon Dioxide for Stationary Sources1160 and 

the 2012 Science Advisory Board peer review of the 2011 Draft 

Framework find that it is not scientifically valid to assume 

that all biogenic feedstocks are “carbon neutral.”1161, but that 

the net biogenic CO2 atmospheric contribution of different 

biomass feedstocks can vary and depends on various factors, 

including feedstock type and characteristics, production 

practices, and, in some cases, the alternative fate of the 

feedstock.1162 Other comments focused on the use of sustainablyderived agricultural and forest biomass feedstocks, including 

stakeholders who supported and those against such feedstocks as 

approvable elements, and those who wanted further definition of 

these feedstocks. As discussed above, and in more detail below, 

these final guidelines provide that states can propose 

qualifyinginclude qualified biomass in their plans and include 

provisions for how qualified biomass feedstocks or feedstock 

categories in state plans.will be determined. The EPA will 

review the appropriateness and basis for determining 

 

1160 www.epa.gov/climatechange/downloads/Framework-for-AssessingBiogenic-CO2-Emissions.pdf.

1161 www.epa.gov/climatechange/ghgemissions/biogenicemissions.html.

1162 www.epa.gov/climatechange/ghgemissions/biogenicemissions.html.
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qualifyingqualified biomass feedstocks or feedstock categories 

in its review of the approvability of a state plan. 

(i1) Considerations for use of biomass in state plans. 

The EPA recognizes that the use of some biomass-derived 

fuels can play a role in controlling increases of CO2 levels in 

the atmosphere. The use of some kinds of biomass has the 

potential to offer a wide range of environmental benefits, 

including carbon benefits. However, these benefits can typically 

only be realized if biomass feedstocks are sourced responsibly 

and attributes of the carbon cycle related to the biomass 

feedstock are taken into account. 

In November 2014, the agency released a second draft of the 

technical report, Framework for Assessing Biogenic Carbon 

Dioxide for Stationary Sources. The revised Framework, and the 

EPA’s Science Advisory Board (SAB) peer review of the 2011 Draft 

Framework, finds that it is not scientifically valid to assume 

that all biogenic feedstocks are “carbon neutral” and that the 

net biogenic CO2 atmospheric contribution of different biogenic 

feedstocks generally depends on various factors related to 

feedstock characteristics, production, processing and combustion 

practices, and, in some cases, what would happen to that 

feedstock and the related biogenic emissions if not used for 
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energy production.1163 AsThe revised Framework also found that the 

production and use of some biogenic feedstocks and subsequent 

biogenic CO2 emissions from stationary sources will not 

inevitably result in increased levels of CO2 to the atmosphere, 

unlike CO2 emissions from combustion of fossil fuels. 

The SAB peer review panel agreed that the use of biomass 

feedstocks derived from the decomposition of biogenic waste in 

landfills, compost facilities or anaerobic digesters did not 

constitute a net contribution of biogenic CO2 emissions to the 

atmosphere. And further, information considered in preparing the 

second draft of the Framework, including the SAB peer review and 

stakeholder input, supports the finding that use of wastederived feedstocks1164 and certain forest-derived industrial 

 

1163 www.epa.gov/climatechange/ghgemissions/biogenicemissions.html. Specifically, the SAB found that “There are 

circumstances in which biomass is grown, harvested and combusted 

in a carbon neutral fashion but carbon neutrality is not an 

appropriate a priori assumption; it is a conclusion that should 

be reached only after considering a particular feedstock’s 

production and consumption cycle. There is considerable 

heterogeneity in feedstock types, sources and production methods 

and thus net biogenic carbon emissions will vary considerably.” 

www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html. 

1164 Types of waste-derived biogenic feedstocks may include: 

landfill gas generated through the decomposition of MSW in a 

landfill; biogas generated from the decomposition of livestock 

waste, biogenic MSW, and/or other food waste in an anaerobic 

digester; biogas generated through the treatment of waste water, 

due to the anaerobic decomposition of biological materials; 
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byproducts (such as those without alternative markets) are 

likely to have minimal or no net atmospheric contributions of 

biogenic CO2 emissions, or even reduce such impacts, when 

compared with an alternate fate of disposal. 

In addition, as detailed in the President’s Climate Action 

Plan,1165 part of the strategy to address climate change includes 

efforts to protect and restore our forests, as well as other 

critical landscapes including grasslands and wetlands, in the 

face of a changing climate. This country’s forests currently 

play a critical role in addressing carbon pollution, removing 

nearly 12more than 13 percent of total U.S. greenhouse gas 

emissions each year.1166 Conservation and sustainable management 

can help ensure our forests and other lands will continue to 

remove carbon from the atmosphere while also improving soil and 

water quality, reducing wildfire risk and enhancing forests’ 

resilience in the face of climate change. 

Many states have recognized the importance of forests and 

other lands for climate resilience and mitigation, and have 

 

livestock waste; and the biogenic fraction of MSW at waste-toenergy facilities. 

1165 www.whitehouse.gov/sites/default/files/image/ 

president27sclimateactionplan.pdf. 1166 www.epa.gov/climatechange/Downloads/ghgemissions/US-GHGInventory-2015-Chapter-6-Land-Use-Land-Use-Change-andForestry.pdf.
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developed a variety of sustainable forestry policies, RE 

incentives and standards, and GHG accounting procedures. Some 

states, for example Oregon and California, have programs that 

recognize the multiple benefits that forests provide, including 

biodiversity and ecosystem services protection as well as 

climate change mitigation through carbon storage. Oregon has 

several programs focused on best forest management practices and 

sustainability, including the Oregon Indicators of Sustainable 

Forests, that promote environmentally, economically and socially 

sustainable management of state forests. California’s Forest 

Practice Regulations support sustained production of highquality timber while considering ecological, economic and social 

values, and the state’s Greenhouse Gas Reduction Fund provides 

resources for forestry projects to improve forest health, 

maintain carbon storage and avoid GHG emissions from pests, 

wildfires and conversion to non-forest uses. 

Several states focus on sustainable bioenergy, as seen with 

the sustainability requirements for eligible biomass in the 

Massachusetts RPS, which, among other requirements, limits old 

growth forest harvests. Many states employ complementary 

programs that together work to address sustainable forestry 

practices. For example, Wisconsin uses a state forest 

sustainability framework that provides a common system to 
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Page 1543 of 2153

measure the sustainability of the state’s public and private 

forests, in conjunction with a series of voluntary best 

management guideline manuals for sustainable woody biomass and 

agriculturally-derived biomass. In addition to state-specific 

programs, some states also actively participate in sustainable 

forest management or certification programs through third-party 

entities such as the Sustainable Forestry Initiative (SFI) and 

the Forest Stewardship Council (FSC). For example, in addition 

to other state sustainability programs, New York has certified 

more than 780,000 acres of state forestland to both SFI and 

FSC’s sustainable forest management programs. SFI and FSC have 

certified more than 63 and 35 million acres of forestland across 

the U.S., respectively. 

These examples demonstrate how states already use diverse 

strategies to promote sustainable forestry and agricultural 

management while realizing their unique economic, environmental 

and RE goals. 

The EPA recognizes that some biomass-derived fuels can play 

a role in CO2 emissions reduction strategies. The EPA also 

anticipates that some states may consider biomass-derived fuels 

used in electricity generation as a way to mitigate CO2

emissions, and will include them as part of their state plans to 

meet the emission guidelines. 
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With regard to assessing qualifying biomass specified in 

state plans, the EPA generally acknowledges the CO2 emissions 

reduction and climate policy benefits of waste-derived biogenic 

feedstocks1167 and certain forest- and agriculture-derived 

industrial byproduct feedstocks, based on the conclusions 

supported by a variety of technical studies, including the 

revised Framework for Assessing Biogenic Carbon Dioxide for 

Stationary Sources. Such waste-derived and certain industrial 

byproduct biomass feedstocks would likely be approvable as 

qualifying biomass in a state plan. In addition, given the 

importance of sustainable land management in achieving the 

carbon reduction goals of the President’s Climate Action Plan, 

sustainably-derived agricultural and forest biomass feedstocks 

may also be acceptable as qualifying biomass in a state plan, if 

the state-supplied analysis of proposed qualifying feedstocks or 

feedstock categories can adequately demonstrate that such 

feedstocks or feedstock categories are considered appropriate as 

 

1167 Types of waste-derived biogenic feedstocks may include: 

landfill gas generated through the decomposition of MSW in a 

landfill; biogas generated from the decomposition of livestock 

waste, biogenic MSW, and/or other food waste in an anaerobic 

digester; biogas generated through the treatment of waste water, 

due to the anaerobic decomposition of biological materials; 

livestock waste; and the biogenic fraction of MSW at waste-toenergy facilities (as discussed in section VIII.G.1.b(3)(c) 

below). 
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a CO2 emission mitigation approach. 

Many states have recognized the importance of forests and 

other lands for climate resilience and mitigation, and have 

developed a variety of sustainable forestry policies, RE 

incentives and standards, and GHG accounting procedures. Some 

states, for example Oregon and California, have programs that 

recognize the multiple benefits that forests provide, including 

biodiversity and ecosystem services protection as well as 

climate change mitigation through carbon storage. Oregon has 

several programs focused on best forest management practices and 

sustainability, including the Oregon Indicators of Sustainable 

Forests, that promote environmentally, economically and socially 

sustainable management of state forests. California’s Forest 

Practice Regulations support sustained production of highquality timber while considering ecological, economic and social 

values, and the state’s Greenhouse Gas Reduction Fund provides 

resources for forestry projects to improve forest health, 

maintain carbon storage and avoid GHG emissions from pests, 

wildfires and conversion to non-forest uses. 

Several states focus on sustainable bioenergy, as seen with 

the sustainability requirements for eligible biomass in the 

Massachusetts RPS, which, among other requirements, limits old 

growth forest harvests. Many states employ complementary 
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Page 1546 of 2153

programs that together work to address sustainable forestry 

practices. For example, Wisconsin uses a state forest 

sustainability framework that provides a common system to 

measure the sustainability of the state’s public and private 

forests, in conjunction with a series of voluntary best 

management guideline manuals for sustainable woody biomass and 

agriculturally-derived biomass. In addition to state-specific 

programs, some states also actively participate in sustainable 

forest management or certification programs through third-party 

entities such as the Sustainable Forestry Initiative (SFI) and 

the Forest Stewardship Council (FSC). For example, in addition 

to other state sustainability programs, New York has certified 

more than 780,000 acres of state forestland to both SFI and 

FSC’s sustainable forest management programs. SFI and FSC have 

certified more than 63 and 35 million acres of forestland across 

the U.S., respectively. 

These examples demonstrate how states already use diverse 

strategies to promote sustainable forestry and agricultural 

management while realizing their unique economic, environmental 

and RE goals. As states evaluate options for meeting the 

emission guidelines, they may consider how the role of wastederived feedstocks as well as sustainably-derived biomass and 

sustainable forestry and agriculture programs, such as the 
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examples highlighted above, may help them meet their emission 

reduction goals.control increases of CO2 levels in the 

atmosphere. In addition, the EPA’s work on assessing biogenic CO2

emissions from stationary sources may also help inform states’ 

efforts to assess the role of different biogenic feedstocks in 

their plans and broader climate strategies.1168

 In November 2014, the agency released a second 

draft of the technical report, Framework for Assessing Biogenic 

Carbon Dioxide for Stationary Sources. The revised Framework,

and the EPA’s Science Advisory Board (SAB) peer review of the 

2011 Draft Framework, finds that it is not scientifically valid 

to assume that all biogenic feedstocks are “carbon neutral” and 

that the net biogenic CO2 atmospheric contribution of different 

biogenic feedstocks generally depends on various factors related 

to feedstock characteristics, production, processing and 

combustion practices, and, in some cases, what would happen to 

that feedstock and the related biogenic emissions if not used 

for energy production.1169 The EPA is engaging in a second round 

 

1168 As highlighted in a November 2014 memorandum to the EPA’s 

Regional Air Division Directors. 

www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html.

1169 www.epa.gov/climatechange/ghgemissions/biogenicemissions.html. Specifically, the SAB found that “There are 

circumstances in which biomass is grown, harvested and combusted 

in a carbon neutral fashion but carbon neutrality is not an 
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of targeted peer review on the revised Framework with the SAB in 

2015.1170 As part of this technical process, and as the EPA and 

states implement these emission guidelines, the EPA will 

continue to assess and closely monitor overall bioenergy demand 

and associated landscape conditions for changes that might have 

negative impacts on public health or the environment. 

(2) Additional considerations and requirements for biomass 

fuels. 

 The EPA anticipates that some states may consider the use 

of certain biomass-derived fuels used in electricity generation 

as a way to control increases of CO2 levels in the atmosphere, 

and will include them as part of their state plans to meet the 

emission guidelines. Not all forms of biomass are expected to be 

approvable as qualified biomass (i.e., biomass that can be 

considered as an approach for controlling increases of CO2 levels 

in the atmosphere). Affected EGUs may use qualified biomass in 

order to control or reduce CO2 emissions that are subject to an 

emission standard requirement, or those that are counted when 

 

appropriate a priori assumption; it is a conclusion that should 

be reached only after considering a particular feedstock’s 

production and consumption cycle. There is considerable 

heterogeneity in feedstock types, sources and production methods 

and thus net biogenic carbon emissions will vary considerably.” 

www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html. 

1170 www.epa.gov/sab. 
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demonstrating achievement of the CO2 emission performance rates 

or a state rate-based or mass-based CO2 emission goal. 

 State plan submissions must describe the types of biomass 

that are being proposed for use under the state plan and how 

those proposed feedstocks or feedstock categories should be 

considered as “qualified biomass” (i.e., a biomass feedstock 

that is demonstrated as a method to control increases of CO2

levels in the atmosphere). The submission must also address the 

proposed valuation of biogenic CO2 emissions (i.e., the proposed 

portion of biogenic CO2 emissions from use of the biomass 

feedstock that would not be counted when demonstrating 

compliance with an emission standard, or when demonstrating 

achievement of the CO2 emission performance rates or a state 

rate-based or mass-based CO2 emission goal). 

 With regard to assessing qualified biomass proposed in 

state plans, the EPA generally acknowledges the CO2 and climate 

policy benefits of waste-derived biogenic feedstocks and certain 

forest- and agriculture-derived industrial byproduct feedstocks, 

based on the conclusions supported by a variety of technical 

studies, including the revised Framework for Assessing Biogenic 

Carbon Dioxide for Stationary Sources. The use of such wastederived and certain industrial byproduct biomass feedstocks 

would likely be approvable as qualified biomass in a state plan 
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when proposed with measures that meet the biomass monitoring, 

reporting and verification requirements discussed below and 

other measures as required elsewhere in these emission 

guidelines. 

 Given the importance of sustainable land management in 

achieving the carbon goals of the President’s Climate Action 

Plan, sustainably-derived agricultural and forest biomass 

feedstocks may also be acceptable as qualified biomass in a 

state plan, if the state-supplied analysis of proposed qualified 

feedstocks or feedstock categories can adequately demonstrate 

that such feedstocks or feedstock categories appropriately 

control increases of CO2 levels in the atmosphere and can 

adequately monitor and verify feedstock sources and related 

sustainability practices. Information in the revised Framework

and, the second SAB peer review process, including stakeholder 

comments, should and the state and third party programs 

highlighted in the previous section can assist both states 

andwhen considering the EPA in assessing qualifyingrole of 

qualified biomass feedstocks included in state plans.plan 

submittals. 

(ii Regardless of what biomass feedstocks are proposed, 

state plans must specify how biogenic CO2 emissions will be 

monitored and reported, and identify specific EM&V, tracking and 
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auditing approaches for qualified biomass feedstocks. As 

discussed in section VIII.D.2, state plan submittals must 

include CO2 emission monitoring, reporting and recordkeeping 

measures. In the case of sustainably-derived forest- and 

agriculture-derived feedstocks, this will also include measures 

for verifying feedstock type, origin and associated 

sustainability practices. Section VIII.K describes how state 

plan submittals must specify the requirements and procedures 

that EM&V measures must meet. As discussed in section VIII.K, 

the EPA is addressing potential EM&V measures for qualified 

biomass in EPA’s model trading rule and draft EM&V guidance, 

such as measures that would ensure that biomass-related biogenic 

CO2 benefits are quantifiable, verifiable, non-duplicative, 

permanent and enforceable. 

 State plan submittals must ensure that all biomass used 

meets the state plan requirements for qualified biomass and 

associated biogenic CO2 benefits, such as using robust, 

independent third party verification and establishing measures 

to maintain transparency, including disclosure of relevant 

documentation and reports. State plan submittals must include 

measures for tracking and auditing performance to ensure that 

biomass used meets the state plan requirements for qualified 

biomass and associated biogenic CO2 benefits. Details on how to 
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adjust CO2 rates through the use of qualified biomass feedstocks 

are provided in section VIII.K.1. 

 The EPA will review the appropriateness and basis for 

proposed qualified biomass and biomass treatment determinations 

and related accounting, monitoring and reporting measures in the 

course of its review of a state plan. The EPA’s determination 

that a state plan satisfactorily proves that proposed biomass 

fuels qualify would be based in part on whether the plan 

submittal demonstrates that proposed state measures for 

qualified biomass and related biogenic CO2 benefits are 

quantifiable, verifiable, enforceable, non-duplicative and 

permanent. The EPA recognizes that CCS technology (described 

above in section VIII.I.2.a) could be applied in conjunction 

with the use of qualified biomass. 

(3) Biomass co-firing. 

Affected EGUs may use qualifyingqualified biomass co-fired 

with fossil fuels at an affected EGU. As discussed above in this 

section, not all forms of biomass are expected to be approvable 

and states should propose biomass feedstocks and treatment of 

biogenic CO2 emissions in state plans, along with supporting 

analysis where applicable. The EPA will review the 

appropriateness and basis for such determinations and accounting 

measures in the course of its review of a state plan. 
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 An affected EGU using qualified biomass as a fuel must 

monitor and report both its overall CO2 emissions and its 

biogenic CO2 emissions. If biomass is to be used as means to 

control increases of CO2 levels in the atmosphere in a state 

plan, the plan must specify requirements for reporting biogenic 

CO2 emissions from affected EGUs. 

(4) Biomass repowering. 

Affected EGUs could fully repower to use primarily 

qualified biomass. The characteristics of affected EGUs, as 

discussed in section IV.D, include the use of at least 10 

percent fossil fuel for applicability of these emission 

guidelines. An EGU repowering with at least 90 percent biomass 

fuels instead of fossil fuels becomes a non-affected EGU.1171

qualifyingAn EGU repowering with less than 90 percent biomass 

would remain an affected EGU and therefore need to propose

biomass feedstocks and treatment of biogenic CO2 emissions in 

state plans, along with supporting analysis where applicable. 

J. Additional Considerations and Requirements for Mass-Based 

State Plans 

 

1171 For such an EGU to be considered non-affected, the EGU 

shouldmust be subject to a federally enforceable or practically 

enforceable condition, expressed in (for example) a construction 

permit or otherwise, that limits the amount of fossil fuel that 

may be used to 10 percent or less. 
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 This section discusses considerations and requirements for 

different types of mass-based state plans. This includes massbased state plans using emission budget trading programs, and 

coordination among such programs where states retain individual 

mass CO2 emission goals. CAA section 111(d) requires states to 

submit, in part, a plan that establishes standards of 

performance for affected EGUs which reflect the BSER. The state 

plan must be satisfactory with respect to this requirement in 

order for the EPA to approve the plan. As previously described, 

states meet the statutory requirements of 111(d) and the 

requirements of the final emission guidelines by establishing 

emission standards for affected EGUs that meet the performance 

rates, which reflect the application of BSER as determined by 

the EPA. This final rule allows states to alternatively 

establish emission standards that meet rate-based or mass-based 

goals. The state goals must be equivalent to the performance 

rates in order to reflect the application of the BSER as 

required by the statute and the final emission guidelines. 

Therefore, a state choosing a mass-based implementation must 

address leakage as part of its mass-based plan in order to 

satisfactorily establish emission standards for affected EGUs 

that reflect the BSER as set by the EPA. 

1. Accounting for CO2 emission reduction measures in mass-based 
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state plans 

As discussed in section VIII.I, measures that occur at 

affected EGUs will result in CO2 emission reductions that are 

automatically accounted for in reported CO2 emissions. Other 

measures that provide substitute generation for affected EGUs or 

avoid the need for generation from affected EGUs, such as 

demand-side EE, are automatically accounted for under a massbased plan to the extent that these measures reduce reported CO2

emissions from affected EGUs. Unlike under a rate-based plan, no 

additional accounting is necessary in order to recognize these 

emission reductions. 

2. Use of emission budget trading programs 

This section addresses the use of emission budget trading 

programs in a mass-based state plan, including provisions 

required for such programs and the design of such programs in 

the context of a state plan. This includes program design 

approaches that ensure achievement of a state mass-based CO2

emission goal (or mass-based CO2 goal plus new source CO2

emission complement) (section VIII.J.2.b), as well as how states 

can use emission budget trading programs with broader source 

coverage and other flexibility features in a state plan, such as 

the programs currently implemented by California and the RGGI 

participating states (section VIII.J.2.c). Section VIII.J.2.d 
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addresses other considerations for the design of emission budget 

trading programs that states may want to consider, such as 

allowance allocation approaches. Section VIII.J.3 addresses 

multi-state coordination among emission budget trading programs 

used in states that retain their individual state mass-based CO2

goals. 

a. State plan provisions required for a mass-based emission 

budget trading program approach. For a mass-based emission 

trading program approach, the state plan would include as its 

federally enforceable emission standards requirements that 

specify the emission budget and related compliance requirements 

and mechanisms. These requirements would include: CO2 emission 

monitoring, reporting, and recordkeeping requirements for 

affected EGUs; provisions for state allocation of allowances; 

provisions for tracking of allowances, from issuance through 

submission for compliance; and the process for affected EGUs to 

demonstrate compliance (allowance “true-up” with reported CO2

emissions). Mass-based emission standards that take the form of 

an emission budget trading program must be quantifiable, 

verifiable, enforceable, non-duplicative and permanent. These 

requirements are described in more detail at section VIII.D.2.

 Where a state plan establishes mass-based emission 

standards for affected EGUs only, the emission standards and the 
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implementing and enforcing measures may be included in the state 

plan as the full set of requirements implementing the emission 

budget trading program. Where an emission budget trading program 

in a state plan addresses affected EGUs and other fossil fuelfired EGUs or emission sources, pursuant to the approaches 

described in sections VIII.J.2.b-d below, the requirements that 

must be included in the state plan are the federally enforceable 

emission standards in the state plan that apply specifically to 

affected EGUs, and the requirements that specifically require 

affected EGUs to participate in and comply with the requirements 

of the emission budget trading program. This includes the 

requirement for an affected EGU to surrender emission allowances 

equal to reported CO2 emissions, and meet monitoring and 

reporting requirements for CO2 emissions, among other 

requirements. These requirements may be submitted as part of the 

federally enforceable state plan through mechanisms with the 

appropriate legal authority and effect, such as state 

regulations, Title V permit requirements for affected EGUs, and 

other possible instruments that impose these requirements 

specifically with respect to affected EGUs. Under this approach, 

the full set of regulations establishing the emission budget 

trading program that applies to affected EGUs and other fossil 

fuel-fired EGUs and other emission sources (if relevant) must be 
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described as supporting documentation in the state plan 

submittal for EPA to evaluate the approvability of the plan by 

determining whether the affected EGUs will achieve the requisite 

goal. 

b. Requirement for emission budget trading programs to address 

potential leakage. In Section VII.D, the EPA specifies that 

potential emission leakage must be addressed in a state plan 

with mass-based emission standards. The EPA received comments 

suggesting various solutions to this concern, such as the 

inclusion of new sources under the rule and quantitative 

adjustments to mass CO2 goals for affected EGUs. In response to 

this issue, the EPA has sought to give states flexibility in how 

they meet this requirement and base the acceptable solutions on 

what will best suit a state’s unique characteristics and state 

plan structure. 

To address the potential for emission leakage to new 

sources under a mass-based plan approach, which could prevent a 

mass-based program from successfully achieving a mass-based CO2

goal consistent with BSER, the EPA is requiring that a state 

submitting a plan that is designed to meet a state mass-based CO2

goal for affected EGUs demonstrate that the plan addresses and 

mitigates the risk of potential emission leakage to new sources. 

The following options provide sufficient demonstration that 
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potential emission leakage has been addressed in a mass-based 

state plan:1172

1. Regulate new non-affected fossil EGUs as a matter of 

state law in conjunction with emission standards for 

affected EGUs in a mass-based plan. If a state adopts an 

EPA-provided mass budget1173 that includes the state massbased CO2 goal for affected EGUs plus a new source CO2

emission complement, this option could be presumptively 

approvable. 

2. Use allocation methods in the state plan that counteract 

incentives to shift generation from affected EGUs to 

unaffected fossil-fired sources. If a state adopts 

allowance set-aside provisions exactly as they are 

outlined in the finalized model rule, this option could 

be presumptively approvable. 

3. Provide a demonstration in the state plan, supported by 

analysis, that emission leakage is unlikely to occur due 

to unique state characteristics or state plan design 

elements that address and mitigate the potential for 

 

1172 The first two options need not be mutually exclusive; they 

can both be implemented as part of a mass-based plan. 

1173 In Table 14, we have provided a mass budget for each state 

that includes the state mass-based CO2 goal and a projection for 

a new source CO2 emission complement. 
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emission leakage. 

In the first option, states may choose to regulate new nonaffected fossil fuel-fired EGUs, as a matter of state law, in 

conjunction with federally enforceable emission standards for 

affected EGUs under a mass-based plan. This regulation of both 

new and existing sources, as part of a state plan approach, is 

conceptually analogous to a method that has been adopted by the 

mass-based systems adopted by California and the RGGI 

participating states. To address potential emission leakage 

under this option, the mass-based plan includes federally 

enforceable emission standards for affected EGUs, and the 

supporting documentation for the plan describes stateenforceable regulations for, at a minimum, all new gridconnected fossil fuel-fired EGUs that meet the applicability 

standards for EGUs subject to CAA section 111(b). States have 

the option of regulating a wider array of sources if they 

choose, as a matter of state law. 

For this option, a state must adopt, as a matter of state 

law, a mass CO2 emission budget of sufficient size to cover both 

affected EGUs under the existing source mass CO2 goal provided in 

this final rule, along with sufficient CO2 emission tonnage to 

cover projected new sources. There are two pathways that states 

can use for adopting such an emission budget that applies to 
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both affected EGUs and new sources. The EPA is providing a mass 

budget for each state that account for the state’s mass CO2 goal 

for affected EGUs and a complementary emission budget for new 

sources, referred to as the new source CO2 emission complement. 

States that both adopt the EPA-provided mass budget, based on 

the state mass-based CO2 goal for affected EGUs plus the new 

source CO2 emission complement, and regulate new sources under 

this emission budget as a matter of state law, in conjunction 

with federally enforceable emission standards for affected EGUs 

as part of the mass-based state plan may be able to submit a 

presumptively approvable plan. Such a plan would include 

federally enforceable emission standards for affected EGUs, and 

in the supporting documentation of the plan, would describe that 

the state is regulating new sources under a mass CO2 emission 

budget that is equal to or less than the state mass-based CO2

goal for affected EGUs plus the EPA-specified CO2 emission 

complement, in conjunction with the federally enforceable 

emission standards for affected EGUs. If the state plan is 

designed to achieve the EPA provided mass budget, plan 

performance will be evaluated based on whether the existing 

affected EGUs, regulated under the federally enforceable state 

plan, and new sources regulated as a matter of state law, 

together meet the total mass budget that includes the state’s 
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mass CO2 goal for affected EGUs and a complementary emission 

budget for new sources.

EPA-specified mass CO2 emission budgets for each state, 

including the state’s mass CO2 goal and a new source CO2 emission 

complement, are provided in Table 14 below. The derivation of 

the new source CO2 emission complements is explained in a TSD 

titled New Source Complements to Mass Goals, which is available 

in the docket. 

Table 14. New Source Complements to Mass Goals 

State 

New Source 

Complements (Short 

Tons of CO2) 

Mass Goals1174 + New Source 

Complements (Short Tons of 

CO2) 

Interim Final Interim Final 

Alabama 

 

856,524 

 

755,700 

 

63,066,812 

 

57,636,174 

Arizona 

 

1,424,998 

 

2,209,446 

 

34,486,994 

 

32,380,196 

Arkansas 

 

411,315 

 

362,897 

 

34,094,572 

 

30,685,529 

California 

 

2,846,529 

 

4,413,516 

 

53,873,603 

 

52,823,635 

Colorado 

 

1,239,916 

 

1,922,478 

 

34,627,799 

 

31,822,874 

Connecticut 

 

135,410 

 

119,470 

 

7,373,274 

 

7,060,993 

Delaware 

 

78,842 

 

69,561 

 

5,141,711 

 

4,781,386 

Florida 

 

1,753,276 

 

1,546,891 

 

114,738,005 

 

106,641,595 

Georgia 

 

677,284 

 

597,559 

 

51,603,368 

 

46,944,404 

Idaho 

 

94,266 

 

146,158 

 

1,644,407 

 

1,639,013 

 

1174 The state mass CO2 goals can be found in Table 13 in section 

VII. 
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Illinois 

 

818,349 

 

722,018 

 

75,619,224 

 

67,199,174 

Indiana 

 

939,343 

 

828,769 

 

86,556,407 

 

76,942,604 

Iowa 

 

298,934 

 

263,745 

 

28,553,345 

 

25,281,881 

Kansas 

 

260,683 

 

229,997 

 

25,120,015 

 

22,220,822 

Kentucky 

 

752,454 

 

663,880 

 

72,065,256 

 

63,790,001 

Louisiana 

 

484,308 

 

427,299 

 

39,794,622 

 

35,854,321 

Maine 

 

40,832 

 

36,026 

 

2,199,016 

 

2,109,968 

Maryland 

 

170,930 

 

150,809 

 

16,380,325 

 

14,498,436 

Massachusetts 

 

225,127 

 

198,626 

 

12,972,803 

 

12,303,372 

Michigan 

 

623,651 

 

550,239 

 

53,680,801 

 

48,094,302 

Minnesota 

 

286,535 

 

252,806 

 

25,720,126 

 

22,931,173 

Mississippi 

 

410,440 

 

362,126 

 

27,748,753 

 

25,666,463 

Missouri 

 

668,637 

 

589,929 

 

63,238,070 

 

56,052,813 

Montana 

 

421,674 

 

653,801 

 

13,213,003 

 

11,956,908 

Nebraska 

 

216,149 

 

190,706 

 

20,877,665 

 

18,463,444 

Nevada 

 

770,417 

 

1,194,523 

 

15,114,508 

 

14,718,107 

New Hampshire 

 

71,419 

 

63,012 

 

4,314,910 

 

4,060,591 

New Jersey 

 

313,526 

 

276,619 

 

17,739,906 

 

16,876,364 

New Mexico 

 

527,139 

 

817,323 

 

14,342,699 

 

13,229,925 

New York 

 

522,227 

 

460,753 

 

34,117,555 

 

31,718,182 

North Carolina 

 

692,091 

 

610,623 

 

57,678,116 

 

51,876,856 

North Dakota 

 

245,324 

 

216,446 

 

23,878,144 

 

21,099,677 
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Ohio 

 

949,997 

 

838,170 

 

83,476,510 

 

74,607,975 

Oklahoma 

 

581,051 

 

512,654 

 

45,191,382 

 

41,000,852 

Oregon 

 

453,663 

 

703,399 

 

9,096,826 

 

8,822,053 

Pennsylvania 

 

1,257,336 

 

1,109,330 

 

100,588,162 

 

90,931,637 

Rhode Island 

 

70,035 

 

61,791 

 

3,727,420 

 

3,584,016 

South Carolina 

 

344,885 

 

304,287 

 

29,314,508 

 

26,303,255 

South Dakota 

 

46,513 

 

41,038 

 

3,995,462 

 

3,580,518 

Tennessee 

 

358,838 

 

316,598 

 

32,143,698 

 

28,664,994 

Texas 

 

5,328,758 

 

8,516,408 

 

213,419,599 

 

198,105,249 

Utah 

 

981,947 

 

1,522,500 

 

27,548,327 

 

25,300,693 

Virginia 

 

450,039 

 

397,063 

 

30,030,110 

 

27,830,174 

Washington 

 

531,761 

 

824,490 

 

12,211,467 

 

11,563,662 

West Virginia 

 

602,940 

 

531,966 

 

58,686,029 

 

51,857,307 

Wisconsin 

 

364,841 

 

321,895 

 

31,623,197 

 

28,308,882 

Wyoming 

 

1,185,554 

 

1,838,190 

 

36,965,606 

 

33,472,602 

Lands of the 

Navajo Nation 

 

809,562 

 

1,255,217 

 

25,367,354 

 

22,955,804 

Lands of the 

Uintah and 

Ouray 

Reservation 

 

84,440 

 

130,923 

 

2,645,885 

 

2,394,354 

Lands of the 

Fort Mojave 

Tribe 

 

37,162 

 

57,619 

 

648,264 

 

646,138 

Total 

 

33,717,871 

 

41,187,289 

 

1,878,255,620 

 

1,709,291,348 

States can, in the alternative, provide their own 
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Page 1565 of 2153

projections for a new source CO2 emission complement to their 

mass-based CO2 goals for affected EGUs. In the supporting 

documentation for the state plan submittal, the state must 

specify the new source budget, specify the analysis used to 

derive such a new source CO2 emission complement, and the state 

must demonstrate that under the state plan affected EGUs in the 

state will meet the state mass-based CO2 goal for affected EGUs 

as a result of being regulated under the broader CO2 emission cap 

that applied to both affected EGUs and new sources. Such a 

projection should take into account the mass goal quantification 

method outlined in section VII.C and the CO2 Emission Performance 

Rate and Goal Computation TSD, including the fact that the massbased state goals already incorporate a significant growth in 

generation from historical levels. The EPA will evaluate the 

approvability of the plan based on whether the federally 

enforceable emission standards for affected EGUs in conjunction 

with the state-enforceable regulatory requirements for new 

sources will result in the affected EGUs meeting the state massbased CO2 goal. If, rather than designing a plan to achieve the 

EPA provided mass budget, the state uses its own projections for 

a new source complement and the plan is approved to meet this 

new source complement, plan performance will be evaluated based 

on whether the existing affected EGUs, regulated under the 
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Page 1566 of 2153

federally enforceable state plan, meet the state’s mass CO2 goal 

for affected EGUs.

The second demonstration option allows states to use 

allowance allocation methods that counteract incentives to shift 

generation from affected EGUs to unaffected fossil-fired 

sources. These allocation approaches must be specified in state 

plans as part of the provisions for state allocation of 

allowances required under a mass-based plan approach (see 

section VIII.J.2.a). The EPA is proposing the inclusion of two 

allocation strategies as part of the mass-based approach in the 

proposed federal plan and model rule: updating output-based 

allocations and an allowance set-aside that targets RE. These 

options are described in more detail below. If a state were to 

adopt allowance set-aside provisions exactly as they are 

outlined in the finalized model rule, they could be considered 

presumptively approvable. The allowance allocation alternative 

for addressing leakage was chosen for the federal plan and model 

rule proposal because EPA does not have authority to extend 

regulation of and federal enforceability to new fossil fuelfired sources under CAA section 111(d), and therefore we cannot 

include them under a federal mass-based plan approach. 

An updating output-based allocation method allocates a 

portion of the total CO2 emission budget to affected EGUs based, 
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Page 1567 of 2153

in part, on their level of electricity generation in a recent 

period or periods. Therefore, the total allocation to an EGU 

that is eligible to receive allowances from an output-based 

allowance set-aside is not fixed, but instead depends on its 

generation. Under this approach, each eligible affected EGU may 

receive a larger allowance allocation if it generates more. 

Therefore, eligible affected EGUs will have an incentive to 

generate more in order to receive more allowances, aligning 

their incentive to generate with new sources. 

This allocation method can be implemented through the 

creation of a set-aside that reserves a subset of the total 

allowances available to sources, and distributes them based upon 

the criteria described above. Because the total number of 

allowances is limited, this allocation approach will not exceed 

the overall state mass-based CO2 goal for affected EGUs. Instead, 

it merely modifies the distribution of allowances in a manner 

designed to mitigate potential emission leakage. 

The other allocation strategy included as part of the massbased approach in the proposed federal plan and model rule is a 

set-aside of allowances to be allocated to providers of 

incremental RE. A set-aside can also be allocated to providers 

of demand-side EE, or to both RE and demand-side EE. The 

increased availability of RE generation can serve as another 
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source of generation to satisfy electricity demand. Increased 

demand-side EE will reduce the demand that sources need to meet. 

Therefore, both RE and demand-side EE can serve to reduce the 

incentive that new sources have to generate, and therefore align 

their incentives with affected EGUs. Thus, increased RE and 

demand-side EE, supported by a dedicated set-aside, can also 

serve to address potential emission leakage. 

If a state is submitting a plan with an allocations 

approach that differs from that of the finalized model rule, the 

state should also provide a demonstration of how the specified 

allocation method will provide sufficient incentive to 

counteract potential emission leakage. 

Finally, a state can provide a demonstration that emission 

leakage is unlikely to occur, without implementing either of the 

two strategies above, as a result of unique factors, such as the 

presence of existing state policies addressing emission leakage 

or unique characteristics of the state and its power sector that 

will mitigate the potential for emission leakage. This 

demonstration must be supported by credible analysis. The EPA 

will determine if the state has provided a sufficient 

demonstration that potential emission leakage has already been 

adequately addressed, or if additional action is required as 

part of the state plan. 
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Aside from the possible incentives for emission leakage 

addressed in this section, there may be other potential 

generation incentives across states and unit subcategories that 

could increase CO2 emissions, particularly in an environment 

where various states are implementing a variety of state plan 

approaches in a shared grid region. Some examples of these 

incentives, particularly those that were specified by 

commenters, are discussed in section VIII.L. That section also 

describes how the EPA has structured this final rule to either 

prevent or minimize the potential for foregone emission 

reductions from differential incentives that may result from 

state plan implementation. These safeguards include placing 

restrictions on interstate trading when there could be a risk of 

such differential incentives. Additionally, the nature of the CO2

emission performance rates and state rate-based CO2 goals helps 

to minimize these potential effects, as does the MWh-accounting 

method for adjusting the CO2 emission rates of affected EGUs 

under rate-based plans. 

However, without a better understanding of the different 

mechanisms that states may ultimately choose to meet the 

emission guidelines, and how different requirements in different 

states may interact, the EPA cannot project every potential 

differential incentive that could lead to a loss of CO2 emission 
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reductions. Therefore, once program implementation begins, the 

EPA will assess how emission performance across states may be 

affected by the interaction of different regulatory structures 

implemented through state plans. Based upon that evaluation, the 

EPA will determine whether there are potential concerns and what 

course of action may be appropriate to remedy such concerns.

c. Emission budget trading programs that ensure achievement of a 

state CO2 goal. A mass-based emission budget trading program can 

be designed such that compliance by affected EGUs will achieve 

the state mass-based CO2 goal. Under this approach, a state plan 

would establish CO2 emission budgets for affected EGUs during the 

interim and final plan performance periods that are equal to or 

lower than the applicable state mass-based CO2 goals specified in 

section VII. A mass-based emission budget trading program can 

also be designed such that compliance by affected EGUs in 

conjunction with new fossil fuel-fired EGUs meeting applicable 

requirements under state law will achieve a mass-based CO2 goal 

plus new source CO2 emission complement. Under this approach, a 

state would establish CO2 emission budgets under state law for 

affected EGUs plus new sources during the interim and final plan 

performance periods that are equal to or lower than the 

applicable state mass-based CO2 emission goal plus the new source 

CO2 emission complement specified in Table 14 in section 
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VIII.J.2.b above, and describe such emission budgets in the 

supporting documentation of the state plan. Under either 

program, compliance periods for affected EGUs (or for affected 

EGUs plus new fossil fuel-fired EGUs meeting applicable 

requirements under state law) would also be aligned with the 

interim and final plan performance periods. This approach would 

limit total CO2 emissions from affected EGUs (or total CO2

emissions from affected EGUs and new fossil fuel-fired EGUs 

meeting applicable requirements under state law) during the 

interim and final plan performance periods to an amount equal to 

or less than the state’s mass-based CO2 goal (or mass-based CO2

goal plus new source CO2 emission complement). 

Under this approach, compliance by affected EGUs with the 

mass-based emission standards in a plan would ensure that the 

state achieves its mass-based CO2 goal for affected EGUs (or 

mass-based CO2 goal plus new source CO2 emission complement). No 

further demonstration would be necessary by the state to 

demonstrate that its plan would achieve the state’s mass-based 

CO2 goal (or mass-based CO2 goal plus new source CO2 emission 

complement). 

For this type of plan, where the emission budget is equal 

to or less than the state mass CO2 goal (or mass-based CO2 goal 
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plus new source CO2 emission complement),1175 the EPA would assess 

achievement of the state goal based on compliance by affected 

EGUs with the mass-based emission standards, rather than 

reported CO2 emissions by affected EGUs during the interim plan 

performance periods and final plan performance periods. This 

approach would allow for allowance banking between performance 

periods, including the interim and final performance periods 

outlined in this final rule. 

 Banking provisions have been used extensively in rate-based 

environmental programs and mass-based emission budget trading 

programs. This is because banking reduces the cost of attaining 

the requirements of the regulation. The EPA has determined that 

the same rationale and outcomes apply under a CO2 emission rate 

approach, in that allowing banking will reduce compliance costs. 

Banking encourages additional emission reductions in the nearterm if economic to meet a long-term emission rate constraint, 

which is beneficial due to social preferences for environmental 

improvements sooner rather than later. It is also beneficial 

when addressing pollutants that are long-lived in the 

atmosphere, such as CO2, and where increasing atmospheric 

 

1175 As specified for the interim plan performance period 

(including specified levels in interim steps 1 through 3) and 

the final two-year plan performance periods.
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concentration of the pollutant leads to increasing adverse 

atmospheric impacts. 

Banking also provides long-term economic signals to 

affected emission sources and other market participants where 

actions taken today will have economic value in helping meet 

tighter emission constraints in the future, provided those 

emission sources expect that the banked ERCs or emission 

allowances may be used for compliance in the future. Linking 

short-term and long-term economic incentives, which allows 

owners or operators of affected EGUs and other market 

participants to assess both short-term and long-term incentives 

when making decisions about compliance approaches or emission 

reduction investments, reduces long-term compliance costs for 

affected EGUs and ratepayer impacts. In addition, the increased 

temporal flexibility provided by banking would further help 

address potential electric reliability concerns, as banked ERCs 

can be used to meet emission standard requirements for an 

affected EGU. 

d. Addressing emission budget trading programs with broader 

source coverage and other flexibility features. As described in 

section VIII.C above, under the emission standards plan type, a 

mass-based emission budget trading program with broader source 

coverage and other flexibility features may be designed such 
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that compliance by affected EGUs (or compliance by affected EGUs 

plus new fossil fuel-fired EGUs meeting applicable requirements 

under state law) would assure achievement of the applicable 

state mass-based CO2 goal (or mass-based CO2 goal plus new source 

CO2 emission complement).1176 

 However, emission budget trading programs, including those 

currently implemented by California and the RGGI participating 

states, include a number of different design elements that 

functionally expand the emission budget under certain 

circumstances. If a state chose, it could apply such mass-based 

emission standards, in the form of an emission budget trading 

program that differs in design from that outlined in section 

VIII.J.2.c above. These types of emission budget trading 

programs must be submitted as a part of a state measures plan 

type. Where an emission budget trading program addresses 

affected EGUs and other fossil fuel-fired EGUs, the requirements 

that must be included in the state plan are the federally 

enforceable emission standards in the state plan that apply 

specifically to affected EGUs, and the requirements that 

specifically require affected EGUs to participate in and comply 

 

1176 Section VIII.J.2.a describes how state plan submittals must 

include as requirements, or describe as part of supporting 

documentation, relevant aspects of such emission budget trading 

programs.
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with the requirements of the emission budget trading program. 

This includes the requirement for an affected EGU to surrender 

emission allowances equal to reported CO2 emissions, and meet 

monitoring and reporting requirements for CO2 emissions, among 

other requirements. These requirements may be submitted as part 

of the federally enforceable state plan through mechanisms with 

the appropriate legal authority and effect, such as state 

regulations, relevant Title V permit requirements for affected 

EGUs, and other possible instruments that impose these 

requirements specifically with respect to affected EGUs.1177 Under 

this approach, the full set of regulations establishing the 

emission budget trading program that applies to affected EGUs 

and other fossil fuel-fired EGUs and other mission sources (if 

relevant) must be described as supporting documentation in the 

state plan submittal. This structure is appropriate to ensure 

that states with an emission budget trading program that 

addresses both affected EGUs and other fossil fuel-fired EGUs do 

not inappropriately submit requirements regarding entities other 

than affected EGUs for inclusion in the federally enforceable 

 

1177 This approach for establishing federally enforceable emission 

standards based on requirements for affected EGUs subject to a 

broader emission budget trading program that also covers nonaffected emission sources is addressed in section VIII.J.2.d. 

above. 
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state plan. 

 Such state programs could include a number of different 

design elements. This includes broader program scope, where a 

program includes other emission sources beyond affected EGUs 

subject to CAA section 111(d) and new fossil fuel-fired EGUs, 

such as industrial sources. Programs might also include design 

elements that make allowances available in addition to the 

established emission budget. This includes project-based offset 

allowances or credits from GHG emission reduction projects 

outside the covered sector and cost containment reserve 

provisions that make additional allowances available at 

specified allowance prices.1178 

In the case where an emission budget trading program 

contains elements that functionally expand the emission budget 

in certain circumstances, compliance by affected EGUs with the 

mass-based emission standards would not necessarily ensure that 

CO2 emissions from affected EGUs do not exceed the state’s massbased CO2 goal (or mass-based CO2 goal plus new source CO2

 

1178 For example, both the California and RGGI programs allow for 

the use of allowances awarded to GHG offset projects to be used 

to meet a specified portion of an affected emission source’s 

compliance obligation. The RGGI program contains a cost 

containment allowance reserve that makes available additional 

allowances up to a certain amount, at specified allowance price 

triggers. 
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emission complement). However, states could modify such programs 

to remove flexibility mechanisms that functionally expand the 

emission budget, such as out-of-sector offsets and certain cost 

containment reserve mechanisms, and submit the program under an 

emission standards plan type. 

Where a state chooses to retain such flexibility mechanisms 

as part of an emission budget trading program, the program may 

only be implemented as part of a state measures plan type 

because these state flexibility mechanisms would not assure CO2

emissions from affected EGUs do not exceed the state’s massbased CO2 goal (or mass-based CO2 goal plus new source CO2

emission complement). A description of the state measures plan 

type and related requirements is provided in section VIII.C.3. 

Under this type of approach, the state would be required to 

include a demonstration,1179 in its state plan submittal, of how 

its plan would achieve the state mass-based CO2 goal (or massbased CO2 goal plus new source CO2 emission complement). This 

demonstration would include a projection of the total CO2

emissions from the fleet of affected EGUs that would occur as a 

result of compliance with the emission standards in the plan. 

 

1179 A demonstration of how a plan will achieve a state’s ratebased or mass-based CO2 goal (or mass-based CO2 goal plus new 

source CO2 emission complement) is one of the required plan 

components, as described in section VIII.D.2. 
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Section VIII.D.2 discusses how such demonstrations could address 

design elements of emission budget trading programs with broader 

scope and additional compliance flexibility mechanisms, such as 

those included in the California and RGGI programs. Once the 

plan is implemented, if the mass-based CO2 goal is not achieved 

during a plan performance period, the backstop federally 

enforceable emission standards included in the state plan that 

apply to affected EGUs would be implemented, as described in 

section VIII.C.3.b.1180 

e. Considerations for mass-based emission budget trading 

programs. The EPA notes that while an emission budget trading 

program included in an emission standards plan must be designed 

to achieve a state mass-based CO2 goal (or mass-based CO2 goal 

plus new source CO2 emission complement), states have wide 

discretion in the design of such programs, provided the emission 

standards included in the plan are quantifiable, verifiable, 

 

1180 Achievement of the state mass-based CO2 goal would be 

determined based solely on stack CO2 emissions from affected 

EGUs. Where a state program includes the ability of an affected 

emission source to use GHG offsets to meet a portion of its 

allowance compliance obligation, no “credit” is applied to 

reported CO2 emissions by the affected EGU. The use of offset 

allowances or credits in such programs merely allows an affected 

EGU to emit a ton of CO2 in the amount of submitted offset 

allowances or credits. In all cases, there is no adjustment 

applied to reported stack emissions of CO2 from an affected EGU 

when determining compliance with its emission limit.
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enforceable, non-duplicative, and permanent. 

(1) Allowance allocation. A key example is state discretion in 

the CO2 allowance allocation methods included in the program.1181

This includes the methods used to distribute CO2 allowances and 

the parties to which allowances are distributed. For example, if 

a state chose, it could include CO2 allowance allocation 

provisions that provide incentives for certain types of 

complementary activities, such as RE generation, that help 

achieve the overall CO2 emission limit for affected EGUs 

established under the program. In addition, a state could use 

its allocation provisions to encourage investments in RE and 

demand-side EE in low-income communities. States could also use 

CO2 allowance allocation provisions to provide incentives for 

early action, such as RE generation or demand-side EE savings 

that occur prior to the beginning of the interim plan 

performance period in 2022. For example, a state could include 

CO2 allowance allocation provisions where CO2 allowances are 

distributed to RE generators based on MWh of RE generation that 

occurs prior to 2022. Such provisions might be addressed through 

a finite set-aside of CO2 allowances that are available for 

 

1181 Allowance allocation refers to the methods used to distribute 

CO2 allowances to the owners or operators of affected EGUs and/or 

other market participants. 
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allocation under these provisions. This set-aside could be 

additional to a set-aside created by the state for the CEIP 

discussed in section VIII.B.2. 

(2) Facility-level compliance. If a state chose, it could 

evaluate compliance (i.e., allowance true-up) under its emission 

budget trading program at the facility level, rather than at the 

individual unit level. The EPA has adopted facility-level 

compliance in the emission budget-trading programs it 

administers, including the Acid Rain Program (70 FR 25162), 

Clean Air Interstate Rule (70 FR 25162), and Cross-State Air 

Pollution Rule (76 FR 48208). Under this approach, states would 

still track reported unit-level CO2 emissions – while evaluating 

compliance at the facility level – allowing them to track 

increases and decreases of CO2 emissions at individual EGUs. 

3. Multi-state coordination: mass-based emission trading 

programs. 

An individual state may provide for the use of CO2

allowances issued by another state(s) for compliance with the 

mass-based emission standards in its plan. This type of state 

plan would include regulatory provisions that enable affected 

EGUs to use allowances issued in other states for compliance 

under the state’s emission budget trading program. This type of 

state plan must also indicate how CO2 allowances will be tracked 
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from issuance through use for compliance, through either a joint 

tracking system, interoperable tracking systems, or use of an 

EPA-administered tracking system.1182 

 Two different implementation approaches could be used to 

create such links. A state could submit a “ready-for-interstatetrading” plan using an EPA-approved tracking system, but the 

plan would not identify links with other states. A state could 

also submit a plan with specified bilateral or multilateral 

links that explicitly identify partner states. 

 Interstate allowance linkages would not affect the 

approvability of each state’s individual plan. However, 

different considerations apply for the approvability of an 

individual plan with such links, based on whether the emission 

budget trading program in the plan applies only to affected EGUs 

or includes other emission sources, and if the plan is designed 

to meet a state mass-based CO2 goal for affected EGUs only or to 

meet a mass-based CO2 goal plus a new source CO2 emission 

 

1182 The emission standards in each individual state plan must 

include regulatory provisions that address the issuance of CO2

allowances and tracking of CO2 allowances from issuance through 

use for compliance, as described in subsection 

VIII.C.3.b.(2)(c).. The description here addresses how those 

regulatory provisions will be implemented through the use of a 

joint tracking system, interoperable tracking systems, or an 

EPA-administered tracking system. 
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complement). 

 Under the first “ready-for-interstate-trading” 

implementation approach, a state would indicate in its state 

plan that its emission budget trading program will be 

administered using an EPA-approved (or EPA-administered) 

emission and allowance tracking system.1183 State plans using a 

specified EPA-approved tracking system would be deemed by the 

EPA as ready for interstate linkage upon approval of the state 

plan. No additional EPA approval would be necessary for states 

to link their emission budget trading programs, and affected 

EGUs in those states could engage in interstate trading 

subsequent to EPA plan approval. 

 A state would indicate in its plan submittal that its 

emission budget trading system will use a specified EPA-approved 

tracking system. The state would also indicate in the regulatory 

provisions for its emission budget trading program that it would 

recognize as usable for compliance any emission allowance issued 

by any other state with an EPA-approved state plan that also 

 

1183 The EPA would designate tracking systems that it has 

determined adequately address the integrity elements necessary 

for the issuance and tracking of emission allowances, as 

described in subsection VIII.C.5.c.(2).. Under this approach, a 

state could include in its plan such a designated tracking 

system, which has already been reviewed by the EPA. 
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uses the specified EPA-approved tracking system. 

 States could also adopt such a collaborative emission 

trading approach over time (through appropriate state plan 

revisions if the plan is not already structured as ready-forinterstate-trading), without requiring all of the original 

participating states to revise their EPA-approved plans. 

 Under the second implementation approach, a state could 

specify the other states from which it would recognize issued 

emission allowances as usable for compliance with its emission 

budget trading program. The state would indicate in the 

regulatory provisions for its emission budget trading program 

that emission allowances issued in other identified partner 

states may be used by affected EGUs for compliance. Such plans 

must indicate how allowances will be tracked from issuance 

through use for compliance, through either a joint tracking 

system, interoperable tracking systems, or EPA-administered 

tracking system. The EPA would assess the design and 

functionality of this tracking system(s) when reviewing 

individual submitted state plans. 

 Under this approach, states could also join such a 

collaborative emission trading approach over time. However, all 

participating states would need to revise their EPA-approved 

plans. If the expanded linkage is among previously approved 
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plans with mass-based emission standards, approval of the plan 

revision would be limited to assessing the functionality of the 

shared tracking system or interoperable tracking systems in 

order to maintain the integrity of the linked programs.1184 

a. Considerations for linked emission budget trading programs. 

For individually submitted plans, interstate emission allowance 

linkages would not affect the approvability of each state’s 

plan. However, approvability of an individual linked plan would 

differ based on the structure of the emission budget trading 

program included in the plan. These differences for plan 

approvability address distinctions among programs that include 

only affected EGUs and programs that cover a broader set of 

emission sources, as well as if the plan is designed to meet a 

state mass-based CO2 goal for affected EGUs only or to meet a 

mass-based CO2 goal plus a new source CO2 emission complement. 

Differences in approval criteria are necessary to ensure that 

each individual state plan demonstrates it will achieve a 

state’s mass-based CO2 emission goal for affected EGUs (or massbased CO2 goal plus new source CO2 emission complement). The 

 

1184 Depending on the specific regulatory provisions in the 

emission standards in their approved state plans, participating 

states may also need to revise their implementing regulations 

(and by extension their state plans) to accept CO2 emission 

allowances issued by new partner states as usable for compliance 

with their mass-based emission standards. 
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accounting applied to individual plans to assess whether a state 

achieves its mass-based CO2 goal (or mass-based CO2 goal plus new 

source CO2 emission complement) will also differ, based on 

whether an emission budget trading program includes only 

affected EGUs (or affected EGUs and applicable new fossil fuelfired EGUs) or a broader set of emission sources. These 

considerations are addressed below, for both types of emission 

budget trading programs. 

(1) Links among emission budget trading programs that only 

include affected EGUs or affected EGUs and applicable new fossil 

fuel-fired EGUs. Where the emission budget trading programs in 

each plan apply only to affected EGUs subject to the final rule 

(or emission budget trading programs that apply to affected EGUs 

under the state plan and applicable new fossil fuel-fired EGUs 

under state law), and include compliance timeframes for affected 

EGUs that align with the interim and final plan performance 

periods, both plans would functionally be meeting an aggregated 

multi-state mass-based goal (or aggregated mass-based CO2 goal 

plus new source CO2 emission complement), but without formally 

aggregating the goal (or aggregated mass-based CO2 goal plus new 

source CO2 emission complement). CO2 emissions from affected EGUs 

in both states could not exceed the total combined CO2 emission 

budgets under the emission standards in the two states. A net 
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“import” of CO2 allowances from one state would mean that 

allowable CO2 emissions in the other net “exporting” state are 

less than that state’s established emission budget. On a multistate basis, CO2 emissions from affected EGUs could not exceed 

the sum of the states’ emission budgets. 

 Under this approach, if the emission budget for the massbased emission standard in each plan is equal to or lower than 

the state’s mass-based CO2 goal (or aggregated mass-based CO2

goal plus new source CO2 emission complement, if applicable), 

compliance by affected EGUs with the mass emission standard in a 

state1185 would ensure that cumulatively the mass CO2 goals (or 

mass-based CO2 goals plus new source CO2 emission complements) of 

the linked states are achieved. As a result, achievement of an 

individual state’s mass CO2 goal (or mass-based CO2 goal plus new 

source CO2 emission complement) would be assessed by the EPA 

based on compliance by affected EGUs with the mass-based 

emission standards in the state plan, rather than reported CO2

emissions by affected EGUs in the state.1186

 

1185 Compliance by an affected EGU with the emission standard is 

demonstrated based on surrender to the state of a number of CO2

allowances equal to its reported CO2 emissions. 1186 This approach is warranted because under such linked 

programs, CO2 emissions from affected EGUs in one state that 

exceed a state’s mass CO2 goal (or mass-based CO2 goal plus new 

source CO2 emission complement) would be accompanied by CO2
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 The same accounting approach will apply for such plans in 

all cases, even if the state is linked to another state emission 

budget trading program that includes a broader set of emission 

sources (e.g., sources beyond affected EGUs, or beyond affected 

EGUs plus applicable new fossil fuel-fired EGUs), as described 

below. In all cases, where a state plan includes an emission 

budget trading program that applies only to affected EGUs (or 

beyond affected EGUs plus applicable new fossil fuel-fired 

EGUs), and includes compliance timeframes that align with plan 

performance periods, achievement of a state mass CO2 goal (or 

mass-based CO2 goal plus new source CO2 emission complement) will 

be assessed by the EPA based on whether affected EGUs comply 

with the mass-based emission standard, rather than reported CO2

emissions from affected EGUs. 

(2) Links with emission budget trading programs that include a 

broader set of emission sources. State plans may involve 

emission budget trading programs that include affected EGUs, 

applicable new fossil fuel-fired EGUs if a plan includes a new 

source CO2 emission complement, and other non-affected emission 

 

emissions from affected EGUs in another linked state that are 

below that state’s mass CO2 goal (or mass-based CO2 goal plus new 

source CO2 emission complement). 
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sources.1187 

 Generally, such plans must demonstrate that the mass-based 

CO2 goal for affected EGUs (or mass-based CO2 goal plus new 

source CO2 emission complement) in a state will be achieved, as a 

result of implementation of the emission budget trading 

program.1188 Where a program includes other non-affected emission 

sources (i.e., non-affected emission sources that are not 

subject to a new source CO2 emission complement) and is linked 

with other programs,1189 the state plan submittal must include a 

demonstration that the mass-based CO2 goal (or mass-based CO2

goal plus new source CO2 emission complement) will be achieved, 

considering the emission allowance links with other programs. 

 

1187 This may apply under both an emission standards plan and a 

state measures plan. Section VIII.J.2.a describes how state plan 

submissions must include as requirements, or describe as part of 

supporting documentation, relevant aspects of such emission 

budget trading programs. 

1188 Under a program that applies to affected EGUs and other 

emission sources, compliance by affected EGUs with the emission 

standard – a requirement to surrender emission allowances equal 

to reported emissions – will not assure that a state’s CO2 mass 

goal (or mass-based CO2 goal plus new source CO2 emission 

complement) is achieved. As a result, a further demonstration is 

required in the plan that compliance by affected EGUs with the 

program will result in CO2 emissions from affected EGUs that are 

at or below a state’s CO2 mass goal (or mass-based CO2 goal plus 

new source CO2 emission complement). 1189 Section VIII.J.2.a describes how state plan submittals must 

include as requirements, or describe as part of supporting 

documentation, relevant aspects of such emission budget trading 

programs.
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The EPA, in determining the approvability of each state’s plan 

under this approach, would evaluate the linkages between plans. 

Specifically, the EPA would evaluate whether the linkages would 

enable the affected EGUs (or affected EGUs in conjunction with 

applicable new fossil fuel-fired EGUs) in each participating 

state to meet the state’s applicable mass-based CO2 goal (or 

mass-based CO2 goal plus new source CO2 emission complement). 

 During plan implementation, the EPA would assess whether 

the affected EGUs in a state achieved the state’s mass-based CO2

goal (or mass-based CO2 goal plus new source CO2 emission 

complement) as follows. Reported CO2 emissions from affected EGUs 

under such plans must be at or below a state’s mass-based CO2

emission goal (or mass-based CO2 goal plus new source CO2

emission complement) during an identified plan performance 

period, with the following state accounting adjustments for net 

“import” and net “export” of CO2 allowances: 

 Net “imports” of CO2 allowances: Reported CO2 emissions from 

affected EGUs in a state may exceed the state CO2 mass goal 

(or mass-based CO2 goal plus new source CO2 emission 

complement) during an identified plan performance period in 

the amount of an adjustment for the net “imported” CO2

allowances during the plan performance period. The 

adjustment represents the CO2 emissions (in tons) equal to 
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the number of net “imported” CO2 allowances.1190 Under this 

adjustment, such allowances must be issued by a state with 

an emission budget trading program that only applies to 

affected EGUs (or affected EGUs plus applicable new fossil 

fuel-fired EGUs). Net “imports” of allowances are 

determined through review of tracking system compliance 

accounts. 

 Net “exports” of CO2 allowances: Reported CO2 emissions from 

affected EGUs in a state during an identified plan 

performance period must be equal to or less than the CO2

mass goal (or mass-based CO2 goal plus new source CO2

emission complement) minus an adjustment for the “exported” 

CO2 allowances during the plan performance period. The 

adjustment represents CO2 emissions (in tons) equal to the 

number of net “exported” CO2 allowances. Net “exports” of 

allowances are determined through review of tracking system 

compliance accounts. 

 Where CO2 emissions from affected EGUs exceed these levels 

(based on reported CO2 emissions with applied plus or minus 

adjustments for net CO2 allowance “imports” or “exports”) over 

the 8-year interim period or during any final plan reporting 

 

1190 Net “imports” and “exports” of CO2 allowances are defined and 

explained below. 
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period, or by 10 percent or more during the interim step 1 or 

step 2 periods, a state would be considered to, in the case of 

the interim and final periods, not have met its CO2 mass goal 

during an identified plan performance period, and in the case of 

the interim step periods, to not be on course to meet the final 

goal. As a result, under a state measures state plan, 

implementation of the backstop federally enforceable emission 

standards for affected EGUs in the state plan would be 

triggered. 

 A net transfer of CO2 allowances during a plan 

performance period represents the net number of CO2 allowances 

(issued by a respective state) that are transferred from the 

compliance accounts of affected EGUs in that state to the 

compliance accounts of affected EGUs in another state.1191 This 

 

1191 A net transfer metric is applied as of the end of the plan 

performance period. This net accounting as of a specified date 

is necessary because multiple individual allowance transfers may 

occur among accounts during a plan performance period, 

representing normal trading activity. In addition, net transfers 

are based on compliance account holdings, because these 

represent the CO2 allowances directly available at that point in 

time for use by an affected EGU for complying with its emission 

limit. Emission budget trading programs typically allow nonaffected entities to hold allowances in general accounts. These 

parties are free to hold and trade CO2 allowances, providing 

market liquidity. General account holdings are not assessed as 

part of a periodic state net transfer accounting, as these 

allowances may subsequently be transferred to other accounts in 

multiple states and do not represent allowances currently held 
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net transfer is determined based on compliance account holdings 

at the end of the plan performance period.1192 For example, assume 

two states, State A and State B, with emission budgets of 1,000 

tons of CO2. Each state issues 1,000 CO2 allowances. At the end 

of a plan performance period, affected EGUs in State A 

collectively hold 500 CO2 allowances in their compliance accounts 

that were issued by State A. Affected EGUs in State B 

collectively hold in their compliance accounts 500 CO2 allowances 

issued by State A and 1,000 CO2 allowances issued by State B. In 

this simplified example, a net transfer of 500 CO2 allowances has 

occurred between State A and State B. State A has “exported” 500 

CO2 allowances to State B, while State B has “imported” 500 CO2

allowances from state A.and quality control measures. The EPA 

will review the appropriateness and basis for such 

determinations and accounting measures in the course of its 

review of a state plan. 

 An affected EGU using qualifying biomass as a fuel must 

monitor and report both its overall CO2 emissions and its 

 

by an affected EGU that can be used for complying with its 

emission limit. 

1192 Compliance account holdings, as used here, refer to the 

number of CO2 allowances surrendered for compliance during a plan 

performance period, as well as any remaining CO2 allowances held 

in a compliance account as of the end of a plan performance 

period. 
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biogenic CO2 emissions. If biomass is to be used as an emission 

reduction measure in a state plan, the plan must specify 

requirements for reporting biogenic CO2 emissions from affected 

EGUs. Reporting requirements for biogenic CO2 emissions under 40 

CFR 98(§§ 98.3(c), 98.36(b)-(d), 98.43(b), and 98.46) are an 

acceptable default reporting approach that would be approvable 

when combined with other state plan components. However, the EPA 

may approve other approaches included in a state plan. 

(iii) Biomass repowering. Affected EGUs could fully repower to 

use primarily qualifying biomass. The characteristics of 

affected sources, as discussed in Section IV.D., include the use 

of at least 10 percent fossil fuel for applicability of these 

emission guidelines. An EGU repowering with at least 90 percent 

biomass fuels instead of fossil fuels becomes a non-affected 

EGU.1193 An EGU repowering with less than 90 percent biomass would 

remain an affected EGU and provide a reduction option similar to 

that described earlier in this section, with the same processes 

for proposing qualified biomass feedstocks or feedstock 

categories and biogenic CO2 emissions evaluation, monitoring and 

 

1193 For such an EGU to be considered non-affected, the EGU 

shouldmust be subject to a federally enforceable or practically 

enforceable condition, expressed in (for example) a construction 

permit or otherwise, that limits the amount of fossil fuel that 

may be used to 10 percent or less. 
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reporting requirements. Entities switching to significantly 

higher amounts of biomass use may be subject to other permitting 

requirements outside of this rule. 

b. Actions 

K. Additional Considerations and Requirements for Rate-Based 

State Plans 

 This section discusses considerations and requirements for 

rate-based state plans. This section discusses eligibility, 

accounting, and quantification and verification requirements 

(EM&V) for the use of CO2 emission reduction measures that 

provide substitute generation for affected EGUs or avoid the 

need for generation from affected EGUs in rate-based state 

plans. These measures may be used to adjust the CO2 emission rate 

of an affected EGU under a rate-based state plan. This 

adjustment may occur when an affected EGU is demonstrating 

compliance with a rate-based emission standard, or when a state 

is demonstrating achievement of the CO2 emission performance 

rates or applicable rate-based state CO2 emission goal in the 

emission guidelines. This section also discusses requirements 

for state plans that include rate-based emission trading 

programs, including approaches and requirements for coordination 

among such programs where states retain individual state ratebased CO2 emission goals. 
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1. Adjustments to CO2 emission rates in rate-based state plans 

Section VIII.K.1.a below describes the basic accounting 

method for adjusting a CO2 emission rate, as well as eligibility 

requirements for measures that may be used for adjusting a CO2

emission rate. Section VIII.K.1.b addresses measures that may 

not be used to adjust the CO2 emission rate of an affected EGU in 

a state plan, and explains the basis for this exclusion. Section 

VIII.K.1.c addresses measures that reduce CO2 emissions outside 

the electric power sector. Such measures may not be counted 

under either a rate-based or mass-based state plan. 

a. Measures taken to adjust the CO2 emission rate of an affected 

EGU. This section describes how measures that substitute for 

generation from affected EGUs or avoid the need for generation 

from affected EGUs may be used in a state plan to adjust the CO2

emission rate of an affected EGU. This section discusses the 

required accounting method for adjusting a CO2 emission rate, as 

well as general eligibility requirements that apply to different 

categories of measures that may be used to adjust a CO2 emission 

rate. Where relevant, this section also discusses additional 

specific accounting methods and other relevant requirements that 

apply to different categories of measures. 

A CO2 emission rate adjustment may be applied in different 

rate-based state plan contexts. For example, in a rate-based 
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emission trading program, adjustments may be applied through the 

use of ERCs.1194 Alternatively, under a state measures plan that 

does not employ rate-based trading, adjustments may be applied 

by the state to the reported CO2 emission rate of the affected 

fleet of EGUs. Regardless of the type of plan in which an 

adjustment is applied, the same basic accounting and general 

eligibility requirements described in this section will apply. 

 As discussed in this section, a wide range of actions may 

be taken to adjust the reported CO2 emission rate of an affected 

EGU in order to meet a rate-based emission standard and/or 

demonstrate achievement of a state CO2 rate-based emissions goal. 

All of the measures described in this section will substitute 

for generation from affected EGUs or avoid the need for 

generation from affected EGUs, thereby reducing CO2 emissions. 

This includes RE measures included in the EPA’s determination of 

the BSER, as well as other measures that were not included in 

the determination of the BSER, such as other RE resources, 

demand-side EE, CHP, WHP, electricity transmission and 

 

1194 ERCs may be issued for the measures presented in this 

section, as well as to affected EGUs that emit at a CO2 emission 

rate below their assigned emission rate limit. ERC issuance and 

trading is discussed in detail in section VIII.GK.2. That 

section addresses the accounting method for ERC issuance to 

affected EGUs that perform below their assigned CO2 emission 

rate. 
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distribution improvements, nuclear energy, and international 

energy imports.RE imports connected to the grid in the 

contiguous U.S., as discussed elsewhere in this preamble. 

 The EPA believes that the broad categories of measures 

listed in this section address the wide range of actions that 

are available to reduce CO2 emissions from affected EGUs under a 

rate-based state plan. However, the actions that a state could 

include in a rate-based state plan are not necessarily limited 

to those described in this section. Other specific actions not 

listed here may be incorporated in a state plan, provided they 

meet the general eligibility requirements listed in this 

section, as well as the other relevant requirements in the 

emission guidelines.1195 Nor are states required to include in 

their plans all of the actions that are described in this 

section. 

This section discusses the basic accounting method for 

adjusting the reported CO2 emission rate of an affected EGU, 

through the use of measures that substitute for or avoid 

generation from affected EGUs. That method is based on adding 

MWh from such measures to the denominator of an affected EGU’s 

reported CO2 emission rate. (lb CO2/MWh). Those additional MWh 

 

1195 These requirements are discussed in section VIII.D. 
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are based on quantified and verified electricity generation or 

electricity savings from eligible measures. 

This section also addresses general eligibility 

requirements for resources that are used to adjust, and in the 

case of an affected EGU’s CO2 emission rate. Specific eligibility 

and accounting methods that apply in order to determine MWh 

generation or savings from different types of resources are also 

addressed, where relevant, including for:compliance with its 

emission standard, are reflected in ERCs. This section also 

addresses eligibility requirements for resources that are used 

to adjust an affected EGU’s CO2 emission rate. 

 hydropower; 

 biomass; 

 waste-to-energy; 

 demand-side EE and other efficiency measures; 

 transmission and distribution (T&D) measures that 

increase T&D efficiency or reduce electricity end-use; 

 CHP at non-affected sources; 

 waste heat to power (WHP); and 

 nuclear power. 

(1) General accounting approach for adjusting a CO2 emission 

rate. 
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In this final rule, the reported CO2 emission rate of an 

affected EGU may be adjusted based on quantified and verified 

MWh from qualifying zero-emitting and low-emitting resources, as 

described in sections VIII.GK.1.ba.(2)-(910) below. These MWh 

are added to the denominator of an affected EGU’s reported CO2

emission rate, resulting in a lower adjusted CO2 emission rate. 

 The measures described in these sections reduce mass CO2

emissions from affected EGUs by substituting zero- or lowemitting generation for generation from affected EGUs, or by 

avoiding the need for generation altogether (in the case of 

resources that lower electricity demand through improved demandside EE and DSM). In both of these cases, generation from an 

affected EGU is replaced, through substitute generation or a 

reduction in electricity demand. To the extent that qualifying 

zero-emitting and low-emitting resources result in reduced 

generation and CO2 emissions from an individual affected EGU, 

those emission impacts are reflected in lower reported CO2

emissions and a reduction in MWh generation from the affected 

EGU. demand-side management). In both of these cases, generation 

from an affected EGU is replaced, through substitute generation 

or a reduction in electricity demand. To the extent that 

qualifying zero-emitting and low-emitting resources result in 

reduced generation and CO2 emissions from an individual affected 
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EGU, those emission impacts are reflected in lower reported CO2

emissions and a reduction in MWh generation from the affected 

EGU. However, while there will be a reduction in CO2 emissions at 

the affected EGU, the fact that both CO2 emissions and MWh 

generation are reduced means that such impacts do not alter the 

reported CO2 emission rate of the affected EGU. As a result, the 

MWh of replacement generation must be added to the denominator 

of the reported CO2 emission rate, in order to represent those 

impacts in the form of an adjusted CO2 emission rate. In this 

manner, adding MWh from these resources to the denominator of an 

affected EGU’s CO2 emission rate allows mass CO2 emission 

reductions from these measures to be fully reflected in an 

adjusted CO2 emission rate. 

 The following provides a simple calculation example of how 

MWh of replacement generation added to the denominator of an 

affected EGU’s reported CO2 emission rate results in a lower 

adjusted CO2 emission rate. Assume an affected EGU with CO2

emissions of 200,000 lb and electric generation of 100 MWh 

during a reporting period. The affected EGU’s reported CO2

emission rate is 2,000 lb/MWh (200,000 lb CO2/100 MWh = 2,000 

lb/MWh). When complying with its rate-based emission limit, the 

affected EGU submits 10 ERCs, representing 10 MWh of replacement 
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generation.1196 Adding 10 MWh of replacement generation to the 

reported MWh generation of the affected EGU results in an 

adjusted CO2 emission rate of 1,818 lb CO2/MWh (200,000 lb 

CO2/110 MWh = 1,818 lb CO2/MWh). 

 In the case of rate-based CO2 emission standards, an 

affected EGU demonstrates compliance with the emission standards 

if the affected EGU’s adjusted CO2 emission rate calculated in 

the aforementioned manner is less than or equal to the 

applicable CO2 emission standard rate.1197 The CO2 emission 

performance rates or rate-based CO2 goal in the emission 

guidelines are met if the adjusted CO2 emission rate of affected 

EGUs in a state is at or below the specified CO2 emission rate in 

a state plan that applies for an identified plan performance 

period. 

Numerous commenters requested that the EPA ensure consistency 

between goal-setting calculations and the methodology used to 

demonstrate achievement of a CO2 emission rate under a state 

plan. This approach for adjusting a CO2 emission rate corresponds 

with how RE, the one component of the BSER that involves 

 

1196 Requirements for the issuance of ERCERCs and a further 

discussion of how ERCs are used in compliance with rate-based 

emission limits are addressed in section VIII.G.3K.2. 

1197 Any ERCs used to adjust a CO2 emission rate must meet 

requirements in the emission guidelines, which are described in 

section VIII.D. 
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adjustment of a CO2 emission rate, is represented in the CO2

emission performance rates in the emission guidelines. EGU CO2

emission rate allows mass CO2 emission reductions from these 

measures to be fully reflected in an adjusted CO2 emission rate. 

 The following provides a simple calculation example of how 

MWh of replacement generation added to the denominator of an 

affected EGU’s reported CO2 emission rate results in a lower 

adjusted CO2 emission rate. Assume an affected EGU with CO2

emissions of 200,000 lb and electric generation of 100 MWh 

during a reporting period. The affected EGU’s reported CO2

emission rate is 2,000 lb/MWh (200,000 lb CO2/100 MWh = 2,000 

lb/MWh). When complying with its rate-based emission limit, the 

affected EGU submits 10 ERCs, representing 10 MWh of replacement 

generation.1198 Adding 10 MWh of replacement generation to the 

reported MWh generation of the affected EGU results in an 

adjusted CO2 emission rate of 1,818 lb CO2/MWh (200,000 lb 

CO2/110 MWh = 1,818 lb CO2/MWh). 

 In the case of rate-based CO2 emission standards, an 

affected EGU demonstrates compliance with the emission standards 

if the affected EGU’s adjusted CO2 emission rate calculated in 

 

1198 Requirements for the issuance of ERCERCs and a further 

discussion of how ERCs are used in compliance with rate-based 

emission limits are addressed in section VIII.G.3K.2. 
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the aforementioned manner is less than or equal to the 

applicable CO2 emission standard rate.1199 In the case of a state 

measures plan, quantified and verified MWh from eligible state 

measures are used by the state to administratively adjust the 

reported CO2 emission rate of affected EGUs in the aforementioned 

manner. The CO2 emission performance rates or rate-based CO2 goal 

in the emission guidelines are met if the adjusted CO2 emission 

rate of affected EGUs in a state is at or below the specified CO2

emission rate in a state plan that applies for an identified 

plan performance period. 

Numerous commenters requested that the EPA ensure 

consistency between goal-setting calculations and the 

methodology used to demonstrate achievement of a CO2 emission 

rate under a state plan. This approach for adjusting a CO2

emission rate corresponds with how RE, the one component of the 

BSER that involves adjustment of a CO2 emission rate, is 

represented in the CO2 emission performance rates in the emission 

guidelines. Specifically, in the calculation of final CO2

emission performance rates, the MWhMWhs of RE are reflected in 

two adjustments of the rate: a reduction of CO2 emissions from 

 

1199 Any ERCs used to adjust a CO2 emission rate must meet 

requirements in the emission guidelines, which are described in 

section VIII.D. 
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affected EGUs in the numerator and a one-to-one replacement of 

affected EGU generation in the denominator, where it is assumed 

that replaced generation from an affected EGU is subtracted from 

the denominator and the same number of zero-emitting MWh are 

added.1200 

 When demonstrating achievement of a CO2 emission performance 

rate, the reported CO2 emissions already reflect the actual 

emission reductions from the deployment of qualifying nonzeroemitting and low-emitting resources across the regional grid; a 

further adjustment of CO2 emissions would double count CO2

emissions impacts across the grid. Consistent with the EPA’s 

calculation of the CO2 emission performance rates and state ratebased CO2 goals in the emission guidelines, the zero-emitting 

MWhs (from substitute generation or a reduction in electricity 

demand) must still be added to the denominator of a reported CO2

emission rate to calculate an adjusted CO2 emission rate that 

appropriately reflects the replaced generation. Thus, the 

resultant rate, where the numerator reflects CO2 emission 

reductions from qualifying measures, and the denominator 

reflects replaced generation, is consistent with the goal-

 

1200 For a detailed discussion of this method, see Section VI.C.3. 

Form of the Performance Rates, in the Equation 

subsectionsection. 
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setting calculation. 

Several commenters suggested that the EPA consider the 

regional nature of the electricity grid and how RE and demandside EE impacts generation and CO2 emissions across the grid when 

accounting for the impacts of RE and demand-side EE measures in 

a rate-based plan approach. This MWh accounting structure 

corresponds with the regional treatment of RE resources in the 

BSER that provide substitute generation in the EPA-calculated CO2

emission performance rates in the emission guidelines. 

Consistent with assumptions used in calculating the CO2 emission 

performance rates in the emission guidelines, affected EGUs and 

states can take full credit for the MWh resulting from eligible 

measures they are responsible for deploying, no matter where 

those measures are implemented. CO2 emission reductions from the 

eligible measures may occur across the region; however, an 

affected EGU or a state may only take credit for avoided CO2

emissions at that affected EGU or set of EGUs in question, as 

reflected in the reported stack CO2 emissions of affected EGUs. 

Because of the separate accounting of MWhs and CO2

emissions, with emission impacts inherent in reported stack CO2

emissions and zero-emitting MWh impacts requiring explicit 

adjustments, the accounting method corresponds with the use of 

MWh-denominated ERCs in the rate-based emission trading 
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framework specified in this rule. The accounting method only 

requires a quantification of the MWh generated or avoided by an 

eligible measure, and thus credits or adjustments can be 

denominated in MWh and do not need to represent an approximation 

of the CO2 emission reductions that result from those MWhs. This 

creates a crediting system or rate adjustment process that is 

simpler to implement than one that requires an approximation of 

avoided CO2 emissions. 

The MWh accounting method also creates a crediting system 

or rate adjustment process that is indifferent to the rate-based 

CO2 emission goals of individual states, or the specific CO2

emission rate standards that states may apply, and the relative 

stringency of those goals or standards. Use of ERCs in ratebased emission trading programs is addressed in detail in 

section VIII.K.2. As a result, the MWh accounting method

addresses interstate effects, because it inherently accounts for 

how generation replacement and CO2 emission reduction impacts may 

cross state borders. For example, if the accounting method was 

informed by avoided CO2 emission rates, it could create perverse 

incentives for development of zero- or low-emitting resources in 

states that result in the greatest calculated estimate of CO2

emission reductions for each replacement MWh. Instead, this 

accounting method is indifferent to avoided CO2 emission rates 
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and creates the same number of zero-emitting credits or 

adjustment for each MWh of energy generation or savings, 

wherever they occur. For a detailed discussion on how the 

accounting method addresses interstate effects, see section 

VIII., however, an affected EGU or a state may only take credit 

for avoided CO2 emissions at that affected EGU or set of EGUs in 

question, as reflected in the reported stack CO2 emissions of 

affected EGUs. 

Because of the separate accounting of MWhs and CO2

emissions, with emission impacts inherent in reported stack CO2

emissions and zero-emitting MWh impacts requiring explicit 

adjustments, the accounting method corresponds with the use of 

MWh-denominated ERCs in the rate-based emission trading 

framework specified in this rule. The accounting method only 

requires a quantification of the MWh generated or avoided by an 

eligible measure, and thus credits or adjustments can be 

denominated in MWh and do not need to represent an approximation 

of the CO2 emission reductions that result from those MWhs. This 

creates a crediting system or rate adjustment process that is 

simpler to implement than one that requires an approximation of 

avoided CO2 emissions. 

The MWh accounting method also creates a crediting system 

or rate adjustment process that is indifferent to the rate-based 
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Page 1608 of 2153

CO2 emission goals of individual states, or the specific CO2

emission rate standards that states may apply, and the relative 

stringency of those goals or standards. Use of ERCs in ratebased emission trading programs is addressed in detail in 

section VIII.G.3. 

This MWh accounting method also addresses interstate 

effects, because it inherently accounts for how generation 

replacement and CO2 emission reduction impacts may cross state 

borders. For example, if the accounting method was informed by 

avoided CO2 emission rates, it could create perverse incentives 

for development of zero- or low-emitting resources in states 

that result in the greatest calculated estimate of CO2 emission 

reductions for each replacement MWh. Instead, this accounting 

method is indifferent to avoided CO2 emission rates and creates 

the same number of zero-emitting credits or adjustment for each 

MWh of energy generation or savings, wherever they occur. For a 

detailed discussion on how the accounting method addresses 

interstate effects, see section VIII.G.2. 

L. 

(2) General eligibility requirements for resources used to 

adjust a CO2 emission rate. 

The EPA is finalizing certain general eligibility 

requirements for resources used to adjust a CO2 emission rate. 
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These requirements align eligibility with certain factors and 

assumptions used in establishing the BSER, and by extension, 

application of the BSER to the performance levels established 

for affected EGUs in the emission guidelines, as well as state 

rate and mass CO2 goals. TheseAs a result, the requirements are 

appropriate, as they align ensure that measures that may be used 

in a state plan are treated consistently (to the extent 

possible) with the EPA’s assessment of the BSER.1201 These general 

requirements also address potential interactions among rate and 

mass plans, as discussed more fully in section VIII.G.2L. 

 As discussed in the subsectionssections that follow, the 

general eligibility criteria address: 

 the date from which eligible measures may be installed 

(e.g., installation of RE generating capacity and 

installation of EE measures); 

 the date from which MWh from eligible measures may be 

counted, and applied toward adjusting a CO2 rate; and

 the date from which eligible measures may be installed 

(e.g., installation of RE generating capacity and 

 

1201 For example, eligibility requirements include installation 

dates for eligible RE measures that may be used in a state plan. 

These dates generally align with the dates used for broadly 

defining incremental RE resources that were considered in 

establishing the BSER. 
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Page 1610 of 2153

installation of EE measures); and 

 the need to demonstrate that eligible measures replace or 

avoid generation from affected EGUs. 

(a) Eligibility date for installation of RE/EE and other 

measures and MWh generation and savings. Electricity generation 

and electricity savings that occur 

Incremental emission reduction measures, such as RE and 

demand-side EE, can be recognized as part of state plans, but 

only for the emission reductions they provide during a plan 

performance period may be applied to adjust a CO2 emission rate..

Specifically, this means that anymeasures installed in any year 

after 2012 are considered eligible measures under this final 

rule, but only the quantified and verified MWh of electricity 

generation or electricity savings that occurthey produce in 2022 

and future years, from an eligible measure, may be applied 

toward adjusting a CO2 emission rate. The eligible measures 

themselves may be installed in any year after 2012, as described 

below.1202 For example, For example, MWh generation in 2022 from a 

wind turbine installed in 2013 may be applied toward adjusting a 

CO2 emission rate. This 2012 date applies to all eligible 

 

1202 For demand-side EE, this eligibility date may require special 

considerations for EM&V plans. EM&V requirements are addressed 

in subsection VIII.C.3. 
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measures that are used to adjust a CO2 emission rate under a 

state plan. For example, eligible measures, such as CHP, nuclear 

power and DSM, also must be installed after 2012, but only their 

generation or savings produced in 2022 and after can be used to 

adjust a CO2 emission rate.

Further, asAs discussed in section VIII.C.2.a, a MWh of 

generation or savings that occurs in 2022 or a subsequent year 

may be carried forward (or “banked”) and applied in a future 

year. For example, a MWh of RE generation that occurs in 2022 

may be applied to adjust a CO2 emission rate in 2023 or future 

years, without limitation.1203 These MWh may be banked from the 

interim to final compliance periods. 

The EPA notes that states can submit a rate-based state 

plan that encourages early action by allowing MWhs generated 

from 2013-2021 to be used to adjust the CO2 rate of affected EGUs 

during the plan performance period (2022 and subsequent years). 

In order for this type of provision to be approvable in a state 

plan, it must meet certain conditions. These MWhs must be from 

eligible measures implemented after 2012. The state must provide 

provisions for adjustment of CO2 emission performance rates or 

rate-based state CO2 goals (applied during the plan performance 

 

1203 Similarly, as discussed in section VIII.C.2.b.(2).(a), 

allowances may be banked in a mass-based trading program. 
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periods in 2022 and future years) downward based upon the number 

of MWhs that are issued from 2013-2021, such that the level of 

emission reductions is equivalent to or more stringent than that 

which would have been achieved had eligible MWh been limited to 

those generated during the plan performance periods in 2022 and 

future years. This downward adjustment of CO2 emission 

performance rates or rate-based state CO2 goals must be 

calculated based upon a projection of total CO2 emissions, total 

MWh generation from affected EGUs, and total ERCs that would 

have been used to demonstrate compliance if the state had 

elected to meet the CO2 emission performance rates or rate-based 

state CO2 goals using only eligible MWh issued in 2022 and 

subsequent years. 

(b) Eligibility date for installation of RE/EE and other 

measures. RE generating capacity and demand-side EE measures 

that are installed after 2012 are eligible for use in adjusting 

a CO2 emission rate. This aligns with treatment of RE in the 

BSER. Other eligible measures, such as CHP, nuclear power and 

DSM, also must be installed after 2012. This 2012 date applies 

consistent eligibility requirements to all forms of zero- and 

low-emitting eligible generating capacity that may be used to 

adjust a CO2 emission rate. As described above, only the MWh of 

energy savings that occur in 2022 and subsequent years as a 
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result of these measures may be applied toward adjusting a CO2

emission rate. 

This eligibility date criterion is consistent with the date 

of installation for “incremental” RE capacity that is included 

in the BSER building block 3, which is the basis for RE MWh 

incorporated in the CO2 emission performance rates for affected 

EGUs in the emission guidelines. For more information on RE in 

the BSER, see section V.E. Many commenters asserted that 

proposed state goals did not sufficiently account for actions 

states take that reduce CO2 emissions prior to the first plan 

performance period, and therefore requested that MWhs of 

electricity generation or electricity savings that occur prior 

to the first plan performance period be eligible to apply toward 

adjusting the CO2 emission rates of affected EGUs. 

Many commenters asserted that proposed state goals did not 

sufficiently account for actions states take that reduce CO2

emissions prior to the first plan performance period, and 

therefore requested that MWhs of electricity generation or 

electricity savings that occur prior to the first plan 

performance period be eligible to apply toward adjusting the CO2

emission rates of affected EGUs. The EPA recognizes the 

importance of early state action as the basis for significant CO2

emission reductions and as a key part of enabling state plans to 
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achieve the CO2 emission performance levels or state CO2 goals. 

The EPA recognizes the importance of early state action as 

the basis for significant CO2 emission reductions and as a key 

part of enabling state plans to achieve the CO2 emission 

performance levels or state CO2 goals. The ability to count 

eligible measures installed in 2013 and subsequent years for the 

MWhs they generate during a plan performance period provides 

significant recognition for early action, corresponding with the 

BSER framework that is based on cost-effective actions that many 

sources are already doing, while still conforming to CO2

performance rates and state goals that are forward-looking. In 

order to provide additional incentives for early investment in 

RE and demand-side EE, the EPA is also establishing the CEIP, as 

discussed in section VIII.B.2. ERCs distributed by states and 

the EPA through this program may also be used by affected EGUs 

to demonstrate compliance with an emission standard, and may be 

banked from the interim to final periods. 

Commenters concerns about treatment of early actions are 

further addressed by changes from proposal to the BSER 

assumptions and the methodology used by the EPA to establish the 

CO2 emission performance levels and rate-based state CO2 goals in 

the emission guidelines. The specifics of these changes are 

addressed in section V.A.3. Three examples of those changes are 
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provided below. 

First, affected EGUs that have maximized their CO2 emission 

reduction opportunities available through early action will be 

better positioned to meet the BSER Commenters concerns about 

treatment of early actions are further addressed by changes from 

proposal to the BSER assumptions and the methodology used by the 

EPA to establish the CO2 emission performance levels and ratebased state CO2 goals in the emission guidelines. The specifics 

of these changes are addressed in section V.A.3. Three examples 

of those changes are provided below. 

First, affected EGUs that have maximized their CO2 emission 

reduction opportunities available through early action will be 

better positioned to meet the BSER technology-source specific CO2

emission rate that is uniformlyperformance rates or state goal

applied to all affected EGUs in a technology categorytheir 

state. For example, a steam generating unit that has already 

reduced its CO2 emission rate through a heat rate improvement may 

have a CO2 emission rate of 2,000 lb/MWh whereas its rate was 

2,100 lb/MWh prior to the improvement. Therefore, it has less 

distance to cover to meet the technology-specificits CO2 emission 

performance rate for steam generating units finalized in this 

action. 

Second, generation from existing RE capacity installed 
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prior to 2013 has been excluded from the EPA’s calculation of 

the CO2 emission performances rates in the emission guidelines. 

Second, generation from existing RE capacity installed prior to 

2013 has been excluded from the EPA’s calculation of the CO2

emission performances rates in the emission guidelines. That RE 

generating capacity will still provide zero-emitting generation 

to the grid meeting demand that will not need to be addressed by 

existing affected EGUs and will better position states and 

affected EGUs to meet the CO2 performances rates or state rateor mass-based CO2 goals. 

Third, commenters expressed concern that demand-side EE 

targets as part of proposed state goals reflected an assumption 

of installation of increased EE measures starting in 2017., 

which seemed to be an implicit requirement to take action prior 

to the performance period. Because demand-side EE is not used in 

calculating the CO2 emission performance rates in the final 

emission guidelines, this is no longer the casea concern. 

Furthermore, eligible demand-side EE actions that occur after 

2012 can be applied toward adjusting the CO2 emission rates of 

affected EGUs, providing a significant compliance option that is 

not assumed in emission performance rates or state goals. 

(cb) Demonstration that measures substitute for grid 

generation. 
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Eligible measures must be grid-connected. This eligibility 

criterion aligns with RE generation in building block 3 of the 

BSER, which substitutes for the need for generation from 

affected EGUs. 

 All EE measures must result in electricity savings at a 

building, facility, or other end-use location that is connected 

to the electricity grid. EE measures only avoid electric 

generation from grid-connected EGUs if the electrical loads 

where the efficiency improvements are made are interconnected to 

the grid. 

 Commenters sought clarity on this issue, so the EPA is 

providing this requirement as part of the final rule. Some 

commenters advocated for the inclusion of measures that were not 

grid connected as eligible resources, arguing that some of these 

measures substituted for non-affected EGUs and resulted in 

reductions in CO2 emissions. However, eligible measures must be 

able to substitute for generation from affected EGUs as defined 

under this rule, and thus must be tied to the electrical grid. 

Eligible measures must be grid-connected. This eligibility 

criterion aligns with RE generation in building block 3 of the 

BSER, which substitutes for the need for generation from 

affected EGUs. 

 All EE measures must result in electricity savings at a 
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building, facility, or other end-use equipment that is connected 

to the electricity grid. EE measures only avoid electric 

generation from grid-connected EGUs if the electrical loads 

where the efficiency improvements are made are interconnected to 

the grid. 

 Commenters sought clarity on this issue, so the EPA is 

providing this requirement as part of the final rule. Some 

commenters advocated for the inclusion of measures that were not 

grid connected as eligible resources, arguing that some of these 

measures substituted for non-affected EGUs and resulted in 

reductions in CO2 emissions. However, eligible measures must be 

able to substitute for generation from affected EGUs as defined 

under this rule, and thus must be tied to the electrical grid. 

(dc) Geographic eligibility. 

All eligible emission reduction measures, including RE 

generation and demand-side EE measures, may occur in any state

or territory, with certain limitations, as described below. To 

the extent these measures are tied to a state plan,1204 these 

measures may be used to adjust a CO2 emission rate, regardless of 

 

1204 As used here, a measure is “tied to a state plan” if it is 

issued an ERC under approved procedures in a rate-based emission 

standard, or under a state measuresstandards plan or represents 

quantified and verified MWh energy generation or energy savings 

achieved by an approved state measure. in a state measures plan.
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whether the REassociated generation or demand-side EEelectricity

savings occur inside or outside the state or territory.1205 This 

approach is generally consistent with the approach used in 

building block 3 of the BSER, which reflects regionally 

available RE and interstate effects. This approach. It also

recognizes that RE and demand-side EEemission reduction measures 

have impacts on electricity generation across the electricity 

system, both within and beyond a state’s borders. A more indepth discussion of the basis for treatment of in-state and outof-state RE and EEmeasures is provided belowin section VIII.L. 

 State plans must demonstrate that emission standards and 

state measures (if applicable) are non-duplicative. For 

consistency, this geographic eligibility criterion applies to 

all other eligible measures that are used to adjust a CO2

emission rate under a state plan. These measures will have 

similar interstate impacts as RE and demand-side EE on 

 

1205 For example, under a rate-based emission standard with credit 

trading, ERCs may be issued for qualifying actions that occur 

both inside and outside the state, provided the measures meet 

requirements of EPA-approved state regulations and the provider 

applies to the state for the issuance of ERCs. Similarly, under 

a state measures plan, a state might include state requirements 

such as an RPS, where compliance with the RPS can be met through 

out-of-state RE generation. In this plan context, MWh of RE 

generation used to comply with the state RPS could be used by 

the state to adjust the CO2 emission rate of the fleet of 

affected EGUs in the state when demonstrating that its plan has 

achieved the state’s rate-based CO2 goal.
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electricity generation across the interconnected electricity 

system. 

 State plans must demonstrate that emission standards and 

state measures (if applicable) are non-duplicative. Given the 

geographic eligibility approach described here, this includes a 

demonstration that a state plan does not provide forallow

recognition of a MWh, for use in adjusting the CO2 emission rate 

of an affected EGU, if the MWh is being or has been used for 

such a purpose under another state plan. Discussion of how such 

a demonstration can be made in the context of a rate-based 

emission trading program is in section VIII.D.2.b.

The EPA received many comments on the treatment of in-state 

and out-of-state RE and demand-side EE. Most commenters 

recommended crediting of both in-state and out-of-state RE and 

demand-side EE measures, similar to the final rule approach for 

eligible emission reductions measures. Commenters argued that 

this approach makes sense based on the nature of the 

interconnected electricity grid and allows states and utilities 

to fully account for their RE and demand-side EE efforts, 

whether that RE or EE, and its related impacts, occurs inside or 

outside of their state. Some commenters expressed concerns that, 

at proposal, states with significant RE resources had large 

amounts of existing RE capacity included in their state CO2
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goals, but that RE was functionally credited to other states for 

use in meeting their goals because it was associated with 

measures (such as an RPS) likely to be included in another 

state’s plan. This concern has been addressed through changes in 

the BSER RE assumptions in the final rule. This includes 

regionalization of the RE building block, and removal of 

existing RE capacity constructed prior to 2012 from the building 

block. The result of these changes is that the RE incorporated 

in the BSER is more equally shared across states. 

(i) Measures that occur in states with mass-based plans. .

Commenters argued that this approach makes sense based on the 

nature of the interconnected electricity grid and allows states 

and utilities to fully account for their RE and demand-side EE 

efforts, whether that RE or EE, and its related impacts, occurs 

inside or outside of their state. Some commenters expressed 

concerns that, at proposal, states with significant RE resources 

had large amounts of existing RE capacity included in their 

state CO2 goals, but that RE was functionally credited to other 

states for use in meeting their goals because it was associated 

with measures (such as an RPS) likely to be included in another 

state’s plan. This concern has been addressed through changes in 

the BSER RE assumptions in the final rule. This includes 

regionalization of the RE building block, and removal of 
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existing RE capacity constructed prior to 2012 from the building 

block. The result of these changes is that the RE incorporated 

in the BSER is more equally shared across states. 

(i) Measures that occur in states with mass-based plans. 

As discussed above, eligible measures for adjusting the CO2

emission rate of an affected EGU may occur in any state, with 

certain conditions. This includes a condition that applies to 

eligible measures that occur in a state with an EPA-approved 

plan that is meeting a state mass-based CO2 goal. 

However,Eligible measures that could be used to adjust a CO2

emission rate under a rate-based state plan which are located in 

a state with a mass-based plan are restricted from being counted 

under another state’s rate-based plan. An exception is made for 

RE measures that occur in such mass-based states, because of its 

unique role in BSER. RE measures must meet additional 

eligibility criteria in order to be used to adjust the CO2

emission rate of an affected EGU in a state with a rate-based 

plan. This exception only applies to RE; other emission 

reduction measures that were not included in the determination 

of the BSER located in mass-based states, including demand-side 

EE, are restricted from ERC issuance in rate-based states.

 These criteria are intended to address the fact that 

eligible measures should lead to substitution of generation from 
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affected EGUs, with related impacts on CO2 emissions from 

affected EGUs. Where states with mass-based plans implement 

mass-based CO2 emission standards, CO2 emissions reductions from 

affected EGUs must occur in order to comply with these emission 

standards and, unlike the rate-based approach, zero- and lowemitting MWhs do not play a specified role in demonstrating that 

the mass-based standards have been met.1206 Since they are not 

counted in the mass-based demonstration, eligible measures 

located in mass-based states could be used in a state with a 

rate-based plan to adjust the CO2 emission rate of affected EGUs. 

Such adjustments would obviate the need for comparable CO2

emission reductions at affected EGUs in the rate-based state or 

the use of other measures to make a rate adjustment. In this 

scenario, to the extent that eligible measures substitute solely 

for generation from affected EGUs in a state with mass-based 

emission limits, and are also used to adjust the reported CO2

emission rate of affected EGUs in a rate-based state, no 

incremental CO2 emissions reductions would occur in the ratebased state as a result of the eligible measures.1207 The result 

 

1206 Where such measures substitute for generation from affected 

EGUs subject to a mass CO2 emission limit, such measures reduce 

the cost of meeting those mass emission limits, but do not 

result in incremental CO2 emission reductions. 1207 As used here, incremental emission reductions refers to 
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would be These criteria are intended to address the fact that 

eligible measures should lead to substitution of generation from 

affected EGUs, with related impacts on CO2 emissions from 

affected EGUs. Where states with mass-based plans implement 

mass-based CO2 emission standards, CO2 emissions reductions from 

affected EGUs must occur in order to comply with these emission 

standards and, unlike the rate-based approach, zero- and lowemitting MWhs do not play a specified role in demonstrating that 

the mass-based standards have been met.1208 Since they are not 

counted in the mass-based demonstration, eligible measures 

located in mass-based states could be used in a state with a 

rate-based plan to adjust the CO2 emission rate of affected EGUs. 

Such adjustments would obviate the need for comparable CO2

emission reductions at affected EGUs in the rate-based state or 

the use of other measures to make a rate adjustment. In this 

scenario, to the extent that eligible measures substitute solely 

for generation from affected EGUs in a state with mass-based 

emission limits, and are also used to adjust the reported CO2

 

emission reductions that are above and beyond what would be 

achieved solely through compliance with the emission standards 

in the mass-based state. 

1208 Where such measures substitute for generation from affected 

EGUs subject to a mass CO2 emission limit, such measures reduce 

the cost of meeting those mass emission limits, but do not 

result in incremental CO2 emission reductions. 
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emission rate of affected EGUs in a rate-based state, no 

incremental CO2 emissions reductions would occur in the ratebased state as a result of the eligible measures.1209 The result 

would be a loss in netforgone CO2 emission reductions that would 

otherwise occur across the two states. These dynamics are 

further addressed in section VIII.G.2L. 

 For RE measures providing zero-located in a mass-based 

state to have some or low-emittingall of its generation located 

in counted under a massrate-based plan in another state, it must 

be demonstrated that the energy generated isgeneration was

delivered to the grid to meet electricity load in a state with a 

rate-based plan.1210 Some examples of documentation that can serve 

as a demonstration include a power delivery contract or power 

purchase agreement. The EPA is giving states flexibility 

regarding the nature of this demonstration, but a state plan 

must describe the nature of the required demonstration and have 

it be approved by the EPA. 

 Under an emission standards plan, this demonstration must 

 

1209 As used here, incremental emission reductions refers to 

emission reductions that are above and beyond what would be 

achieved solely through compliance with the emission standards 

in the mass-based state. 

1210 This does not need to necessarily be the state where the MWh 

of energy generation from the measure is used to adjust the CO2

emission rate of an affected EGU. 
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be made by the provider of the RE measure seeking ERC issuance 

under the rate-based emission standards in a rate-based state, 

as part of the eligibility application for the measure.1211 Under 

a state measures plan, this demonstration must be made by the 

rate-based state as part of its demonstration of how its state 

measures meet the CO2 emission performance rates or achieve the 

state rate-based CO2 emission goal for affected EGUs.1212 In the 

case of either an emission standards plan or state measures 

plan, theThe rate-based state must include in its state plan 

provisions that describe what it will consider a sufficient 

demonstration of geographic eligibility for zero- or lowemittingthe RE generation under rate-based emission standards, 

or geographic eligibility of state measures that can be used to 

adjust the reported CO2 emission rate of affected EGUs. 

 Further examples of eligible demonstrations and how they 

should be outlined in state plans isare provided in section 

VIII.G.2L. 

(ii) Measures that occur in states, including areas of 

Indian country, that do not have affected EGUs. 

 

1211 Requirements for ERC issuance are addressed in 

subsectionsection VIII.CK.2. 1212 This demonstration is part of a state’s annual report to the 

EPA, outlining the eligibility of MWh used to adjust the 

reported CO2 emission rates of affected EGUs under a rate-based 

state measures plan. 
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States, including areas of Indian country, that do not have 

any affected EGUs within their borders may be providers of 

credits for generation from zero- or low-emitting resources to 

adjust CO2 emission rates. In its supplemental proposal for the

proposed rulemaking, the EPA sought comment on whether or not 

jurisdictions without affected fossil fuel generation units 

subject to the proposed emission guidelines should be authorized 

to participate in state plans. Commenters were supportive of 

allowing those jurisdictions without affected EGUs the 

opportunity to participate in state plans. CO2 reduction measures 

in areas without affected EGUs have the potential to provide 

cost-effective opportunities to reduce emissions and should be 

available on a voluntary basis to affected EGUs. Commenters 

noted that some tribes, for example, have many untapped RE 

resources that could be developed, and they should be able to 

realize the benefits of contributing to a state plan. Commenters 

stated that because of the integrated nature of the U.S. 

electricity grid, it is appropriate to allow all jurisdictions 

with the ability to contribute to and benefit from CO2 emission 

reductions or CO2 emission rate adjustments. 

 and territories that are not interconnected to the grid or 

do not have affected EGUs. States and territories that are not 

interconnected to the grid in the continental U.S. or that do 
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not have any affected EGUs within their borders may be providers 

of credits to adjust CO2 emission rates. In its supplemental 

proposal for this proposed rulemaking, the EPA sought comment on 

whether or not jurisdictions without affected fossil fuel 

generation units subject to the proposed emission guidelines 

should be authorized to participate in state plans. Commenters 

were supportive of allowing those jurisdictions without affected 

EGUs the opportunity to participate in state plans. CO2 reduction 

measures in areas without affected EGUs have the potential to 

provide cost-effective opportunities to reduce emissions and 

should be available on a voluntary basis to affected EGUs. 

Commenters noted that some tribes, for example, have many 

untapped RE resources that could be developed, and they should 

be able to realize the benefits of contributing to a state plan. 

Commenters stated that because of the integrated nature of the 

U.S. electricity grid, it is appropriate to allow all 

jurisdictions with the ability to contribute to and benefit from 

CO2 emission reductions or CO2 emission rate adjustments. 

For rate-basedparticipating states and territories, they 

must adhere to EM&V standards, installation dates, and any other 

criteria that apply to all states. Section VIII.GK.3 below 

identifies and discusses the EM&V criteriarequirements used to 

quantify MWh savings from demand-side EE and generation from 
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zero-emitting sources. States, including areas of Indian 

country, that do not have any affected EGUs may provide ERCs to 

adjust CO2 emissions provided they are connected to the 

continental U.S. grid and have a power purchase agreement or 

contract for delivery of the generation from zero- or lowemission power, along with meeting the other requirements for 

eligibility. Mass-based states and territories are not allowed 

to provide ERCs for zero- or lower-emission power generation if 

they are not connected to the continental U.S. grid and, hence, 

not able to also deliver the power. For demand-side EE 

adjustments where there is no power delivery, the emission 

reductions must meet the demonstration criteria that also 

applies to demand-side EE reductions in all other mass-based 

statesemitting sources. 

(iii) Measures that occur outside the U.S. The EPA will 

work with states using the rate-based approach and interested in 

allowing the use of RE and demand-side EE from outside the U.S. 

to adjust CO2 emission rates. In these cases, certain conditions 

must be demonstrated including: the country generating the ERCs 

must beStates, including areas of Indian country, that do not 

have any affected EGUs may provide ERCs to adjust CO2 emissions 

provided they are connected to the U.S. grid; resources must be 

incremental and installed after 2012 for RE and demand-side EE; 
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all EM&V standards that apply to domestic measures must be met; 

and, specifically for RE,contiguous U.S. grid and meet the other 

requirements for eligibility. To qualify for ERCs from zero or 

low-emitting resources, it must be demonstrated that the 

generation was delivered to the grid to meet electricity load in 

a state with a rate-based plan.1213 Some examples of documentation 

that can serve as a demonstration include a power delivery 

contract or power purchase agreement. The EPA is giving states 

flexibility regarding the nature of this demonstration, but a 

state plan must describe the nature of the required 

demonstration and have it be approved by the EPA. 

In addition to generation from zero- or low-emitting 

resources, demand-side EE resources in areas of Indian country 

located within the borders of states with rate-based emission 

standards for affected EGUs may also be issued ERCs. In these 

instances, the area of Indian country is located within the 

rate-based service area subject to a rate-based state plan. The 

ERCs from demand-side EE resources must meet the eligibility 

requirements to adjust a CO2 emission rate, including 

installation date and EM&V requirements described below in 

 

1213 This does not need to necessarily be the state where the MWh 

of energy generation from the measure is used to adjust the CO2

emission rate of an affected EGU. 
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section VIII.K.3. If the area of Indian country is located 

within the borders of a state that is meeting a mass-based CO2

goal, then the demand-side EE resources are not eligible to be 

issued ERCs. Similarly, demand-side EE resources in any state 

with a mass-based CO2 goal are not eligible to provide ERCs. 

Non-contiguous states and territories may not be providers 

of ERCs to the contiguous U.S. states. As discussed previously 

in section VII.F, we have not set CO2 emission performance goals 

for Alaska, Hawaii, Guam, or Puerto Rico in this final rule at 

this time. 

(iii) Measures that occur outside the U.S. 

The EPA will work with states using the rate-based approach 

that are interested in allowing the use of RE from outside the 

U.S. to adjust CO2 emission rates. In these cases, all conditions 

for creditable domestic RE must be met, including that RE 

resources must be incremental and installed after 2012, and all 

EM&V standards must be met. In addition, the country generating 

the ERCs must be connected to the U.S. grid, and there must be a 

power purchase agreement or other contract for delivery of the 

power with an entity in the U.S. For demand-side EE adjustments 

where there is no power delivery, the emission reductions must 

meet the demonstration criteria that also applies to demand-side 

EE reductions in mass-based states. RE generation capacity 
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outside the U.S. that existed prior to 2012 but was not exported 

to the U.S. is not considered new or incremental generation and, 

therefore, not eligible for adjusting CO2 emission rates under 

this rule. For example, a new transmission interconnection to 

existing RE in Canada would not be considered incremental, but a 

new interconnection to RE where the RE was built after 2012 

would be considered incremental. See below in section 

VIII.K.1.a.(3) for more specifics regarding the use of 

incremental hydroelectric power in a rate-based approach. 

 The EPA received comments encouraging the use of 

international zero-emitting electricity imports in state plans, 

particularly hydroelectric power from Canada. Canada currently 

provides states such as Minnesota and Wisconsin with RE through 

existing grid connections. New projects are in various stages of 

development to increase generating capacity, which could be 

called upon as a base load resource to supplement variable forms 

of RE generation. Commenters said that the EPA should permit the 

use of all incremental hydropower—both domestic and 

international—towards EGU CO2 emission rate adjustments providing 

that double-counting can be prevented; and the EPA acknowledges 

this may be allowable, as long as the specified criteria have 

been met. 

. See below for more specifics regarding the use of 
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incremental hydroelectric power in a rate-based approach. 

 The EPA received comments encouraging the use of 

international zero-emitting electricity imports in state plans, 

particularly hydroelectric power from Canada. Canada currently 

provides states such as Minnesota and Wisconsin with RE through 

existing grid connections. New projects are in various stages of 

development to increase generating capacity, which could be 

called upon as a base load resource to supplement intermittent 

forms of RE generation. Commenters said that the EPA should 

permit the use of all incremental hydropower—both domestic and 

international—towards EGU CO2 emission rate adjustments providing 

that double-counting can be prevented; and the EPA acknowledges 

this may be allowable, as long as the specified criteria have 

been met. 

(3) RE and demand-side EE. . 

RE1214 and demand-side EE measures may be used to adjust a CO2

emission rate, provided they meet the general eligibility 

requirements outlined above and the MWh electricity generation 

or electricity savings areis properly quantified and verified.1215

 

1214 As used in this section, RE includes electric generating 

technologies using RE resources, such as wind, solar, 

geothermal, hydropower, biomass and wave and tidal power. 

1215 All state plans must demonstrate that measures included in 

the plan are quantifiable and verifiable. See section VIII.CK.2 
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Many commenters supported using RE deployment as 

measures to adjust the CO2 emission rate of affected EGUs. Some 

commenters specifically agreed with the EPA’s determination that 

only new and incremental RE (including hydropower) should be 

used to adjust CO2 emission rates. Those commenters objected to 

counting existing RE that are already embedded in the baseline 

emissions and generation mix. A significant number of commenters 

supported the integration of RE into a rate-based credit trading 

system. 

 Certain additional requirements apply for hydropower and 

biomass (including waste-to-energy), as described below. 

(a) Hydroelectric power. Consistent with other types of RE, new 

hydroelectric power generating capacity installed after 2012 is 

eligible for use in adjusting a CO2 emission rate. In addition, 

aAs used in this section, RE includes electric generating 

technologies using RE resources, such as wind, solar, 

geothermal, hydropower, biomass and wave and tidal power. A

capacity uprate at an existing hydroelectric power resource RE 

facility (i.e., an uprate to generating capacity originally 

installed as of 2012 or earlier) is also eligible to adjust a CO2

 

for discussion of requirements for the issuance of ERCs, and 

section VIII.CK.3 for discussion of EM&V requirements for use of 

RE and demand-side EErelied on in a state plan. 
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emission rate. The capacity uprate must occur after 2012. Such 

uprates to capacity represent incremental capacity added after 

2012, which we refer to as “incremental hydroelectric power.”. 

 Generation (in MWh) from Quantification and accounting 

criteria for incremental hydroelectric power generating capacity 

is determinedRE (and nuclear generation) are as follows. The 

incremental generating capacity (in nameplate MW) is divided by 

the total uprated generating capacity (in nameplate MW) and then 

multiplied by generation output (in MWh) from the uprated 

generator. For example, if a hydroelectric power plant expands 

generating nameplate capacity from 100 MW to 125 MW and 

generation output increased to 1,000 MWh, then 200 MWh ((25 

MW/125 MW) * 1,000 MWh) is eligible for use in adjusting a CO2

emission rate, regardless of the overall level of generation for 

the period.1216 

Many commenters supported using RE deployment as measures 

to adjust the CO2 emission rate of affected EGUs. Some commenters 

specifically agreed with the EPA’s determination that only new 

and incremental RE (including hydropower) should be used to 

adjust CO2 emission rates. Those commenters objected to counting 

 

1216 For example, the overall generation from the uprated 

hydroelectric power plant may be higher or lower than generation 

levels that occurred at the plant prior to the capacity uprate. 
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Page 1636 of 2153

existing RE that are already embedded in the baseline emissions 

and generation mix. A significant number of commenters supported 

the integration of RE into a rate-based credit trading system. 

 Certain additional requirements apply for hydropower 

and biomass (including waste-to-energy For example, if a 

hydroelectric power plant expands generating nameplate capacity 

from 100 MW to 125 MW and generation output increased to 1,000 

MWh, then 200 MWh ((25 MW/125 MW) * 1,000 MWh) is eligible for 

use in adjusting a CO2 emission rate, regardless of the overall 

level of generation for the period.1217 

 Relicensed facilities are considered existing capacity and, 

therefore, are not eligible for use in adjusting a CO2 emission 

rate, unless there is a capacity uprate as part of the 

relicensed permit. In such a case, only the incremental capacity 

is eligible for use in adjusting a CO2 emission rate. 

 The EPA noted that many commenters preferred that 

generation from hydropower displace generation from fossil 

sources. One commenter suggested that existing zero-emitting 

sources, including hydropower, do not reduce emissions from 

existing fossil generation, but that new or uprated zero-

 

1217 For example, the overall generation from the uprated 

hydroelectric power plant may be higher or lower than generation 

levels that occurred at the plant prior to the capacity uprate. 
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Page 1637 of 2153

emitting sources would, because of their low variable rate, 

reduce fossil emissions. Several commenters recommended allowing 

incremental generation from new or uprated zero-emitting 

sources, including hydropower, be available for compliance. ) 

RE, as described below. 

(a) Hydroelectric power. 

Consistent with other types of RE, new hydroelectric power 

generating capacity installed after 2012 is eligible for use in 

adjusting a CO2 emission rate. 

 Relicensed facilities are considered existing capacity and, 

therefore, are not eligible for use in adjusting a CO2 emission 

rate, unless there is a capacity uprate as part of the 

relicensed permit. In such a case, only the incremental capacity 

is eligible for use in adjusting a CO2 emission rate. 

 The EPA noted that many commenters preferred that 

generation from hydropower displace generation from fossil 

sources. One commenter suggested that existing zero-emitting 

sources, including hydropower, do not reduce emissions from 

existing fossil generation, but that new or uprated zeroemitting sources would, because of their low variable rate, 

reduce fossil emissions. Several commenters recommended allowing 

incremental generation from new or uprated zero-emitting 

sources, including hydropower, be available for compliance. One 
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Page 1638 of 2153

commenter recognized the difficulty of quantifying emission 

reductions due to uprated zero-emitting sources. The EPA 

believes the approach described is appropriate. 

(b) Biomass. 

RE generating capacity installed after 2012 that uses 

qualifyingqualified biomass as a fuel source is eligible for use 

in adjusting a CO2 emission rate.1218 As discussed in section 

VIII.G.1.a.(I.2)(.c),., if a state shouldintends to allow for 

the use of biomass as a compliance option for an affected EGU to 

meet a CO2 emission standard, a state must propose 

qualifyingqualified biomass feedstocks and treatment of biogenic 

CO2 emissions in its plan, along with supporting analysis and 

quality control measures, and the EPA wouldwill review the 

appropriateness and basis for such determinations in the course 

of its review of a state plan. Where an RE generating unit uses 

qualifyingqualified biomass, as designated in an approved state 

plan, MWh generation from the unit could be used to adjust a CO2

emission rate. Considerations for the use of biomass in state 

plans are discussedthe reported CO2 emission rate of an affected 

EGU. Total MWh generation from an RE generating unit that uses 

 

1218 As with other RE, only generating capacity installed after 

2012 would be eligible for use in adjusting a CO2 emission rate. 
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Page 1639 of 2153

qualified biomass must be prorated based on either the heat 

input supplied from qualified biomass as a proportion of total 

heat input or on the proportion of biogenic CO2 emissions 

compared to total stack CO2 emissions from the RE generating 

unit. Either approach must incorporate the approved valuation of 

biogenic CO2 emissions from qualified biomass in sectionthe plan 

(i.e., the proportion of biogenic CO2 emissions from use of 

qualified biomass feedstock that would not be counted) 

 Section VIII.G.1.a(2)(c)(i).K describes the requirements 

and procedures for EM&V, and discusses how all eligible 

resources must demonstrate how they will quantify and verify MWh 

savings using best-practice EM&V approaches. One way to make 

this demonstration for eligible resources could be to use the 

presumptively approvable EM&V approaches that are included in 

the final model trading rule.

(c) Waste-to-energy. Use of qualifying 

Qualified biomass may include the biogenic portion of MSW 

combusted in a waste-to-energy facility.1219 With regard to 

assessing qualifyingqualified biomass specifiedproposed in state 

plans, the EPA generally acknowledges the CO2 emission reduction 

emissions and climate policy benefits of waste-derived biomass, 

 

1219 As with other RE, only generating capacity installed after 

2012 would be eligible for use in adjusting a CO2 emission rate.
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Page 1640 of 2153

based on the conclusions supported by a variety of technical 

studies, including the revised Framework for Assessing Biogenic 

Carbon Dioxide for Stationary Sources.1220 Suchwhich includes 

biogenic MSW inputs to waste-derived biomass feedstocks would 

likely be approvable as qualifying biomass in a state plan. As 

described in Section VIII.G.1.a.(2)(c), states should propose 

qualifying biomass feedstocksto-energy facilities. The process

and treatment of biogenic CO2 emissions in state plans, along 

with supporting analysis, and the EPA would review the 

appropriateness and basis for such determinations in the course 

of its review of a state plan. Considerationsconsiderations for 

the use of biomass in state plans are discussed in section 

VIII.G.1.a.(I.2)(.c. 

 MSW can be directly combusted in waste-to-energy 

facilities to generate electricity as an alternative to landfill 

disposal. In the U.S., almost all incineration of MSW occurs at 

waste-to-energy facilities or industrial facilities where the 

waste is combusted and energy is recovered.1221 Total MSW 

 

1220 http://www.epa.gov/climatechange/downloads/Framework-forAssessing-Biogenic-CO2-Emissions.pdf.

1221 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-

2012. 

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.

html. 
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Page 1641 of 2153

generation in 2012 was 251 million tons, but of that total 

volume generated, almost 87 million tons were recycled and 

composted.1222 Increasing demand for electricity generated from 

waste-to-energy facilities could increase competition for )(i). 

 MSW can be directly combusted in waste-to-energy facilities 

to generate electricity as an alternative to landfill disposal. 

In the U.S., almost all incineration of MSW occurs at waste-toenergy facilities or industrial facilities where the waste is 

combusted and energy is recovered.1223 Total MSW generation in 

2012 was 251 million tons, but of that total volume generated, 

almost 87 million tons were recycled and composted.1224 Increasing 

demand for electricity generated from waste-to-energy facilities 

could increase competition for and generation of waste stream 

materials - including discarded organic waste materials, – which 

could work against programs promoting waste reduction or cause 

diversion of these materials from existing or future efforts 

promoting waste reduction, composting, and recycling. The EPA 

and many states have recognized the importance of integrated 

 

1222 http://www.epa.gov/osw/nonhaz/municipal/pubs/2012_msw_fs.pdf. 1223 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-

2012. 

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.

html. 

1224 http://www.epa.gov/osw/nonhaz/municipal/pubs/2012_msw_fs.pdf. 
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Page 1642 of 2153

waste materials management strategies that emphasize a hierarchy 

of waste prevention, starting with waste reduction programs as 

the highest priority and then focusing on all other productive 

uses of waste materials to reduce the volume of disposed waste 

materials.1225 For example, Oregon and Vermont have strategies 

that emphasize waste prevention, followed by reuse, then 

recycling and composting materials prior to treatment and 

disposal.1226 

Information in the revised Framework for Assessing Biogenic CO2

Emissions from Stationary Sources and other technical studies 

and tools (e.g., and all other productive uses of waste 

materials to reduce the volume of disposed waste materials.1227

For example, Oregon and Vermont have strategies that emphasize 

waste prevention, followed by reuse, then recycling and 

composting materials prior to treatment and disposal.1228 

Information in the revised Framework for Assessing Biogenic 

CO2 Emissions from Stationary Sources and other technical studies 

 

1225 http://www.epa.gov/wastes/nonhaz/municipal/hierarchy.htm. 1226

http://www.anr.state.vt.us/dec/wastediv/WastePrevention/main.htm

. 

1227 http://www.epa.gov/wastes/nonhaz/municipal/hierarchy.htm. 1228

http://www.anr.state.vt.us/dec/wastediv/WastePrevention/main.htm

. 
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Page 1643 of 2153

and tools (e.g., EPA Waste Reduction Model, EPA Decision Support 

Tool) should assist both states and the EPA in assessing the 

role of biogenic feedstocks used in waste-to-energy processes, 

where use of such feedstocks is included in a state plan.1229 

 When developing their plans, states planning to use wasteto-energy as an option for the adjustment of a CO2 emission rate 

should assess both their capacity to strengthen existing or 

implement new waste reduction, reuse, recycling and composting 

programs, and measures to minimize any potential negative 

impacts of waste-to-energy operations on such programs. States 

must include that information in their plan submissions. When 

developing their plans, states planning to use waste-to-energy 

as an option for the adjustment of a CO2 emission rate should 

assess both their capacity to strengthen existing or implement 

new waste reduction, reuse, recycling and composting programs, 

and measures to minimize any potential negative impacts of 

waste-to-energy operations on such programs. States must include 

that information in their plan submissions. 

The EPA will reject as qualified biomass any proposed waste-toenergy component of state plans if states do not include 

information on their efforts to strengthen existing or implement 

 

1229 http://epa.gov/epawaste/conserve/tools/warm/Warm_Form.html., 

https://mswdst.rti.org/.
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Page 1644 of 2153

new waste reduction as well as reuse, recycling and composting 

programs, and measures to minimize any potential negative 

impacts of waste-to-energy operations on such programs. Only 

electric generation at a waste-to-energy facility that is 

related to the biogenic fraction of MSW and that is added after 

2012 is eligible for use in adjusting a CO2 emission rate. Total 

electric generation from the facility 

A state plan must be prorated based oninclude a method for 

determining the proportion of biogenic contenttotal MWh 

generation from a waste-to-energy facility that is eligible for 

use in adjusting a CO2 emission rate. The EPA will evaluate the 

method as part of MSW. This can be achieved its evaluation of 

the approvability of the state plan. Measuring the proportion of 

biogenic to fossil CO2 emissions can be performed through 

periodic sampling and testing of the biogenic fraction of the 

MSW used as fuel at a waste-to-energy facility, (e.g., via ASTM 

D-6866-06 testing or other methods - ASTM, 2006; Bohar, et al. 

2010), or based on the proportion of biogenic CO2 emissions to 

total CO2 emissions from the facility. Measuring the proportion 

of biogenic to fossil CO2 emissions can be performed via ASTM D6866-06 testing or other methods (ASTM, 2006; Bohar, et al. 

2010).For an example, where of the former method, if the 

biogenic fraction of MSW is 50 percent by input weight, only the 
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Page 1645 of 2153

proportion of MWh output attributable to the biogenic portion of 

MSW at the waste-to-energy facility may be used to adjust an 

affected EGU CO2 emission rate. Alternatively, whereas an example 

of the latter method, if biogenic CO2 emissions represent 50 

percent of total reported CO2 emissions, a facility would need to 

estimate the fraction of biogenic to fossil MSW utilized and the 

net energy output of each component (based on relative higher 

heating values) to determine the percent of the MWh output from 

the waste-to-energy facility that may be used to adjust an 

affected EGU CO2 emission rate. A state plan must propose a 

method for determining the proportion of total MWh generation 

from a waste-to-energy facility that is eligible for use in 

adjusting a CO2 emission rateEGU’s CO2 emission rate. Section 

VIII.K describes the requirements and procedures for EM&V, and 

discusses how all eligible resources must demonstrate how they 

will quantify and verify MWh savings using best-practice EM&V 

approaches. One way to make this demonstration for eligible 

resources could be to use the presumptively approvable EM&V 

approaches that are included in the final model trading rule. 

 The EPA received multiple comments supporting the use of 

waste-to-energy as part of state plans. Some commenters 

expressed concern that non-biogenic materials, such as plastics 

and metal, would be incinerated along with biogenic materials. 
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Page 1646 of 2153

As discussed above, only electric generation related to the 

biogenic fraction of MSW at a waste-to-energy facility added 

after 2012 is eligible for use in adjusting a CO2 emission rate. 

The EPA also received comments that expressed concern about the 

potential negative impacts on recycling and waste reduction 

efforts, while other commenters asserted that waste-to-energy 

practices encourage recycling programs. Some commenters also 

expressed concern about what treatment would be approvable for 

emissions from waste-to-energy practices. As discussed above, 

potential negative impacts from waste-to-energy production on 

recycling, waste reduction, and composting programs should be 

evaluated and efforts to mitigate negative impacts must be 

discussed in Where biogenic CO2 emissions as a proportion of 

total CO2 emissions from a waste-to-energy facility are used to 

prorate total MWh output that may be used to adjust a CO2

emission rate, the state plan must specify requirements for 

reporting biogenic CO2 emissions from the facility. Reporting 

requirements for biogenic CO2 emissions under 40 CFR 98 (§§ 

98.3(c), 98.36(b)-(d), 98.43(b), and 98.46) are an acceptable 

default reporting approach that would be approvable. However, 

the EPA may approve other approaches included in a state plan. 

The EPA received multiple comments supporting the use of wasteto-energy as part of a state’s plan for reducing CO2 emissions.
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Page 1647 of 2153

Some commenters expressed concern that non-biogenic materials, 

such as plastics and metal, would be incinerated along with 

biogenic materials. As discussed above, only electric generation 

related to the biogenic fraction of MSW at a waste-to-energy 

facility added after 2012 is eligible for use in adjusting a CO2

emission rate. The EPA also received comments that expressed 

concern about the potential negative impacts on recycling and 

waste reduction efforts, while other commenters asserted that 

waste-to-energy practices encourage recycling programs. Some 

commenters also expressed concern about what treatment would be 

approvable for emissions from waste-to-energy practices. As 

discussed above, potential negative impacts from waste-to-energy 

production on recycling, waste reduction, and composting 

programs should be evaluated and efforts to mitigate negative 

impacts must be discussed in the supporting documentation of 

state plans. 

(4) Demand-side management. DSM. 

Avoided MWh of electricity use that result from demand-side 

managementDSM may be used to adjust a CO2 emission rate. Eligible 

DSM actions are those that are nonzero-emitting and avoid, 

rather than shift, the use of electricity by an electricity end-
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Page 1648 of 2153

user.1230 The MWh that may be used for such an adjustment are 

determined based on the MW of demand reduction multiplied by the 

hours during which such a demand reduction is achieved (MW of 

demand reduction x hours = MWh avoided). DSM measures must be 

appropriately quantified and verified, in accordance with 

requirements in the emission guidelines, as discussed in section 

VIII.CK.3. 

(5) Energy storage. 

Energy storage may not be directly recognized as an 

eligible measure that can be used to adjust a CO2 emission rate, 

because storage does not directly substitute for electric 

generation from the grid or avoid electricity use from the 

grid.1231 The electric generation that is input to an energy 

storage unit may be used to adjust a CO2 emission rate, but the 

output from the energy storage unit may not.1232 However, energy 

 

1230 An example is a utility direct load control program, such as 

those where customer air conditioning units are cycled during 

periods of peak electricity demand. Actions that shift 

electricity demand from one time of day to another, without 

reducing net electricity use, are not eligible, as these 

measures do not avoid electricity use from the grid. Use of 

emitting generators as a DSM measure areis also not eligible. 1231 Energy storage depends on a generation source, either from a 

utility-scale EGU (e.g., a fossil EGU, a wind turbine, etc.) or 

a distributed generation source at an electricity end-user 

(e.g., a PV system installed at a building). 

1232 This approach focuses on counting the qualifying electric 

generation, which may be an input to an energy storage unit. 
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Page 1649 of 2153

storage can be used as an enabling measure that facilitates 

greater use of RE, which can be used to adjust a CO2 emission 

rate. For example, utility scale energy storage may be used to 

facilitate greater grid penetration of RE generating capacity 

and can also be used to store RE generation that may have 

otherwise been shed in times of excess generating capacity. 

Likewise, on-site energy storage at an electricity end-user can 

enable greater use of RE to meet on-site electricity demand.1233 

The EPA received multiple comments regarding the overall 

merits of energy storage. Consistent with the discussion above, 

the majority of commenters observed that storage technology 

enables greater grid penetration of RE and supports more 

efficient and effective operations of both RE and fossil-fuel 

plants. Commenters further noted that energy storage can provide 

RE to the grid when it is most needed, while simultaneously 

taking pressure off fossil-fuel plants to respond to sudden 

 

Counting both the generation input to energy storage and the 

output from the energy storage unit would be a form of double 

counting. The electric generation that is stored may be counted; 

the subsequent output from the storage unit may not. 

Furthermore, it may be impossible in certain instances to 

determine the specific EGUs that supplied an energy storage 

unit, in some utility-scale applications of energy storage. 

1233 For example, battery storage at a building with solar PV can 

enable the PV system to meet the building’s entire electrical 

load, by storing energy during times of peak PV system output 

for later use when the sun is not shining. 
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Page 1650 of 2153

shifts in demand. Despite broad acknowledgment of the benefits 

of storage, public comments underscore its indirect and 

supporting role in providing zero-emission MWh to the grid 

(consistent with the EPA’s decision to exclude energy storage as 

an eligible measure that can be used to adjust a CO2 emission 

rate). 

(6) Transmission and distribution (T&D) measures. 

Electricity T&D measures that improve the efficiency of the 

T&D system and/or reduce electricity use may be used to adjust a 

CO2 emission rate. This includes T&D measures that reduce losses 

of electricity during delivery from a generator to an end-user 

(sometimes referred to as “line losses”1234) and T&D measures that 

reduce electricity use at the end-user, such as conservation 

voltage reduction (CVR).1235 The EPA received many comments in 

 

1234 T&D system losses (or “line losses”) are typically defined as 

the difference between electricity generation to the grid and 

electricity sales. These losses are the fraction of electricity 

lost to resistance along the T&D lines, which varies depending 

on the specific conductors, the current, and the length of the 

lines. The Energy Information Administration (EIA) estimates 

that national electricity T&D losses average about 6% percent of 

the electricity that is transmitted and distributed in the 

United StatesU.S. each year. 

1235 Volt/VAR optimization (VVO) refers to coordinated efforts by 

utilities to manage and improve the delivery of power in order 

to increase the efficiency of electricity distribution. VVO is 

accomplished primarily through the implementation of smart grid 

technologies that improve the real-time response to the demand 

for power. Technologies for VVO include load tap changers and 
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Page 1651 of 2153

support of advanced energy technologies, including energy 

storage and transmission and distribution upgrades, and 

including these technologies in the suite of potential measures 

that states could consider for emission rate adjustments in 

their state plans. Comments pointed out that in addition to 

helping achieve emission standards, T&D efficiency improvements 

make the grid more robust and flexible, as well as delivering 

environmental benefits. In many parts of the country, grid 

operators, transmission planners, transmission owners and 

regulators are already taking steps to expand and modernize T&D 

networks. Commenters suggested that the EPA clarify the 

eligibility and criteria under which such measures would be 

permitted in a state plan. 

(5) Energy storage. Energy storage may not be directly 

recognized as an eligible measure that can be used to adjust a 

CO2 emission rate, because storage does not directly substitute 

for electric generation from the grid or avoid electricity use 

 

voltage regulators, which can help manage voltage levels, as 

well as capacitor banks that achieve reductions in transmission 

line loss. VVO efforts are often closely related to conservation 

voltage reduction (CVR),, which are actions taken to reduce 

initial delivered voltage levels in feeder transmission lines 

while remaining within the 114 volt to 126 volt range (for 

normal 120-volt service) required at the customer meter (based 

on, per the ANSI C84.1 standards).. 
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Page 1652 of 2153

from the grid.1236 The electric generation that is input to an 

energy storage unit may be used to adjust a CO2 emission rate, 

but the output from the energy storage unit may not.1237 However, 

energy storage can be used as an enabling measure that 

facilitates greater use of RE, which can be used to adjust a CO2

emission rate. For example, utility scale energy storage may be 

used to facilitate greater grid penetration of RE generating 

capacity and can also be used to store RE generation that may 

have otherwise been shed in times of excess generating capacity. 

Likewise, on-site energy storage at an electricity end-user can 

enable greater use of RE to meet on-site electricity demand.1238 

The EPA received multiple comments regarding the overall 

merits of energy storage. Consistent with the discussion above, 

 

1236 Energy storage depends on a generation source, either from a 

utility-scale EGU (e.g., a fossil EGU, a wind turbine, etc.) or 

a distributed generation source at an electricity end-user 

(e.g., a PV system installed at a building). 

1237 This approach focuses on counting the qualifying electric 

generation, which may be an input to an energy storage unit. 

Counting both the generation input to energy storage and the 

output from the energy storage unit would be a form of double 

counting. The electric generation that is stored may be counted; 

the subsequent output from the storage unit may not. 

Furthermore, it may be impossible in certain instances to 

determine the specific EGUs that supplied an energy storage 

unit, in some utility-scale applications of energy storage. 

1238 For example, battery storage at a building with solar PV can 

enable the PV system to meet the building’s entire electrical 

load, by storing energy during times of peak PV system output 

for later use when the sun is not shining. 
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Page 1653 of 2153

the majority of commenters observed that storage technology 

enables greater grid penetration of RE and supports more 

efficient and effective operations of both RE and fossil-fuel 

plants. Commenters further noted that energy storage can provide 

RE to the grid when it is most needed, while simultaneously 

taking pressure off fossil-fuel plants to respond to sudden 

shifts in demand. Despite broad acknowledgment of the benefits 

of storage, public comments underscore its indirect and 

supporting role in providing zero-emission MWh to the grid 

(consistent with the EPA’s decision to exclude energy storage as 

an eligible measure that can be used to adjust a CO2 emission 

rate). 

(6) Transmission and distribution measures. Electricity T&D 

measures that improve the efficiency of the T&D system and/or 

reduce electricity use may be used to adjust a CO2 emission rate. 

This includes T&D measures that reduce losses of electricity 

during delivery from a generator to an end-user (sometimes 

referred to as “line losses”1239) and T&D measures that reduce 

 

1239 T&D system losses (or “line losses”) are typically defined as 

the difference between electricity generation to the grid and 

electricity sales. These losses are the fraction of electricity 

lost to resistance along the T&D lines, which varies depending 

on the specific conductors, the current, and the length of the 

lines. The Energy Information Administration (EIA) estimates 

that national electricity T&D losses average about 6% percent of 
*** E.O. 12866 Review – DraftRevised Version – Do Not Cite, Quote or Release During Review 

*** 

Page 1654 of 2153

electricity use at the end-user, such as conservation voltage 

reduction (CVR).1240 The EPA received many comments in support of 

advanced energy technologies, including energy storage and 

transmission and distribution upgrades, and including these 

technologies in the suite of potential measures that states 

could consider for emission rate adjustments in their state 

plans. Comments pointed out that in addition to helping achieve 

emission standards, T&D efficiency improvements make the grid 

more robust and flexible, as well as delivering environmental 

benefits. In many parts of the country, grid operators, 

transmission planners, transmission owners and regulators are 

already taking steps to expand and modernize T&D networks. 

Commenters suggested that the EPA clarify the eligibility and 

 

the electricity that is transmitted and distributed in the 

United StatesU.S. each year. 

1240 Volt/VAR optimization (VVO) refers to coordinated efforts by 

utilities to manage and improve the delivery of power in order 

to increase the efficiency of electricity distribution. VVO is 

accomplished primarily through the implementation of smart grid 

technologies that improve the real-time response to the demand 

for power. Technologies for VVO include load tap changers and 

voltage regulators, which can help manage voltage levels, as 

well as capacitor banks that achieve reductions in transmission 

line loss. VVO efforts are often closely related to conservation 

voltage reduction (CVR),, which are actions taken to reduce 

initial delivered voltage levels in feeder transmission lines 

while remaining within the 114 volt to 126 volt range (for 

normal 120-volt service) required at the customer meter (based 

on, per the ANSI C84.1 standards).. 
*** E.O. 12866 Review – DraftRevised Version – Do Not Cite, Quote or Release During Review 

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Page 1655 of 2153

criteria under which such measures would be permitted in a state 

plan. 

For T&D measures, the same eligibility date for measure 

installation applies as that which applies to demand-side EE To 

be eligible, T&D measures must be installed after 2012. This 

general eligibility requirement is discussed above in section 

VIII.CK.1.b.(2)(b).a. The MWh of avoided losses or reduction in 

end-use that result from T&D measures must be appropriately 

quantified and verified, as discussed in section VIII.C.3. To 

this point, the predominant view expressed in public comments 

was broad acknowledgement that EM&V for T&D strategies is 

maturing in tandem with their increasing adoption by states and 

utilities. For example, several commenters referenced protocols 

and procedures currently under development and already in usage 

for quantifying MWh savings from CVR. This development in EM&V 

for T&D strategies was cited as a rationale for their inclusion 

as an eligible measure that can be used to adjust a CO2 emission 

rateK.3. 

(7) Demand-side EE, including water system efficiency. 

Demand-side EE measures may be used to adjust a CO2 emission 

rate, provided they meet the general eligibility requirements 

outlined above and the MWh electricity savings are properly 
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Page 1656 of 2153

quantified and verified.1241 As used in this section, demand-side 

EE may include a range of eligible measures, provided that the 

measures can be quantified and verified in accordance with the 

EM&V requirements in the emission guidelines, which are 

addressed in section VIII.K.3. Examples of demand-side EE 

measures include, but are not limited to, EE measures that 

reduce electricity use in residential and commercial buildings, 

industrial facilities, and other grid-connected equipment. Water 

efficiency programs that improve EE at water and wastewater 

treatment facilities also provide demand-side EE savings 

opportunities. EE measures, for the purposes of this section, 

may consist of EE measures installed as the result of individual 

EE projects, such as those implemented by energy service 

companies, as well as multiple EE measures installed through an 

EE deployment program (e.g. appliance replacement and recycling 

programs, and behavioral programs) administered by electric 

utilities, state entities, and other private and non-profit 

entities.1242 EE measures, for the purposes of this section, may 

 

1241 All state plans must demonstrate that measures included in 

the plan are quantifiable and verifiable. See section VIII.K.2 

for discussion of requirements for the issuance of ERCs, and 

section VIII.K.3 for discussion of EM&V requirements for use of 

demand-side EE relied on in a state plan. 

1242 EE programs may also be implemented by other entities. 

Eligible EE measures that are deployed through EE programs are 
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also consist of state or local requirements that result in 

electricity savings, such as building energy codes and state 

appliance and equipment standards. Other interventions that 

result in electricity savings may also be considered an EE 

measure for the purposes of this section, provided the 

intervention can be specified and quantified and verified in 

accordance with EM&V requirements in the emission guidelines. 

 Numerous commenters expressed support for including demandside EE as an eligible measure states and affected EGUs can use 

to meet the emission guidelines. Commenters touted the value of 

demand-side EE as a resource that delivers energy savings, 

lowers bills, creates jobs and reduces CO2 emissions. Commenters 

called for the EPA to allow for the use of a broad range of 

demand-side EE measures to meet the emission guidelines, 

including, but not limited to, utility and non-utility EE 

deployment programs; energy savings performance contracts; 

measures that reduce electricity use in residential and 

commercial buildings, industrial facilities and other gridconnected equipment; state and local requirements that result in 

electricity savings, such as building energy codes and state 

appliance and equipment standards; appliance replacement and 

 

not limited to those EE measures deployed through EE programs 

administered by the types of entities listed here. 
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recycling programs; and behavioral programs. The EPA also

received comments supporting the use of water sector EE programs 

and projects. Commenters identified water and wastewater 

utilities as particularly well-suited for participating in EE 

programs and providing a source of electricity savings. 

Investments such as replacing pumps and other aging equipment 

and repairing leaks can result in greater EE. The EPA agrees 

that these electricity savings should be eligible for 

adjustments to CO2 emission rates at affected EGUs. 

(7) Water system efficiency. Water efficiency programs that 

improve EE at water and wastewater treatment facilities also 

provide demand-side EE savings opportunities. The EPA received 

comments supporting the use of water sector EE programs and 

projects. Commenters identified water and wastewater utilities 

as particularly well-suited for participating in EE programs and 

providing a source of electricity savings. Investments such as 

replacing pumps and other aging equipment and repairing leaks 

can result in greater EE. The EPA agrees that these electricity 

savings should be eligible for adjustments to CO2 emission rates 

at affected EGUs. 

For water efficiency measures, the same eligibility date 

for measure installation applies as that which applies to 

demand-side EE--installed after 2012. This general eligibility 
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requirement is discussed above in section VIII.C.1.b.(2)(b). The 

MWh of avoided electricity use that result from water efficiency 

measures must be appropriately quantified and verified, as 

discussed in section VIII.C.3. 

(8) Nuclear power. 

As is discussed in section V.A.3.,, upon consideration of 

comments received, the EPA doeshas not include eitherincluded

nuclear generation from either existing or under construction 

units in the determination of the BSER. In addition to comments 

received on the provisions for determining the BSER, the EPA 

also received comments requesting that the EPA allow all 

generation from nuclear generating units to be recognized as an 

eligible measure that can be used to adjust a CO2 emission rate. 

Commenters also recommended that the EPA consider nuclear 

generating units and RE generating units in a consistent manner 

for CO2 emission rate adjustments in state plans. We agree with 

comments that nuclear generation and RE should be treated 

consistently when it comes to CO2 emission rate adjustments. 

The EPA has determined that generation from new nuclear 

units and capacity uprates at existing nuclear units will be 

eligible for use in adjusting a CO2 emission rate, just like new 

and uprated capacity RE. However, consistent with the reasons 

discussed for not including the preservation of existing nuclear 
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capacity in the BSER – namely, that such preservation does not 

actually reduce existing levels of CO2 emissions from affected 

EGUs – preserving generation from existing nuclear capacity is 

not eligible for use in adjusting a CO2 emission rate. 

In contrast, any incremental zero-emitting generation from 

new nuclear capacity would be expected to replace generation 

from affected EGUs and, thereby, reduce CO2 emissions; and the 

continued commitment of the owner/operators to completion of the 

new units and improving the efficiency of existing units through 

uprates can play a key role in state plans. Therefore, 

consistent with treatment of other low- and zero-emitting 

generation, new nuclear power generating capacity installed 

after 2012 and incremental generation resulting from nuclear 

uprates after 2012 are measures eligible for adjusting a CO2

emission rate. However, existing nuclear units (i.e., those that 

originally commenced operation in 2012 or earlier years) that 

receive operating license extensions are not eligible for use in 

adjusting a CO2 emission rate, except where such units receive a 

capacity uprate as a result of the relicensing process. Only the 

incremental capacity from the uprate is eligible for use to 

adjust a CO2 emission rate. In addition to comments received on 

the provisions for determining the BSER, the EPA also received 

comments requesting that the EPA allow all generation from 
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nuclear generating units to be recognized as an eligible measure 

that can be used to adjust a CO2 emission rate. Commenters also 

recommended that the EPA consider nuclear generating units and 

RE generating units in a consistent manner for CO2 emission rate 

adjustments in state plans. We agree with comments that nuclear 

generation and RE should be treated consistently when it comes 

to CO2 emission rate adjustments. 

The EPA has determined that generation from new nuclear 

units and capacity uprates at existing nuclear units will be 

eligible for use in adjusting a CO2 emission rate. However, 

consistent with the reasons discussed for not including the 

preservation of existing nuclear capacity in the BSER – namely, 

that such preservation does not actually reduce existing levels 

of CO2 emissions from affected EGUs – preserving generation from 

existing nuclear capacity is not eligible for use in adjusting a 

CO2 emission rate. 

In contrast, any incremental zero-emitting generation from 

new nuclear capacity would be expected to replace generation 

from affected EGUs and, thereby, reduce CO2 emissions; and the 

continued commitment of the owner/operators to completion of the 

new units and improving the efficiency of existing units through 

uprates can play a key role in state plans. Therefore, 

consistent with treatment of other low- and zero-emitting 
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generation, new nuclear power generating capacity installed 

after 2012 and incremental generation resulting from nuclear 

uprates after 2012 are measures eligible for adjusting a CO2

emission rate. Additionally, existing nuclear units (i.e., those 

that originally commenced operation in 2012 or earlier years) 

that receive operating license extensions are not eligible for 

use in adjusting a CO2 emission rate, except where such units 

receive a capacity uprate as a result of the relicensing 

process. Only the incremental capacity from the uprate is 

eligible for use to adjust a CO2 emission rate. 

Applicable generation (in MWh) from incremental nuclear 

power is determined in the same manner as that described for 

incremental hydroelectric powerRE above. 

(9) Combined heat and power (CHP) units. 

Electric generation from non-affected CHP units1243 may be 

used to adjust the CO2 emission rate of an affected EGU, as CHP 

 

1243 The accounting treatmentconsiderations described in this 

section isare for a “topping cycle” CHP unit. A topping cycle 

CHP unit refers to a configuration where fuel is first used to 

generate electricity and then heat is recovered from the 

electric generation process to provide additional useful thermal 

and/or mechanical energy. A CHP unit can also be configured as a 

“bottoming cycle” unit. In a bottoming cycle CHP unit, fuel is 

first used to provide thermal energy for an industrial process 

and the waste heat from that process is then used to generate 

electricity. Some waste heat power (WHP) units are also 

bottoming cycle units and the accounting treatment for bottoming 

cycle CHP units is provided with the WHP description below. 
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units displace emissionsare low-emitting electric generating 

resources that can replace generation from affected EGUs. 

Electrical generation from an on-site boiler and electricity 

from the grid. Nonnon-affected CHP units that meet the 

eligibility criteria under section VIII.GK.1.b.(2)a can be 

considered under this option. In most cases, aused to adjust the 

reported CO2 emission rate of an affected EGU. 

 Where a state plan provides for the use of electrical 

generation from eligible non-affected CHP units to adjust the 

reported CO2 emission rate of an affected EGU, the state plan 

must provide a required calculation method for determining the 

MWh that may be used to adjust the CO2 emission rate. This 

proposed accounting method must adequately address the 

considerations discussed below. The EPA will review whether a 

state’s proposed accounting method for electric generation from 

eligible non-affected CHP units is approvable per the 

requirements of the final emission guidelines, as part of its 

overall plan review of the rate-based emission standards and 

implementing and enforcing measures in the state plan. The EPA 

notes that the proposed model rule for a rate-based emission 

trading program includes a proposed accounting method for nonaffected CHP units. The accounting method provided in a final 

model rule could be a presumptively approvable accounting 
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approach. 

 The proposed accounting method in a state plan must address 

the following considerations. The accounting approach proposed 

in a state plan must take into account the fact that a nonaffected CHP unit would be a low-emitting CO2is a fossil fuelfired emission source and therefore the MWh output would need to 

be prorated to account for the, as well as the fact that the 

incremental CO2 emissions. A denominator approach consistent with 

the accounting approach for EE and RE, can be taken. 

The CHP unit’s electrical output would related to electrical 

generation from a non-affected CHP unit are typically very low. 

In accordance with these considerations, a non-affected CHP 

unit’s electrical MWh output that can be used to adjust the 

reported CO2 emission rate of an affected EGU should be prorated 

based on the CO2 emission rate of the electrical output 

associated with the CHP unit.1244 The incremental rate (a CHP 

unit’s “incremental CO2 emission rate”) compared to a reference 

CO2 emission rate. This “incremental CO2 emission rate” related 

 

1244 The applicable CO2 emission limit rate depends on the type of 

state plan being implemented. Where a state plan includes a 

single CO2 emission limit rate for the fleet of affected EGUs, 

the applicable rate is the rate that applies to all affected 

EGUs. Where a state plan includes subcategorized rates for 

different categories of affected EGUs, the applicable rate is 

the rate that applies to affected NGCC EGUs. 
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to the electric generation from the CHP unit would be relative 

to the applicable CO2 emission rate for affected EGUs in the 

state and would be limited to valuesa value between 0 and 1. 

Prorated MWh = (1-incremental CHP emission rate/applicable 

affected EGU emission limit rate)* CHP MWh output 

Where the ratio is limited to values between 0 and 1. 

The CHP electrical emission rate is the net emission rate 

when the CHP unit’s thermal output emissions are deducted from 

the CHP unit’s total emissions. It can be derived as follows 

[CHP fuel input * fuel emission factor – (UTO/boiler 

efficiency) * fuel emission factor]/CHP MWh 

 This low CO2 emission rate for electrical generation from a 

non-affected CHP unit is a product of both the fact that CHP 

units are typically very thermally efficient and the fact that a 

portion of the CO2 emissions from a non-affected CHP unit would 

have occurred anyway from an industrial boiler used to meet the 

thermal load in the absence of the CHP unit. In contrast, the 

CHP unit also provides the benefit of electricity generation 

while resulting in very low incremental CO2 emissions beyond what 

would have been emitted by an industrial boiler. As a result, 

the accounting method proposed in a state plan should not 

presume that CO2 emission reductions occur outside the electric 

power sector, but instead only would account for the CO2
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emissions related to the electrical production from a CHP unit 

that is used to substitute for electrical generation from 

affected EGUs. 

Non-affected CHP units can use qualifyingqualified biomass 

fuels. As described in Sectionsection VIII.G.1.a.(I.2)(.c),,

states should propose qualifyingmust submit state plan 

requirements regarding qualified biomass feedstocks and 

treatment of biogenic CO2 emissions in state plans, along with 

supporting analysis and quality control measures, and the EPA 

would review the appropriateness and basis for such 

determinations in the course of its review of the approvability 

of a state plan. Considerations for qualifyingqualified biomass 

included in state plans are discussed in section 

VIII.G.1.a.(I.2).(.c).(i). 

The measurement of the fuel and MWh output of the CHP unit 

, while accounting requirements for RE using biomass are based 

on standard industry practice and discussedprovided in section 

VIII.G.d.5. K.1.a.(3)(b).

In order to determine the incremental CO2 emission rate, a 

CHP unit would monitor requirements for CO2 emissions and energy 
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output.1245 The monitoring requirements are standard methods 

currently in use and the requirements would depend on the size 

of the CHP units and the fuel used in the unit. 

Non-affected CHP facilities1246 with electric generating 

capacity greater than 100 MW would follow the same monitoring 

and reporting protocols for CO2 emissions and energy output as 

are required for affected EGU CHP units. These requirements are 

discussed in section VIII.F. For non-affected CHP facilities 

with electric generating capacity less than 100 MW, which use 

only natural gas and/or distillate fuel oil, the low mass 

emission unit CO2 emission monitoring and reporting methodology 

outlined in 40 CFR 75, or a similar fuel tracking and emission 

factor approach, is acceptable. For non-affected CHP facilities 

with an electric generating capacity less than 100 MW, which use 

all other fuels, the CO2 emissions monitoring and reporting 

protocols for affected EGU CHP units would be used. These 

requirements are discussed in section VIII.G.5. 

Most comments received on CHP recommended that the EPA 

explicitly call outdescribe how CHP can be accounted for in a 

 

1245 Where a CHP unit uses biomass fuel, it must report both total 

CO2 emissions and biogenic CO2 emissions. Requirements for 

reporting biogenic CO2 emissions are discussed in section 

VIII.G.1.a.(2)(c) above. 

1246 A CHP facility may consist of one or more electric 

generators. 
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state plan. Commenters described the CO2 emission reductions 

achieved through CHP’s thermal efficiency and the precedent set 

in other federal and state rules that have included CHP as a 

compliance option. Some commenters pointed out that without such 

a description, states would not be able to readily take 

advantage of the CO2 emissions reduced by the use of CHP. Other 

commenters weighed the advantages to considering a numeratorbased approach versus a denominator-based approach. The EPA 

believes that a denominator approach is appropriate because it 

is consistent with the accounting approach used for RE and 

demand-side EEemission reductions that result from the use of 

CHP. 

(10) WHP. 

 WHP units that meet the eligibility criteria under section 

VIII.GK.1.b.(2) may be used to adjust the CO2 emission rate of an 

affected EGU. There are several types of WHP units. There are 

units, also referred to as bottoming cycle CHP units, where the 

fuel is first used to provide thermal energy for an industrial 

process and the waste heat from that process is then used to 

generate electricity.1247 Emissions from these There are also WHP 

 

1247 This configuration is sometimes referred to as a “bottoming 

cycle” CHP unit. In such a configuration, the waste heat stream 

could also be generated from a mechanical process, such as at 

natural gas pipeline compressors. 
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facilities where the waste heat from the initial combustion 

process is used to generate additional power. Under both 

configurations, unless the WHP unit supplements waste heat with 

fossil fuel use, there is no additional fossil fuel used to 

generate this additional power. As a result, there are no 

incremental CO2 emissions associated with that additional power 

generation. As a result, the incremental electric generation 

output from the WHP facilities would be based on the initial 

fuel combustion process that produced the waste heat and would 

be accounted in the same way as non-affected CHP units under 

section VIII.G.1.b.9. 

 There are WHP facilities where the waste heat from the 

initial combustion process is used to generate additional power. 

There is no additional fuel used to generate this additional 

power as so there are no incremental emissions associated with 

that additional power. As a result, the incremental electric 

generation output from the WHP facilities could be considered 

nonzero-emitting, for the purposes of meeting the emission 

guidelines, and the MWh of electrical output could be used to 

adjust the CO2 emission rate of an affected EGU. 
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 1248 The MWh of electrical output from a WHP unit that can be 

recognized may not exceed the MWh of industrial or other thermal 

load that is being met by the WHP unit, prior to the generation 

of electricity.1249 Most commenters that addressed WHP noted the 

benefits forof WHP at the same time that they discussed the 

benefits of CHP. The commenters reflected that WHP is another 

potential compliance option and requested it be called 

outdiscussed explicitly as a compliance option that can be used 

to meet the emission guidelines. The comments discussed WHP 

benefits but did not elaborate on a preferred accounting method. 

c. Measures that may not be used to adjust a CO2 emission rate. 

This section addresses measures that may not be used to adjust a 

CO2 emission rate. Other new and existing non-affected fossil 

fuel-fired EGUs that are not subject to CAA section 111(b) or 

111(d) may not for MWh of electrical generation from WHP that 

could be used to adjust the CO2 emission rate of an affected EGU.

b. Measures that may not be used to adjust a CO2 emission rate. 

 

1248 This only applies where no additional fossil fuel is used to 

supplement the use of waste heat in a WHP facility. Where fossil 

fuel is used to supplement waste heat in a WHP application, MWh 

of electrical generation that can be used to adjust the CO2

emission rate of an affected EGU must be prorated based on the 

proportion of fossil fuel heat input to total heat input that is 

used by the WHP unit to generate electricity. 

1249 This limitation prevents oversizing the thermal output of a 

WHP unit to exceed the useful industrial or other thermal load 

it is meeting, prior to generation of electricity. 
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This section addresses measures that may not be used to adjust a 

CO2 emission rate. New, modified, and reconstructed EGUs covered 

under the CAA section 111(b) final Standards of Performance for 

Greenhouse Gas Emissions from New Stationary Sources: Electric 

Utility Generating Units rule are not approvable sources of 

electric generation for adjusting the CO2 emission rate of an 

affected EGU under a rate-based state plan. As discussed earlier 

in section VII.D of this preamble, a key concern under this rule 

is leakage to new units that are not covered by the emission 

guidelines. Emissions leakage, or increased CO2 emissions due to 

increased utilization of unaffected sources, is contradictory to 

objectives of this rule and should, therefore, be minimized. 

Allowing affected EGUs to adjust their emission rates as a 

result of lower-emitting new NGCC units not covered under this 

section 111(d) rule would not mitigate leakage concerns, and 

could even exacerbate the situation. Consequently, new EGUs 

covered under the CAA section 111(b) rule are not allowable 

measures in state plans because the EPA believes it would result 

in increased emission leakage. 

 The EPA received comments both supporting and opposing the 

use of new NGCC units in state plans. In addition to leakage 

concerns, commenters expressed concern with the potential 

incentives created by including new NGCC capacity in the BSER or 
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as a compliance mechanism in state plans. Some commenters 

suggested that including new NGCC capacity in the BSER or for 

compliance would distort market incentives to build new NGCC 

units, particularly if new units were allowed to generate ERCs 

that could be sold to affected EGUs. These commenters suggested 

that the additional incentive for new NGCC units could make 

existing NGCC units less competitive. Other commenters suggested 

that including new NGCC capacity in state plans would promote 

generation from new CO2-emitting units at the expense of new 

zero-emitting units, increasing overall emissions within a 

state. This effect would be exacerbated if state plans allowed 

new NGCC units to be treated as “zero-emitting” for purposes of 

compliance –- as suggested by other commenters. In addition, 

commenters expressed concern that the EPA’s inclusion of new 

NGCC capacity in setting the BSER or in compliance could 

negatively impact ratepayers over the long-term by sending the 

wrong signal to industry and resulting in stranded assets if, in 

the future, carbon emissions become more expensive or the EPA 

proposes to incorporate sources built under the forthcoming 

section 111(b) standard into the section 111(d) program. 

Commenters also expressed concern that including generation from 

new NGCC units could create unreasonable uncertainty, given 

limitations on the ability to accurately project new NGCC 
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builds, could create undue pressure on natural gas prices, and 

could create unfair disparities in the compliance opportunities 

afforded different states. In light of the emissions leakage 

concerns, and in consideration of these comments, the EPA is not 

allowing shifting generation to new NGCC units to be used as a 

measure for adjusting CO2 emission rates for affected EGUs in 

rate-based state plans. 

In addition, other new and existing non-affected fossil 

fuel-fired EGUs that are not subject to CAA section 111(b) or 

111(d), such as simple cycle combustion turbines, may not be 

used to adjust the CO2 emission rate of an affected EGU. While 

generation from such units could substitute for generation from 

affected EGUs, the EPA has determined that additional incentives 

for such generation, in the form of an explicit adjustment to 

the CO2 rate of an affected EGU, are not necessary or warranted. 

Providing for such an adjustment could create perverse 

incentives for the construction of new simple cycle 

CTscombustion turbines that are not subject to the applicability 

criteria of the final Standards of Performance for Greenhouse 

Gas Emissions from New Stationary Sources: Electric Utility 

Generating Units rule. These units could provide only limited 

adjustment credit, as operation beyond a certain capacity factor 

threshold would trigger applicability under CAA section 111(b). 
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Further, providing for the ability to generate adjustment 

credits would provide incentives for construction of less 

efficient fossil generating capacity than would likely otherwise 

be constructed (e.g., addition of a simple cycle combustion 

turbine rather than a NGCC unit). In addition, providing for the 

ability to generate adjustment credits could create perverse 

incentives for the continued operation of less efficient 

existing fossil generating capacity. Such outcomes run counter 

to the objectives of this final rule. 

For example, such units could provide only limited 

adjustment credit, as operation beyond a certain capacity factor 

threshold would trigger applicability under CAA section 111(b). 

Further, providing for the ability to generate adjustment 

credits would provide incentives for construction of less 

efficient fossil generating capacity than would likely otherwise 

be constructed (e.g., addition of a simple cycle combustion 

turbine rather than a NGCC unit). In addition, providing for the 

ability to generate adjustment credits could create perverse 

incentives for the continued operation of less efficient 

existing fossil generating capacity. Such outcomes run counter 

to the objectives of this final rule. 

d. Measures that reduce CO2 emissions outside the electric power 

sector.c. Measures that reduce CO2 emissions outside the electric 
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power sector. Measures that reduce CO2 emissions outside the 

electric power sector may not be counted toward meeting a CO2

emission performance level for affected EGUs or a state CO2 goal, 

under either a rate-based or mass-based approach, because all of 

the emission reduction measures included in the EPA’s 

determination of the BSER reduce CO2 emissions from affected 

EGUs. Examples of measuremeasures that may not be counted toward 

meeting a CO2 emission performance level for affected EGUs or a 

state CO2 goal include GHG offset projects representing emission 

reductions that occur in the forestry and agriculture sectors,1250

direct air capture, and crediting of CO2 emission reductions that 

occur in the transportation sector as a result of vehicle 

electrification. 

2. Requirements for rate-based emission trading approaches 

 As made clear in the proposal,1251 all emission standards in 

a state plan must be quantifiable, verifiable, enforceable, non-

 

1250 We note, however, that the final emission guidelines allow 

state measures like emission budget trading programs to include 

out-of-sector GHG offsets. For example, both the California and 

RGGI programs allow for the use of allowances awarded to GHG 

offset projects to be used to meet a specified portion of an 

affected emission source’s compliance obligation. The RGGI 

program contains a cost containment allowance reserve that makes 

available additional allowances up to a certain amount, at 

specified allowance price triggers. See section VIII.C.3.b(2)(a) 

of this preamble.

1251 79 FR 34830, 34913. 
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duplicative and permanent.1252 This requirement is applicable to 

emission standards that include a rate-based emission trading 

program. The State Plan Considerations TSD for the proposal also 

explained that in order to ensure a plan is enforceable, a state 

plan must: identify in its plan the entity or entities 

responsible for meeting compliance and other enforceable 

obligations under the plan; include mechanisms for demonstrating 

compliance with plan requirements or demonstrating that other 

binding obligations are met; and provide a mechanism(s) for 

legal action if affected EGUs are not in compliance with plan 

requirements or if other entities fail to meet enforceable plan 

obligations. A state plan using a rate-based emission trading 

approach must therefore include rate-based emission standards 

for affected EGUs along with related implementation and 

compliance requirements and mechanisms.1253 These related 

requirements include those applicable to rate-based emission 

standards more broadly: CO2 emission monitoring, reporting, and 

recordkeeping requirements for affected EGUs, including 

requirements for monitoring and reporting of useful energy 

 

1252 These requirements are described in detail in section 

VIII.D.2.

1253 As described below, these requirements would likely be 

provided in a state plan in the form of state regulations, but 

could potentially be provided in another form. 
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output. By satisfactorily addressing these requirements, state 

plans including a rate-based emission trading program will be 

able to meet the statutory requirements of CAA section 111(d) 

regarding the need for state plans to provide for the 

implementation and enforcement of emission standards, as well as 

meet the requirement that each emission standard be 

quantifiable, verifiable, non-duplicative, permanent, and 

enforceable with respect to each affected EGU. 

The EPA also specifically proposed that for state plans 

that rely on measures that avoid EGU CO2 emissions, such as RE 

and demand-side EE measures, the state will also need to include 

quantification, monitoring, and verification provisions in its 

plan for these measures. The EPA is finalizing requirements 

specific to rate-based emission trading programs as requirements 

the EPA has determined are necessary to assure the integrity of 

a rate-based approach that includes an emission trading program, 

and therefore assures a state plan using such an approach 

appropriately provides for the implementation and enforcement of 

rate-based emission standards in accordance with CAA section 

111(d).1254 These specific requirements for a rate-based emission 

 

1254 By “integrity of a rate-based emission trading program”, the 

EPA is referring to elements in the design and administration of 

a program necessary to assure that emission standards 
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trading program include provisions for issuance of ERCs by the 

state and/or its designated agent; provisions for tracking ERCs, 

from issuance through submission for compliance; and the 

administrative process for submission of ERCs by the owner or 

operator of an affected EGU to the state, in order to adjust its 

reported CO2 emission rate when demonstrating compliance with a 

rate-based emission standard.1255 These requirements must be 

submitted for inclusion in the federally enforceable plan, per 

the statutory requirement that states provide for the 

implementation and enforcement of emission standards. A ratebased trading program would provide for the implementation and 

enforcement of rate-based emission standards for a state plan 

that allows its affected EGUs to adjust a rate by the use of an 

ERC. 

The EPA will review a state plan submittal including a 

rate-based emission trading program to assure that the plan 

contains the requirements necessary to assure the integrity of a 

rate-based approach, and therefore provide for the 

implementation and enforcement of rate-based emission standards. 

 

implemented using a rate-based emission trading approach are 

quantifiable, verifiable, enforceable, non-duplicative, and 

permanent. 

1255 See section VIII.K.1 for a discussion of the accounting 

method used to adjust a CO2 emission rate. 
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These requirements are discussed in more detail in this section. 

The EPA also notes it is proposing model rules for both 

mass-based and rate-based emission trading programs. State plans 

that include the finalized model rule for a rate-based emission 

trading program could be presumptively approvable as meeting the 

requirements of CAA section 111(d) and these emission 

guidelines. The EPA would evaluate the approvability of such 

plans through independent notice and comment rulemaking. 

A state may issue ERCs to an affected EGU that performs at 

a CO2 emission rate below a specified CO2 emission rate, as well 

as to providers of qualifying measures that provide substitute 

generation for affected EGUs or avoid the need for generation 

from affected EGUs. This latter category includes providers of 

qualifying RE and demand-side EE measures, as well as other 

types of measures, as discussed in section VIII.K.1.a.1256 

 ERCs may be used by an affected EGU to adjust its reported 

CO2 emission rate when demonstrating compliance with a rate-based 

 

1256 As used in this section, the term “EE program” refers to an 

EE deployment program. An EE program involves deployment of 

multiple EE measures or EE projects, such as utility- or stateadministered EE incentive programs that accelerate the 

deployment of EE technologies and practices. As used in this 

section, the term “EE/RE project” refers to a discrete EE 

project (e.g., an EE upgrade to a commercial building or set of 

buildings) or a RE generator (e.g., a single wind turbine or 

group of turbines).
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emission standard. This adjustment is made by adding MWh to the 

denominator of an affected EGU’s reported CO2 emission rate, in 

the amount of submitted ERCs, resulting in a lower adjusted 

rate. To demonstrate compliance with a rate-based emission 

standard, an affected EGU would report its CO2 lb/MWh emission 

rate to the state regulatory body, and would also surrender to 

the state any ERCs it wishes to use to adjust its reported 

emission rate. The state regulator would then cancel the 

submitted ERCs. The affected EGU would add the MWh the ERCs 

represent to the denominator of its reported CO2 lb/MWh emission 

rate to demonstrate compliance with its emission standard. The 

state regulator could facilitate its evaluation of the affected 

EGU’s compliance (as well as evaluation by the affected EGU, the 

EPA, and others) by providing functionality in its tracking 

system to run such compliance calculations. If the affected 

EGU’s adjusted CO2 emission rate is equal to or lower than its 

applicable emission rate standard, the affected EGU would be in 

compliance. 

a. Issuance of ERCs to affected EGUs. ERCs may be issued to 

affected EGUs that emit below a specified CO2 emission rate, as 

discussed below. For issuance of ERCs to affected EGUs, the 

state plan must specify the accounting method and administrative 

process for ERC issuance. This includes the calculation method 
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for determining the number of ERCs to be issued to an affected 

EGU, based on reported CO2 emissions and MWh energy output, in 

comparison to a reference CO2 emission rate. The reference rate 

is a specified CO2 lb/MWh emission rate that an affected EGU’s 

reported CO2 emission rate is compared to, when determining the 

amount of ERCs that may be issued to an affected EGU. 

Following determination of the number of ERCs an affected 

EGU is eligible to receive, based on an affected EGU’s reported 

CO2 emission rate compared to a specified reference rate, the 

state regulatory body would issue those ERCs into a tracking 

system account held by the owner or operator of the affected 

EGU. Tracking system requirements are addressed below at section 

VIII.K.2.c. 

The accounting method that may be applied in a state plan 

differs depending on whether a state plan includes a single 

rate-based emission standard that applies to all affected EGUs 

(e.g., if a plan is designed to meet a state rate-based CO2 goal) 

or separate rate-based emission standards that apply to 

subcategories of affected EGUs, namely fossil fuel-fired 

electric utility steam generating units and stationary 

combustion turbines. In both cases, ERCs are issued in MWh, 

based on the difference between an affected EGU’s reported CO2

emission rate (in CO2 lb/MWh) and a specified CO2 lb/MWh emission 
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rate that the reported rate is compared to (referred to as a 

“reference rate”). The reference rate may be an affected EGU’s 

assigned CO2 emission limit rate or another CO2 emission rate, as 

described below. Where an affected EGU’s reported CO2 emission 

rate is lower than the specified reference CO2 emission rate, 

ERCs may be issued. 

Where a state plan includes emission standards in the form 

of a single rate-based emission standard that applies to all 

affected EGUs, the reference rate is the CO2 emission rate limit 

for affected EGUs. In this instance, ERCs may be issued based on 

an affected EGU’s reported CO2 emission rate as a proportion of 

the emission limit rate. For example, if the emission rate limit 

is 2,000 lb CO2/MWh and the affected EGU emits at a rate of 1,000 

lb CO2/MWh, 0.5 MWh would be awarded for every MWh generated by 

the affected EGU. ERCs would be issued to affected EGUs in whole 

MWh increments. The calculation method is as follows: 

ERCs1257 = reported MWh by affected EGU1258 x ((CO2 emission 

rate limit for affected EGUs1259 – affected EGU reported CO2

 

1257 For all calculations in this section, where the result is a 

negative value, no ERCs would be issued.

1258 This term represents the reported MWh by the affected EGU on 

an annual basis. 

1259 This term represents the “reference rate.” 
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emission rate1260)/ CO2 emission rate limit for affected EGUs) 

For the example above, the calculation is as follows: 

ERCs = MWh reported x (2,000 – 1,000)/2,000 = MWh reported 

x 0.5 

If the affected EGU in this example generated 1,000,000 MWh, 

500,000 ERCs would be issued. 

Where a state plan includes separate emission standards for 

subcategories of affected EGUs, specifically affected fossil 

fuel-fired electric utility steam generating units and 

stationary combustion turbines, the reference rate differs for 

affected fossil fuel-fired electric utility steam generating 

units and stationary combustion turbines. Additionally, if the 

state plan applies emission standards for its affected EGUs that 

are equal to the subcategorized CO2 emission performance rates 

there is a unique opportunity for the adjustment of an affected 

EGU’s emission rate using ERCs that are generated as a result of 

building block 2 incremental NGCC unit operation. The EPA is 

requiring state plans to account for incremental NGCC generation 

in ERC generation if a state plan applies the subcategorized CO2

emission performance rates to its affected EGUs as emission 

standards. Additionally, the EPA is requiring that a NGCC unit 

 

1260 This term represents the annual reported CO2 emission rate of 

the affected EGU.
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is not able to use ERCs generated by it or any other NGCC unit’s 

building block 2 incremental generation. 

For affected steam generating units, the reference CO2

emission rate is the assigned CO2 emission rate limit for steam 

generating units, and the following accounting method for 

generating ERCs applies: 

ERCs1261 = reported MWh x ((steam generating unit CO2

emission rate limit1262 – steam generating unit reported CO2

emission rate)/ steam generating unit CO2 emission rate limit). 

For an affected NGCC stationary combustion turbine in a 

subcategorized rate-based emission trading program, the 

following equation provides a required accounting method for 

generating ERCs based on operation with respect to the NGCC 

unit’s emission standard: 

ERCs = NGCC unit’s reported MWh x ((NGCC unit’s CO2 emission 

standard1263 – NGCC unit’s reported CO2 emission rate)/ NGCC 

unit’s CO2 emission standard) 

According to this equation, ERC issuance is assessed based 

on the difference between the CO2 emission rate standard for the 

 

1261 For all calculations in this section, where the result is a 

negative value, no ERCs would be issued. 

1262 The “reference rate.” 1263 The “reference rate.” 
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NGCC unit1264 and the reported CO2 emission rate of the affected 

NGCC unit. In other words, affected NGCC stationary combustion 

turbines earn ERCs for generation when they perform at an 

emission rate better than the reference rate for stationary 

combustion turbines, similarly to how affected steam units can 

earn ERCs. 

To account for incremental generation for a NGCC stationary 

combustion turbine to generate ERCs in a subcategorized ratebased emission trading program, a state must use the incremental 

operation of an affected NGCC unit quantified for building block 

2 to allow a NGCC unit to generate ERCs based on its expected 

incremental generation. 

A state plan that provides for the use of ERCs issued based 

on incremental affected NGCC generation must provide a required 

calculation method that allows for issuance of ERCs based on the 

ability of incremental generation from affected stationary 

combustion turbines to substitute for generation from affected 

steam generating units (as represented in building block 2), 

while also respecting the fact that affected stationary 

combustion turbines must also meet an assigned CO2 emission rate 

limit for the entirety of its MWh energy output. This accounting 

 

1264 This is the CO2 emission performance rate for affected 

stationary combustion turbines in the emission guidelines.
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method must reflect the application of the BSER, as described in 

section V, and the accounting method must not create incentives 

to rearrange dispatch between existing NGCC units to generate 

additional ERCs without changing the overall level of NGCC 

generation. 

The EPA will review whether a state’s accounting method is 

approvable per the requirements of the statute and this final 

rule as part of its overall plan review of the rate-based 

emission standards and implementing and enforcing measures in 

the state plan. The EPA notes that the proposed model rule for a 

rate-based emission trading program includes a proposed 

accounting method and takes comments on alternatives. The 

accounting method provided in a final model rule could be a 

presumptively approvable approach for issuance of ERCs based on 

the ability of incremental generation from affected stationary 

combustion turbines to substitute for generation from affected 

steam generating units. A state’s accounting requirements for 

generation of ERCs based on incremental affected NGCC generation 

must maintain consistency with the EPA’s application of the BSER 

when calculating CO2 emission performance rates for affected 

stationary combustion turbine and steam generating units. In 

particular, a state’s accounting method must maintain

consistency of accounting in a state rate-based CO2 emission 
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standard with the EPA’s application of building block 2 in 

calculating CO2 emission performance rates for affected fossil 

fuel-fired electric utility steam generating units and 

stationary combustion turbines, which is based on use of 

incremental generation from affected stationary combustion 

turbine to replace generation from affected steam generating 

units. 

b. Issuance of ERCs for RE, demand-side EE, and other measures. 

ERCs may be issued for qualifying measures.1265 For issuance of 

ERCs for qualifying measures, state plan requirements for ERC 

issuance must include a two-step process. In the first step of 

the process, a potential ERC provider submits an eligibility 

application for a qualifying program or project1266 to the 

administering state regulator (or its agent1267). The state 

 

1265 Qualifying measures that can be used to adjust the CO2

emission rate of an affected EGU are discussed at 

subsectionsection VIII.GK.1, and include RE, demand-side EE, and 

other measures, such as DSM, CHP and incremental nuclear 

generation.

1266 For example, for an EE/RE program or project, as described in 

this section for illustrative purposes. The requirements 

described in this section for EE/RE programs and projects also 

apply for all other eligible qualifying measures discussed in 

subsectionsection VIII.GK.1. 

1267 As used here, an agent is a party acting on behalf of the 

state, based on authority vested in it by the state, pursuant to 

the legal authority of the state. A state could designate an 

agent to provide certain limited administrative services, or 

could choose to vest an agent with greater authority. Where an 
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regulator reviews the application to determine whether, in this 

example, an EE/RE program or project meets eligibility 

requirements for the issuance of ERCs.1268 An eligibility 

application must include a description of the program or 

project, a projection of the MWh generation or energy savings 

anticipated over the life of the program or project, and an EM&V 

plan that meets state plan requirements. The EM&V plan must 

describe how MWh of RE generation or energy savings resulting 

from the program or project will be quantified and verified.1269 A 

state, in its emission standard regulations, must include 

requirements for EM&V plans that are consistent with the 

requirements in the emission guidelines for EE/RE measures and 

other eligible measures, as discussed in sections VIII.K.1 and 

 

agent issues an ERC on behalf of the state, such issuance would 

have the same legal effect as issuance of an ERC by the state. 

1268 The entity implementing the EE/RE program or project 

(referred to in the preamble as a “provider”) would submit the 

application. This is the identified entity to which ERCs would 

ultimately be issued, to a tracking system account held by the 

entity. Such entities could include a wide variety of parties 

that implement EE/RE programs and projects, including owners or 

operators of affected EGUs, electric distribution companies, 

independent power producers, energy service companies, 

administrators of state EE programs, and administrators of 

stateindustrial EE programs, among others. 

1269 The verification process includes confirmation that 

quantified MWh are non-duplicative and permanent (i.e., are not 

being used in any other state plan to demonstrate compliance 

with an emission standard or achievement of an emission 

performance rate or state CO2 emission goal). 
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VIII.K.3. 

 The EPA has determined that state requirements for an 

eligibility application must include review of the application 

by an independent verifier, approved by the state as eligible 

per the requirements of the final emission guidelines to provide 

such verification, prior to submittal. This requirement builds 

on the approach used for assessing GHG offset projects, both in 

international emission trading programs and the GHG emission 

budget trading programs implemented by California and the RGGI 

participating states.1270 An assessment by an independent verifier 

would be included as a component of an eligibility application. 

 The EPA has determined that independent verification 

requirements are necessary to ensure the integrity of state 

rate-based emission trading programs included in a state plan, 

given the wide range of eligible measures that may generate ERCs 

and the broad geographic locations in which those measures may 

occur. Inclusion of an independent verification component 

provides technical support for state regulatory bodies to ensure 

 

1270 Information about the verification process for GHG offsets 

under the RGGI program, including verifier accreditation 

requirements and access to relevant documents, is available at 

http://www.rggi.org/market/offsets/verification. Similar 

information about the verification process for GHG offsets under 

the California program is available at 

http://www.arb.ca.gov/cc/capandtrade/offsets/verification/verifi

cation.htm. 
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that eligibility applications and M&V reports are thoroughly 

reviewed prior to issuance of ERCs. Inclusion of an independent 

verification component is also consistent with similar 

approaches required by state PUCs for the review of demand-side 

EE program results and GHG offset provisions included in state 

GHG emission budget trading programs. 

 State plans with rate-based emission trading programs must 

include requirements regarding the qualification status of an 

independent verifier. An independent verifier is a person 

(including any company, any corporate parent or subsidiary, any 

contractors or subcontractors, and the actual person) who has 

the appropriate technical and other qualifications to provide 

verification reports. The independent verifier must not have, or 

have had, any direct or indirect financial or other interest in 

the subject of its verification report or ERCs that could impact 

its impartiality in performing verification services. State 

plans must require that a person be approved by the state as an 

independent verifier, as defined by this final rule, as eligible 

to perform the verifications required under the approved state 

plan. State plans must also include a mechanism to temporarily 

or permanently revoke the qualification status of an independent 

verifier, such that it can no longer provide verification 

services related to an eligibility application or M&V report for 
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at least the duration of the period it does not meet the 

qualification requirements for independent verifiers in an 

approved state plan. The EPA’s proposed model rate-based 

emission trading rule contains provisions addressing 

accreditation and conflicts of interest for independent 

verifiers. State plans that adopt the finalized model rule could 

be presumptively approvable with respect to these requirements 

regarding independent verifiers. 

The state’s eligibility requirements and application 

procedures must ensure that only eligible actions may generate 

ERCs and that documentation is submitted only once for each 

program or project, and to only one state program.1271 These 

provisions will ensure that actions that are eligible for the 

issuance of ERCs are “non-duplicative.”1272 The tracking system 

used to administer a state’s rate-based emission trading system 

must provide transparent, electronic, public access to 

information about program and project eligibility applications, 

including EM&V plans, and regulatory approval status. 

 In the second step of the process, following implementation 

 

1271 This includes ensuring that multiple parties do not submit an 

eligibility application for the same EE program or project, or 

for the same RE generator. 

1272 Emission standards must be “non-duplicative” as described in 

section VIII.D.2. 
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of the RE/EE program or project (as described in this example) 

that was approved in step one, the RE/EE provider periodically 

submits a M&V report to the state regulatory body documenting 

the results of the program or project in MWh of electric 

generation or energy savings.1273 These results are quantified 

according to the EM&V plan that was approved as part of step 

one. These results are verified by an accredited independent 

verifier, and its verification assessment must be included as 

part of the M&V report submitted to the state regulatory body. 

The administering state regulator (or its agent) then reviews 

the M&V report, and determines the number of ERCs (if any) that 

should be issued, based on the report. Finally, the state 

regulatory body (or its agent) issues ERCs to the provider of 

the approved program or project. These ERCs are issued to the 

tracking system account held by the program or project provider. 

 State plan requirements must ensure that only one ERC is 

issued for each verified MWh. This is addressed through 

registration in the tracking system of programs and projects 

 

1273 State rate-based emission trading program regulations must 

specify the frequency for submission of M&V reports for approved 

qualified measures that have been deemed eligible to generate 

ERCs. These reporting periods should be annual, but a state 

could consider shorter or longer periods, depending on the type 

of ERC resource. 
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that have been qualified for the issuance of ERCs, to ensure 

that documentation is submitted only once for each RE/EE action, 

and to only one state program.1274 The tracking system must 

provide transparent electronic public access to submitted M&V 

reports and regulatory approvals related to such reports.1275 Such 

reports are the basis for issuance of ERCs. 

c. Tracking system requirements. State requirements must include 

provisions to ensure that ERCs issued to any eligible entity are 

properly tracked from issuance to submission by affected EGUs 

for compliance (where ERCs are “surrendered” by the owner or 

operator of an affected EGU and “retired” or “cancelled” by the 

administering state regulatory body), to ensure they are only 

used once to meet a regulatory obligation. This is addressed 

through specified requirements for tracking system account 

holders, ERC issuance, ERC transfers among accounts, compliance 

true-up for affected EGUs,1276 and an accompanying tracking system 

 

1274 EE/RE programs and projects, and other eligible measures, 

with an approved eligibility application would be designated in 

a tracking system as qualified programs or projects. Qualified 

programs and projects may be issued ERCs, based on approved M&V 

reports. 

1275 This must include electronic Internet access to such 

information in the tracking system. 

1276 “Compliance true-up” refers to ERC submission by an owner or 

operator of an affected EGU to adjust a reported CO2 emission 

rate, and determination of whether the adjusted rate is equal to 

or lower than the applicable rate-based emission limitstandard. 
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that meets requirements specified in the emission trading 

program regulations. Each issued ERC must have a unique 

identifier (e.g., serial number) and the tracking system must 

provide for traceability of issued ERCs back to the program or 

project for which they were issued. 

The EPA received a number of comments from states and 

stakeholders about the value of the EPA’s support in developing 

and/or administering tracking systems to support state 

administration of rate-based emission trading systems. This 

could include regional systems and/or a national system. The EPA 

is exploring options for providing such support and is 

conducting an initial scoping assessment of tracking system 

support needs and functionality. 

d. Effect of improperly issued ERCs. Because the goal of this 

rulemaking is the actual reduction of CO2 emissions, it is 

fundamental that ERCs represent the MWh of energy generation or 

savings they purport to represent. To this end, only valid ERCs 

that actually meet the standards articulated in this rule may be 

used to satisfy any aspect of compliance by an affected EGU with 

emission standards. Despite safeguards included in the structure 

of ERC issuance and tracking systems, such as the review of 

eligibility applications and M&V reports, and state issuance of 

ERCs, ERCs may be issued that do not, in fact, represent 
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eligible zero-emission MWh as required in the emission 

guidelines. A variety of situations may result in such improper 

ERC issuance, ranging from simple paperwork errors to outright 

fraud.

 An approvable state plan that allows affected EGUs to 

comply with their emission standards in part through reliance on 

ERCs must include provisions making clear that an affected EGU 

may only demonstrate compliance with an ERC that actually 

represents the one MWh of energy generation or savings that it 

purports to represent and otherwise meets the emission 

guidelines. 

e. Banking of ERCs. ERCs issued in 2022 or a subsequent year may 

be carried forward (or “banked”) and used for demonstrating 

compliance in a future year.1277 For example, an ERC issued for a 

MWh of RE generation that occurs in 2022 may be applied to 

adjust a CO2 emission rate in 2023 or future years without 

limitation. ERCs may be banked from the interim plan performance 

period to the final plan performance period. Banking provides a 

 

1277 States also have the option to participate in the CEIP, under 

which they can issue ERCs for MWh generation or savings that 

occur in 2020-2021 for measures implemented following submission 

of a final state plan, and receive matching ERCs from a federal 

pool. See section VIII.B.2 for a detailed discussion. The ERCs 

issued under this program can also be banked during and between 

the interim and final compliance period. 
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number of advantages while ensuring that the same outputweighted average CO2 emission rates of the interim and final 

state CO2 goals are achieved over the course of a state plan. 

Banking provisions have been used extensively in rate-based 

environmental programs and mass-based emission budget trading 

programs.1278 This is because banking reduces the cost of 

attaining the requirements of the regulation. The EPA has 

determined that the same rationale and outcomes apply under a CO2

emission rate approach, in that allowing banking will reduce 

compliance costs. Banking encourages additional emission 

reductions in the near-term if economic to meet a long-term 

emission rate constraint, which is beneficial due to social 

preferences for environmental improvements sooner rather than 

later.1279 State plans must specify whether the state is allowing 

or restricting the banking of ERCs between compliance periods 

 

1278 Banking under mass-based emission budget trading programs, 

and the rationale for banking provisions, is addressed below in 

section VIII.C.3.b.(J.2)(a)..c.

1279 The absence of banking creates an incentive to defer both 

relatively low-cost and higher-cost CO2 emission reduction 

actions until a later period when emission rate limits become 

more stringent, rather than incentives to undertake the low-cost 

activities sooner in order to further delay the high cost 

actions. Under a rate-based emission trading program, banking 

will encourage ERC providers to generate larger numbers of ERCs 

in early years of a plan performance period, in anticipation of 

rising ERC prices over time, when demand for ERCs is expected to 

increase as rate-based CO2 emission standards become more 

stringent. 
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for affected EGUs. State plans must also prohibit borrowing of 

any ERCs from future compliance periods by affected EGUs or 

eligible resources. 

f. Considerations for ERC issuance. The EPA notes that stateadministered and state-overseen EE programs, such as those 

administered by state-regulated electric distribution utilities, 

could play a key role in supplying energy savings to a ratebased emission trading system in the form of ERCs. These 

programs have been the primary means for delivering EE programs 

and energy savings at scale, and also allow for a state to 

conduct a portfolio planning process to guide EE program design 

and focus in a manner that best provides multiple benefits to 

electricity ratepayers in a state. Such portfolio planning 

processes typically treat EE as an energy resource comparable to 

electricity generation. 

 The EPA also notes that non–ERC certificates may be issued 

by states and other bodies for MWh of energy generation and 

energy savings that are used to meet other state regulatory 

requirements, such as state RPS and EERS, or by individuals to 

make environmental or other claims in voluntary markets. 

 The EPA defines an ERC in the emission guidelines as a 

tradable compliance instrument that represents a zero-emission 

MWh (for the purposes of meeting the emission guidelines) from a 
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qualifying measure that may be used to adjust the reported CO2

emission rate of an affected EGU subject to a rate-based 

emission standard in an approved state plan under CAA section 

111(d). The sole purpose of an ERC is for use by an affected EGU 

in demonstrating compliance with a rate-based emission standard 

in such an approved state plan. 

 An ERC is issued separately from any other instruments that 

may be issued for a MWh of energy generation or energy savings 

from a qualifying measure. Such other instruments may be issued 

for use in meeting other regulatory requirements (e.g., such as 

state RPS and EERS requirements) or for use in voluntary 

markets. An ERC may be issued based on the same data and 

verification requirements used by existing REC and EEC tracking 

systems for issuance of RECs and EECs. 

 The EPA notes that the definitions of other instruments, 

such as RECs, differ (as established under state statute, 

regulations, and PUC orders) and that requirements under state 

regulatory programs that use such instruments, such as state 

RPS, also differ. As a result, states may want to assess, when 

developing their state plan, how such existing instruments may 

interact with ERCs. For example, a state may want to assess how 

issuance of ERCs pursuant to a state plan may interact with 

compliance with a state RPS by entities affected under relevant 
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state RPS regulations or PUC orders. The interaction of other 

instruments and ERCs may also impact existing or future 

arrangements in the private marketplace. Actions taken by 

states, separate from the design of their state plan, could 

address a number of these potential interactions. For example, 

state RPS regulations that specify a REC for a MWh of RE 

generation, and the attributes related to that MWh, may or may 

not explicitly or implicitly recognize that the holder of the 

REC is also entitled to the issuance of an ERC for a MWh of 

electricity generation from the eligible RE resource. This could 

impact existing and future RE power purchase agreements or REC 

purchase agreements. Such interactions among existing 

instruments and ERCs could also impact how marketing claims are 

made in the voluntary RE market. How a state might choose to 

address these potential interactions will depend on a number of 

factors, including the utility regulatory structure in the 

state, existing statutory and regulatory requirements for state 

RPS, and existing RE power purchase agreements and REC 

contracts. 

g. Program review. The EPA is requiring that states periodically 

review the administration of their rate-based emission trading 

programs. The results of these program reviews must be submitted 

by states to the EPA as part of their required reports on the 
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implementation of their state plans, as described in sections 

VIII.D.a.(5) and VIII.D.2.b.(4), and must be made publicly 

available. Such a review submitted as part of a required state 

report provides for the implementation of rate-based emission 

standards per the requirements of CAA section 111(d)(2). For a 

rate-based emission trading program, the review must cover the 

reporting period addressed in the state’s periodic reports to 

the EPA on plan implementation. 

 The program review must address all aspects of the 

administration of a state’s rate-based emission trading program, 

including the state’s evaluations and regulatory decisions 

regarding eligibility applications for ERC resources and M&V 

reports (and associated EM&V activities), and the state’s 

issuance of ERCs. The program review must assess whether the 

program is being administered properly in accordance with the 

state’s approved plan; whether ERC eligibility applications and 

M&V reports are being properly evaluated and acted upon (i.e., 

approved or disapproved); whether reported annual MWh of 

generation and savings from qualified ERC resources are being 

properly quantified, verified, and reported in accordance with 

approved EM&V plans, and whether appropriate records are being 

maintained. The program review must also address determination 

of the eligibility of verifiers by the state and the conduct of 
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verifiers, including the quality of verifier reviews. Where 

significant deficiencies are identified by the state’s program 

review, those deficiencies must be rectified by the state in a 

timely manner. 

 States must collect, compile, and maintain sufficient data 

in an appropriate format to support the periodic program review. 

The EPA will review the results of each program review. The EPA 

may also audit a state’s administration of its rate-based 

emission trading program and pursue appropriate remedies where 

significant deficiencies are identified. 

3. EM&V requirements for RE, demand-side EE, and other measures 

used to adjust a CO2 rate 

This section discusses EM&V for RE, demand-side EE, and 

other measures that are used to generate ERCs or otherwise 

adjust an emission rate.1280 EM&V is applied for purposes of 

quantifying and verifying MWh in rate-based state plans, as 

described below. Rate-based state plans must require that 

eligible resources document in EM&V plans and M&V reports how 

all MWh saved and generated from eligible measures will be 

 

1280 EM&V is defined to mean the set of procedures, methods, and 

analytic approaches used to quantify the MWh from demand-side EE 

and RE and other measures, and thereby ensure that the resulting 

savings and generation are quantifiable and verifiable. 
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quantified and verified. Additionally, with respect to EM&V, the 

EPA’s proposed model rule identifies certain industry best 

practices that, upon finalization, could be adopted as 

presumptively approvable components of a state plan.1281 

As discussed in section VIII.K.1, quantified and verified 

MWh of RE generation, EE savings,1282 and other eligible measures 

may be used to adjust a CO2 emission rate when demonstrating 

compliance with the emission guidelines. In states implementing 

emission standard type plans with rate-based trading, affected 

EGUs adjust their reported emission rate using ERCs, which 

represent MWh that are quantified and verified according to the 

EM&V requirements described in this section. The EPA will 

evaluate the overall approvability of the state plan taking into 

consideration whether the state’s submitted EM&V requirements 

 

1281 The EPA recognizes that EM&V best practices are routinely 

evolving to reflect changes in markets, technologies and data 

availability. Therefore the agency is providing draft EM&V 

guidance with the proposed model rule, which can be updated over 

time to address any such changes to best practices. The guidance 

can also identify and describe alternative quantification 

approaches that may be approved for use, provided that such 

approaches meet the requirements of the finalized EM&V 

requirements. 

1282 In the context of demand-side EE, “measure” refers to an 

installed piece of equipment or system at an end-use energy 

consumer facility, a strategy intended to affect consumer energy 

use behaviors, or a modification of equipment, systems or 

operations that reduces the amount of electricity that would 

have delivered an equivalent or improved level of end-use 

service in the absence of EE. 
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satisfy these final emission guidelines. 

a. Discussion of proposed EM&V approach and public comment. The 

EPA proposed that a state plan that incorporates RE and demandside EE measures must include an EM&V plan that explains how the 

effect of these measures will be determined in the course of 

plan implementation. The proposal sought comment on the 

suitability of current state and utility EM&V approaches for RE 

and demand-side EE programs in the context of an approvable 

state plan, and on whether harmonization of state approaches, or 

supplemental actions and procedures, should be required in an 

approvable state plan, provided that supporting EM&V 

documentation meets applicable minimum requirements. In the 

proposal, the EPA also indicated that it would issue guidance to 

help states, sources, and project providers quantify and verify 

MWh savings and generation resulting from zero-emitting RE and 

demand-side EE efforts. 

The proposal and associated “State Plans Considerations” 

TSD1283 suggested that the EPA’s EM&V requirements could leverage 

existing industry practices, protocols, and tracking mechanisms 

currently utilized by the majority of states implementing RE and 

 

1283 See discussion beginning on p. 34 of the State Plan 

Considerations TSD for the Clean Power Plan Proposed Rule: 

http://www2.epa.gov/carbon-pollution-standards/clean-power-planproposed-rule-state-plan-considerations. 
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demand-side EE. The EPA further noted that many state regulatory 

bodies and other entities already have significant EM&V 

infrastructure in place and have been applying, refining, and 

enhancing their evaluation and quality assurance approaches for 

over 30 years, particularly with regard to the quantification 

and verification of energy savings resulting from utilityadministered EE programs. The proposal also observed that the 

majority of RE generation is typically quantified and verified 

using readily available, reliable, and transparent methods such 

as direct metering of MWh. 

As a result, the agency took comment on whether this 

infrastructure is appropriate in the context of approvable state 

plans for use in rate-based state plans that include RE, demandside EE, and other measures. The majority of commenters 

addressing this question responded affirmatively, indicating 

that existing EM&V infrastructure is appropriate to assure 

quality, credibility, and integrity. However, commenters also 

noted that EM&V methods are routinely improving and changing 

over time, and that the EPA’s requirements and guidance should 

be responsive to such changes, should avoid locking in outdated 

methods, and should be updated to maintain relevance. 

Another point made by commenters is that, despite the 

observed improvements in EM&V over time, quantification 
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knowledge is more robust for some EE program and policy types 

than for others. Additionally, there is relatively limited 

experience applying EM&V protocols and procedures to emission 

trading programs, where each MWh of replaced generation that can 

be bought and sold by a regulated source. As a result, the EPA’s 

final emission guidelines and proposed model rule include a 

number of safeguards and quality-control features that are 

intended to ensure the accuracy and reliability of quantified EE 

savings. 

b. Requirements for EM&V and M&V submittals. As discussed in 

section VIII.K.2, these final guidelines require that state 

plans include a requirement that EM&V plans and M&V reports be 

submitted to the state for rate-based emission trading programs. 

States must require that at the initiation of an eligible 

measure, project providers must develop and submit to the state 

an EM&V plan that documents how requirements for quantification 

and verification will be carried out over the period that MWh 

generation or savings are produced. States must also require 

that after a project or program is implemented, the provider 

must submit periodic M&V reports to confirm and describe how 

each of the requirements was applied. These reports must also 

specify the actual MWh savings or generation results, as 

quantified by applying EM&V methods on a retrospective (ex-post) 
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basis. States may not allow MWh values that are quantified using 

ex-ante (pre-implementation) estimates of savings. As previously 

described, the EPA took comment on the suitability of current 

state and utility EM&V approaches for RE and demand-side EE 

programs in the context of an approvable state plan. These final 

requirements regarding EM&V plans and M&V reports are intended 

to leverage and closely resemble those already in routine use. 

For energy generating resources, including RE resources, 

states may leverage the programs and infrastructure they have in 

place for achievement of their RPS and take advantage of 

registries in place for the issuance and tracking of RECs. Many 

existing REC tracking systems already include well-established 

safeguards, documentation requirements, and procedures for 

registry operations that could be adapted to serve similar 

functions in relation to the final emission guidelines. For 

example, a key element of RPS compliance in many states that 

parallels the final rule’s requirements is that each generating 

unit must be uniquely identified and recorded in a specified 

registry to avoid the double counting of credits at the time of 

issuance and retirement. In addition, the existing reports and 

documentation from tracking systems may, together with eligible 

independent third party verification reports, serve as the 

substantive basis for eligibility applications, EM&V plans and 
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M&V reports for the issuance of ERCs to energy generating 

resources for affected EGUs to meet their obligations under the 

final rule. With respect to actual monitoring requirements, many 

existing REC registries include provisions for the monitoring of 

MWh of generation that would be appropriate to meet state plan 

requirements pursuant to the final rule, such as requirements to 

use a revenue quality meter. 

For demand-side EE, states must require that EM&V plans 

that are developed for purposes of adjusting an emission rate 

under this final rule include several specific components. The 

EPA notes these components reflect existing provisions in a wide 

range of publicly or rate-payer funded EE programs and energy 

service company projects. One of these components state plans 

must require is a demonstration of how savings will be 

quantified and verified by applying industry best-practice 

protocols and guidelines, as well as an explanation of the key 

assumptions and data sources used. State plans must require EM&V 

plans to include and address the following: 

 A baseline that represents what would have happened in 

the absence of the EE intervention, such as the equipment 

that would most likely have been installed – or that a 

typical consumer or building owner would have continued 

using – in a given circumstance at the time of EE 
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implementation 

 The effects of changes in independent factors affecting 

energy consumption and savings; that is, factors not 

directly related to the EE action, such as weather, 

occupancy, or production levels 

 The length of time the EE action is anticipated to 

continue to remain in place and operable, effectively 

providing savings (in years) 

Examples and discussion of industry best-practices for 

executing each of the above-listed components is provided in the 

EPA’s draft EM&V guidance for demand-side EE, which is being 

released in conjunction with the proposed model rule. The model 

trading rule defines certain EM&V provisions for demand-side EE, 

as well as specific provisions for non-affected CHP and RE 

resources, including incremental hydroelectric power, biomass RE 

facilities, and waste-to-energy facilities, that may be 

presumptively approvable upon finalization. 

The EPA notes that state plans incorporating the finalized 

model rule for rate-based emission trading programs could be 

presumptively approvable as meeting the requirements of CAA 

section 111(d) and the EM&V provisions in these emission 

guidelines. The EPA will evaluate the approvability of such 

state plans through independent notice and comment rulemaking. 
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c. Skill certification standards. Using a skilled workforce to 

implement demand-side EE and RE projects and other measures 

intended to reduce CO2 emissions, and to evaluate, measure, 

quantify and verify the savings associated with EE projects or 

the additional generation from performance improvements at 

existing RE projects are both important in existing best 

industry practices. Several commenters pointed out that skill 

certification standards can help to assure quality and 

credibility of demand-side EE, RE, and other CO2 emission 

reduction projects. The EPA also recognizes that a skilled 

workforce performing the EM&V is important to substantiate the 

authenticity of emissions reductions. 

The EPA is therefore recommending in conjunction with the 

EM&V requirements discussed in this section, that states are 

encouraged to include in their plans a description of how states 

will ensure that the skills of workers installing demand-side EE 

and RE projects or other measures intended to reduce CO2

emissions as well as the skills of workers who perform the EM&V 

of demand-side EE and RE performance will be certified by a 

third party entity that:

1) Develops a competency based program aligned with a job 

task analysis and certification scheme; 

2) Engages with subject matter experts in the development 
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of the job task analysis and certification schemes that 

represent appropriate qualifications, categories of the 

jobs, and levels of experience; 

3) Has clearly documented the process used to develop the 

job task analysis and certification schemes, covering such 

elements as the job description, knowledge, skills, and 

abilities; 

4) Has pursued third-party accreditation aligned with 

consensus-based standards, for example ISO/IEC 17024. 

Examples of such entities include: parties aligned with the 

Department of Energy’s (DOE) Better Building Workforce 

Guidelines and validated by a third party accrediting body 

recognized by DOE; or by an apprenticeship program that is 

registered with the federal Department of Labor (DOL), Office of 

Apprenticeship; or with a state apprenticeship program approved 

by the DOL, or by another skill certification validated by a 

third party accrediting body. This can help to substantiate the 

authenticity of emission reductions due to demand-side EE and RE 

and other CO2 emission reduction measures. 

4. Multi-state coordination: rate-based emission trading 

programs 

Individual rate-based state plans may provide for the 

interstate transfer of ERCs, which would enable an ERC issued by 
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one state to be used for compliance by an affected EGU with a 

rate-based emission standard in another state. Such plans would 

include regulatory provisions in each state’s emission standard 

requirements that indicate that ERCs issued in other partner 

states may be used by affected EGUs for compliance. Such plans 

must indicate how ERCs will be tracked from issuance through use 

for compliance, through either a joint tracking system, 

interoperable tracking systems, or an EPA-administered tracking 

system.1284

The approaches described in this section are only allowed 

for states that impose rate-based emission limits for affected 

EGUs that are equal to the CO2 emission performance levels in the 

emission guidelines. This approach is necessary to ensure that 

each state that is allowing for the interstate transfer of ERCs 

is implementing rate-based emission standards for affected EGUs 

at the same lb CO2/MWh level.1285 This assures that all the 

 

1284 The emission standards in each individual state plan must 

include regulatory provisions that address the issuance of ERCs 

and tracking of ERCs from issuance through use for compliance, 

as described in subsectionsection VIII.G.3K.2. The description 

here addresses how those regulatory provisions will be 

implemented through the use of a joint tracking system, 

interoperable tracking systems, or an EPA-administered tracking 

system. 

1285 As noted above in section VIII.C.6, states also have the 

option of implementing a multi-state plan with a single ratebased emission standard that applies to all affected EGUs in the 
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participating states are issuing ERCs to affected fossil steam 

and NGCC units that emit below their assigned emission standards 

on the same basis. 

 This approach avoids providing different incentives, in the 

form of issued ERCs, to affected steam generating units and NGCC 

units in different states that have comparable CO2 emission 

rates. Providing different incentives to similar affected EGUs 

across states could create distortionary effects that lead to 

shifts in generation among states based on the different CO2

emission rate standards applied by states to similar types of 

affected EGUs. Providing for the interstate trading of ERCs in 

this instance would exacerbate these distortionary effects by 

providing arbitrage opportunities. 

 When demonstrating that a state’s CO2 emission goal is 

achieved as a result of plan implementation, a state with 

linkages to other states would be required to demonstrate that 

any ERCs issued by another state that are used by affected EGUs 

in the state for compliance with its rate-based CO2 emission 

 

participating states. This approach would also allow for 

interstate transfers of ERCs. Under this approach, a rate-based 

multi-state plan would include emission standards for affected 

EGUs based on a weighted average rate-based emission goal, 

derived by calculating a weighted average CO2 emission rate based 

on the individual rate-based goals for each of the participating 

states and 2012 generation from affected EGUs.
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standards were issued by states with an EPA-approved state 

plan.1286

 States could implement these linkages among state plans 

with rate-based emission trading systems through three different

implementation approaches: (1) plans that are “ready-forinterstate-trading;” (2) plans that include specified bilateral 

or multilateral linkages; and (3) plans that provide for joint 

ERC issuance among states with materially consistent 

regulations. These approaches are summarized below: 

 Ready-for-interstate-trading plans: A state plan recognizes 

ERCs issued by any state with an EPA-approved plan that 

also uses a specified EPA-approved1287 or EPA-administered 

tracking system. Plans are approved individually. A state 

plan need not designate the individual states by name from 

which it would accept issued ERCs. States can join such a 

coordinated approach over time, without the need for plan 

 

1286 This could be done by reference to data in the tracking 

system used to implement a state’s rate-based emission trading 

program that identifies the origin of each ERC (e.g., by serial 

identifier). 

1287 The EPA would designate tracking systems that it has 

determined adequately address the integrity elements necessary 

for the issuance and tracking of ERCs, as described in 

subsectionsection VIII.C.5.c.(1).K.2. Under this approach, a 

state could include in its plan such a designated tracking 

system, which has already been reviewed by the EPA. 
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revisions.1288

 Specified bilateral linkage: States recognize ERCs issued 

by named partner states. Partner states must demonstrate 

that they use a shared tracking system, interoperable 

tracking systems, or an EPA-administered tracking system. 

Plans are approved individually, including review of the 

shared tracking system or interoperable tracking systems. 

 Joint ERC issuance: States implement materially consistent 

rate-based emission trading program regulations and share a 

tracking system. States coordinate their review of 

submissions for ERC issuance1289 and their issuance of ERCs 

to the shared tracking system. Issued ERCs are recognized 

as usable for compliance in all states using the shared 

 

1288 The EPA notes that it is proposing a model rule for a ratebased emission trading program that could be used by states 

interested in implementing a ready-for-interstate-trading plan 

approach. A state plan that included the finalized rate-based 

model rule could be presumptively approvable as meeting the 

requirements of CAA section 111(d) and the emission guidelines. 

If a state plan also met the requirements described in this 

section for ready-for-interstate-trading plans, it could be 

approved as ready-for-interstate trading. 

1289 This refers to eligibility applications and monitoring and 

verificationM&V reports, which are required submittals for nonaffected EGU entities seeking the issuance of ERCs. Where 

affected EGUs are issued ERCs for emission performance below a 

specified CO2 emission rate, these ERCs are issued by the 

individual state in which they are subject to a rate-based 

emission standard. Requirements for ERC issuance are discussed 

in subsectionsection VIII.G.3K.2. 
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tracking system. Plans are approved individually, including 

review of the shared tracking system. 

 These implementation approaches are designed to streamline 

the process for linking emission trading programs, avoid or 

limit the need for plan revisions as new states join a 

collaborative emission trading approach, and facilitate the 

development of regional or broader multi-state markets for 

ERCs.1290 

L. Treatment of interstate effectsInterstate Effects 

 This section discusses how differing characteristics 

across states and sources could create risks of increased 

emissions under this rule through double counting of emission 

reduction measures or through foregone emission reductions due 

to movement of generation from source to source. The section 

also discusses how the final rule addresses these concerns: 

 

1290 The EPA also notes that individual state plans may utilize RE 

and demand-side EE (and other eligible measures), that occur in 

other states, as described in section VIII.G.1L addressing 

interstate effects. Under an individual state plan, ERCs could 

be issued for RE and demand-side EE measures that occur in other 

states, provided the EE/RE provider submits the measures to the 

state and the measures meet requirements in the state’s ratebased emission trading program requirements. The multi-state 

approaches described above provide additional flexibility for 

states to informally and formally coordinate their 

implementation of rate-based plans across states while retaining 

individual rate-based state goals. 
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first, through the characteristics of goal-setting and the 

framework of state plans, and second, through specific 

requirements intended to minimize the risk of double counting 

and increased emissions.1291 

The section is structured as follows. First, this section 

discusses the dynamics that cause these risks to potentially 

arise. Second, it provides a discussion of how the risks of 

double counting and foregone reductions are minimized through 

the following provisions: the nature of the final emission 

performance rates, multi-state plan options that limit 

distortionary effects, the structure of mass-based plan and 

rate-based plan accounting for emission reductions measures, and 

specified restrictions on the counting in a rate-based plan of 

emission reduction measures located in a mass-based state. 

Finally, the section discusses how the rate-based accounting 

framework minimizes incentives to develop emission reduction 

measures in particular states due to differences in rates. 

In the June 2014 proposal, the EPA acknowledged that 

emission reduction measures implemented under a state plan will 

 

1291 This section does not discuss emission leakage and how it is 

addressed by this final rule. See section VII.D for a discussion 

of emission leakage and its impact on state goal equivalence. 

See section VIII.J for a discussion of requirements for massbased plans to address leakage.
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likely have impacts across many affected sources both within and 

across state boundaries due to the dynamic and interstate nature 

of the electric grid, as is discussed above in section VIII.G..

These interactions, herein called interstate effects, may be 

driven in part due to differences in power sector dynamics 

across states, including the types of affected EGUs in a state, 

the availability of eligible nonzero-emitting resources, and the 

costs of different compliance options and existing policies in 

states. These state-level characteristics play out across 

dynamic regional grids that provide electricity across state 

bordersstates. EGUs are dispatched both within and across state 

borders and are constantly adjusting behavior in response to 

available generation and electricity demand on the regional 

grid. Whenever CO2 emission reduction measures, such as RE or 

demand-side EE, are implemented, the RE or demand-side EEmeasure

can affect EGU generation and CO2 emissions across the regional 

grid. These dynamicsimpacts can change across multiple affected 

EGUs on a minute-to-minute, hour-to-hour, and day-to-day basis 

as electricity demand changes and different generating resources 

are dispatched. These dynamicsimpacts will also change in the 

long-term, as the generating fleet and load behavior change over 

a period of years. Interactions among EGUs across states may be 

further driven by the plan types (i.e., rate-based or mass-
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based) and the individual characteristics of the plans that 

states choose to adopt. 

In the context of this complex environment of federal and 

state policies and interstate grids, commenters expressed 

concern about the risk of double-counting of measure impacts, 

particularly across states and thestate plans. Commenters stated 

that there is potential for distortionary incentives between 

states that could undermine overall CO2 emission reductions 

(i.e.,often termed emissions “leakage”). Commenters requested 

that the EPA ensure that states avoid double-counting and 

minimize leakage effects when demonstrating achievement of state 

goals and minimize leakage effects.. 

The EPA acknowledges that some amount of interstate 

effectsshifts in generation between sources within and across 

state borders will inevitably be present and unavoidable in the 

context of this rule and may affect how affected EGUs achieve 

the applicable CO2 performance rates or state goals under a state 

plan. In fact, the definition of the BSER is premised upon 

shifts in generation across sources, particularly shifts from 

higher- to lower-emitting units that result in overall emission 

reductions. However, in the context of these shifts, the extent 

to which the movement of generation may be driven not by the 

potential to capture lower-cost emission reduction but by 
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arbitrage across different emission rates, causing 

inefficiencies in the power markets and possibly eroding overall 

emission reductions, should be minimized. 

 In particular, the EPA has determined final emission 

performance rates that serve to reduce relative differences 

between state goals, and thus also focus the potential for 

generation shifting between affected EGUs on achieving the 

emission reductions quantified in the BSER. In the proposal, 

goals differed more substantially between states based upon an 

assessment of what emission reduction potential units could 

access located within their state. Commenters observed that due 

to the interconnected nature of the power sector, units are not 

limited to such emission reduction measures within their state, 

and indeed any operational decisions that units take necessarily 

influence operational decisions at other units throughout the 

interconnected grid. As a result, in the final rule, we are 

finalizing CO2 emission performance rates, informed by regional 

emission reduction potential, for fossil fuel-fired electric 

utility steam generating units and stationary combustion 

turbines that are applied consistently across all affected EGUs. 

As the same source category-specific performance rates are 

applied to all units in the contiguous U.S. regardless of the 

state in which they are located, any differences between state 
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goals in this final rule stem only from the relative prevalence 

in each state of fossil fuel-fired electric utility steam 

generating units and stationary combustion turbines. 

Consequently, there is substantially less incentive in this 

final rule for units to shift generation across state lines 

based solely on differences in state goals, since there is 

substantially less difference between the final rule’s state 

goals, and since those state goals are themselves premised on 

nationally consistent source category-specific performance 

rates. 

The EPA has also incorporated elements into the rule that 

seek to minimize interstate effects.double-counting and the 

distortionary effects that could potentially increase emissions.

First, states have the option to adopt multi-state 

complianceplans that reflectsreflect regional interactions. 

while eliminating chances for double counting and providing a 

level playing field for trading of rate-based ERCs or mass-based 

allowances. Second, in the method for rate-based plan 

compliance, the rule provides a general accounting approach for 

adjusting a sourcean affected EGU’s or state’s CO2 rate that 

inherently acts to minimize state differences. Third, the final 

CO2 performance rates uniformly apply the same standard for 

affected source sectors across the states and also account for 
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the regional supply of RE available to states. These points are 

further discussed below. 

For both rate-based and mass-based approaches, the rule 

provides states with the option of creating either multi-state 

plans or trading-ready plans. Both strategies can be effective 

in minimizing interstate effects because the regional impacts of 

emission reduction actions across states contribute to meeting 

aggregate rate-based or mass-based CO2 emission goals“ready-forinterstate-trading” plans or multi-state plans. These options 

for states working together provide opportunities to enable 

protections against double counting and minimize the presence of 

distortionary effects. 

“Ready-for-interstate-trading” and multi-state plans engage 

multiple states in the same system for the purpose of trading 

mass-based allowances or issuing and trading rate-based ERCs. 

This allows for efficient implementation of protections against 

double counting provided in state plan requirements, as multiple 

state are participating in the same tracking systems. This is 

particularly useful in the context of rate-based ERC issuance 

and tracking, where it must be ensured that the ERCs being 

generated are unique across rate-based plans. 

This final rule also reduces distortionary effects within 

the context of multi-state plans. It does so by restricting 
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states to interstate trading with equivalently denominated massbased allowances or rate-based ERCs. In a mass-based context, 

all affected EGUs will trade uniform mass-based allowances, 

whether in a “ready-for-interstate-trading” plan or multi-state 

plan. In a rate-based plan context, “ready-for-interstatetrading” states must all adopt as their goal the CO2 emission 

performance rates as their joint goal. This assures that all the 

participating states are issuing ERCs using the same 

subcategorized performance rates, and that the sources in each 

state have equivalent incentives for trading ERCs. Similarly, 

under multi-state plans, the relevant states must choose to 

adopt identical rates, either the CO2 emission performance rates 

or a weighted average goal rate based on the rate-based goals of 

all the states involved. These requirements along with a method 

for calculating a weighted average goal rate are specified in 

section VIII.C.5. 

 Under all types of state plans, states must ensure that the 

emission reduction measures and associated CO2 emission 

reductions counted as part of meeting their plan requirements 

are not duplicative of any measures that are counted by another 

state. Interstate effects make this more difficult because 

states may be responsible for the deployment of measures that 

have effects on generation and emissions beyond the state 
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borders., in order to avoid double counting of the MWhs of 

generation or energy savings that these measure produce. 

Depending on the accounting method used to reflect these 

measures in state goals, interstate effects could still allow 

for the double counting of the emission reductions resulting 

from these measures, particularly if mathematical adjustments 

were made to stack emissions to reflect these reductions.

Depending on how these measures are accounted for, the 

reductions could be counted by both the state that deployed the 

measure, and the state that reports a reduction in fossil 

generation or reported emissions. In this final rule, the MWhbased general accounting approaches for both mass-based and 

rate-based plans minimizehave been specifically designed to 

eliminate the risk of double counting. of reductions, because 

emission reduction measures are accounted for only through their 

inherent impact on stack emissions for affected EGUs. 

Mass-based plans rely exclusively on reported stack 

emissions for determining whether a mass-based CO2 emission goal 

is achieved. This means that under a mass-based plan any 

emission reduction measures that are implemented are 

automatically accounted for in reduced stack emissions of CO2

from affected EGUs, which avoids concerns about counting the 

same mass reductions in two different mass-based states. 
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In a rate-based plan, there needs to be an explicit 

adjustment of reported CO2 emission rates from affected EGUs, to 

reflect the measures that substitute low- or zero-emitting 

generation or energy savings for affected EGU generation. States 

with rate-based plans must demonstrate that the RE and demandside EE that they usemeasures used to adjust their CO2 emission 

rate, such as RE and demand-side EE, are non-duplicative. The 

proposal attempted to address this issue in part by limiting 

demand-side EE that states could claim to in-state measures. In 

fact, those in-state measures still have an impact outside of 

the state and under the proposal’s approach, states arewould 

have been restricted from taking credit for all the measures 

they have put in place that reduce CO2 emissions. Therefore, the 

EPA is finalizing a treatment that allows states to count all 

in-state and out-of-state measures, while addressing interstate 

effects through the structure of itsthe rule’s accounting 

approach for adjusting the CO2 emission rate of an affected EGU, 

detailed in section VIII.CK.1 above, used to show that the state 

has met its obligation under its state plan. 

 The general accounting approach for adjusting the CO2

emission rate of an affected EGU inherently accounts for the 

regional nature of how substitute generation and energy savings 

will impact affected EGU generation and CO2 emissions. The 
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following discussions refer to the substituting generation and 

energy savings in question as RE and demand-side EE, but this 

method can apply to other non-measures that were not included in 

the determination of the BSER technologies that substitute for 

affected EGU generation. The adjusted CO2 emission rate gives 

credit to the affected EGU or state for the MWhs of RE and 

demand-side EE it is responsible for deploying, by allowing 

those MWhs to be added to the denominator of the CO2 rate, but 

makes no adjustment to the numerator. Instead, the numerator 

reflects reported stack emissions, which will reflect the extent 

to which RE and demand-side EE reduced the affected EGU’s 

generation and emissions, without needing to account for the 

state in which the RE or demand-side EE originated, or 

approximating exactly how it impacted the regional grid. 

Across states with rate-based plans, the accounting method 

avoids potential double-counting of both components of a CO2

emission rate: CO2 emission reductions and generation. Doublecounting of CO2 emission reductions is prevented because there is 

no explicit adjustment to the numerator of the reported CO2

emission rate that could be redundant to CO2 emission reductions 

alreadyemissions from each unit are represented in the numerator 

of each of those units’ emission rates, and those real emissions 

capture whatever emission reduction impact occurred with regard 
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to any particular MWh of RE or demand-side EE. Because the 

general accounting approach disallows any adjustment to any 

EGU’s reported CO2 emissions from, it is not possible for the 

affected EGU, resulting inreal emission reductions prompted by 

any particular measure to be double-counting.1292 counted. 

Double-counting of MWhs in the denominator can be avoided 

because adding the MWhit is relatively straightforward to 

quantify the MWhs that the affected EGU is responsible for 

deploying and add them to the denominator is relatively 

straightforward to quantify and assign, and, and this method

aligns well with the MWh-denominated trading system described in 

this final rule. As long as it is assured that the MWhs of RE 

and demand-side EE are only being claimed by one affected EGU or 

state, as is outlined in section VIII.C.2K, then there is no 

double-counting of MWh. Therefore, the accounting method avoids 

double counting of both CO2 emission reductions and MWhs, the two 

characteristics of RE and demand-side EE measures that affect CO2

emission rates. For further discussion of the MWh-based 

accounting method, including a calculation example, see section 

 

1292 If a MWh of substitute generation or avoided generation 

replaced generation at another affected EGU, CO2 emission 

reductions would be represented in reduced reported CO2 emissions 

from that affected EGU. Again, a double-counting of emission 

reduction effects would occur. 
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VIII.K.1.

 There may also be interactions between mass-based and ratebased plans regarding counting measures, specifically where 

measures that provide substitute or avoided generation, such as 

RE and demand-side EE, are located in a mass-based state and can 

also be used by a rate-based state in meeting the CO2 performance 

rates or state goals. The EPA received comments on this 

particular issue, and many expressed concerns that this use of 

mass-based resources in a rate-based state would result in 

double-counting of emission reductions. 

Commenters provided analyses specifying how two states can 

benefit from the same RE and demand-side EE measures as a result 

of rate- and mass-based plan interactions. Some commenters 

considered this double-counting of emission reductions, and 

requested specific mathematical adjustments of reported 

generation or CO2 emissions from affected EGUs under either ratebased or mass-based state plans in order to eliminate doublecounting. 

The EPA has determined that, in the context of interactions 

among rate-based and mass-based plans, there is not explicit 

double-counting of the CO2 emission reductions associated with 

counting measures located in mass-based states, considering the 

accounting methods outlined in this final rule. First, as 
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discussed above, the accounting method for adjusting the CO2

emission rate only counts the MWhs generated by a measure to 

adjust the MWh in the denominator of its reported CO2 emission 

rate. The CO2 emissions impacts of the measures will be reflected 

in the rate-based state only to the extent that the MWhs 

resulted in lower reported CO2 emissions from an affected EGU in 

the rate-based state. To the extent that measures that provide 

substitute or avoided generation reduce generation from affected 

EGUs in a mass-based state, the effect of those measures is 

reflected in lower reported CO2 emissions. of the mass-based 

EGUs. The CO2 emission reductions reflected in the rate and the 

mass state will necessarily be mutually exclusive, because both 

are based on reported stack emissions. Additionally, the 

mechanism in the mass-based state that is assuring CO2 emission 

reductions is the mass goal or capbudget, which is met by 

affected sourcesEGUs adjusting their generation. Low- or zeroemitting MWhs from resources like RE and demand-side EE can 

serve load in the mass-based state and play a role in lowering 

compliance costs, but they play no direct role in mass-based 

compliance. As a result, no double-counting of emission 

reductions can take place. 

Though there is no risk of double-counting emissions, some 

commenters expressed the concern that overall CO2 emissions 
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reductions would be erodedforegone in situations where a source 

in a rate-based state counts the MWh from measures in a massbased state, but the generation from that measure acts solely to 

serve load in the mass-based state. As a resultIn that scenario, 

expected CO2 emission reduction actions in the rate-based state 

are foregone as a result of counting MWh that resulted in CO2

emission reductions in a mass-based state. Therefore the EPA is 

restricting the ability of rate-based states to claim emission 

reduction measures, such as RE and demand-side EE, located in 

mass-based states. 

While the EPA understands this concern regarding foregone 

reductions, we do not believe it is appropriate to restrict RE

and demand-side EE crediting unilaterally between rate-based and 

mass-based states. Such a restriction could cut some states off 

from regional RE supplies that are assumed in the BSER building 

block 3 and incorporated in the CO2 emission performance rates 

orand state rate-based CO2 goals in the emission guidelines..

Allowing crediting between rate- and mass-based states, as long 

as the risk of foregone CO2 emission reduction actions in ratebased states are minimized, will assure a supply of eligible 

low- and zero-emittingRE MWhs that will further enable affected 

EGUs and states to meet obligations under the final rule. 

Therefore, the EPA has determined that it is appropriate for 
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rate-based states to count MWhs from RE or demand-side EE 

measures, or similar low- or zero-emitting measures, located in 

mass-based states only if the measure is implemented, subject to 

the condition that the generation in question was intended to 

meet electricity load in a state with a rate-based plan.1293 This 

may apply to some or all of the generation from an individual RE 

installation. To assure that measures used to adjust a CO2

emission rate meetthe RE generation in question meets this 

condition, the EPA is requiring that measures providing zero- or 

low-emittingRE generation from non-affected EGUsRE installations

located in a mass-based state, such as RE, can only be counted 

in a rate-based state if the energyelectricity generated is 

delivered with the intention to meet load in a state with a 

rate-based plan., and was treated as a generation resource used 

to serve regional load that included the rate-based state. This 

can be demonstrated through, for example: 1), the provision of a 

power delivery contract or power purchase agreement in which an 

entity in the rate-based state contracts for the supply of the 

mass-based MWhs in question and 2) documentation that this was 

done specifically to serve rate-based state load. The EPA is 

 

1293 This does not need to necessarily be the state where the MWh 

of energy generation from the RE measure is used to adjust the 

CO2 emission rate of an affected EGU. 
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providing flexibility to states regarding the nature of the 

required demonstration, though the state must specify eligible 

demonstrations for approval in state plans. Under an emission 

standards plan, this demonstration would be made by the provider 

of the measure seeking ERC issuance to the rate-based state. 

Under an emission standards plan, this demonstration would 

be made by the provider of the measure seeking ERC issuance to 

the rate-based state. Under a state measures plan, the ratebased state will need to provide the demonstration of geographic 

eligibility as part of its demonstration that it is meeting its 

CO2 emission performance rates or achieving the state CO2

emission goal for affected EGUs. 

 The following are examples of how requirements for a 

demonstration could be established in state plans and used to 

allow a resourceRE in a mass-based state to be counted in a 

rate-based state. For an emissionsemission standards state plan, 

a state could specify in the regulations for the rate-based 

emission standards included in its state plan that it will 

require aan RE provider of RE that seeks the issuance of ERCs to 

show that load-serving entities in the rate-based state have 

contracted for the delivery of the RE generation that occurs in 

a mass-based state to meet load in a rate-based state. Under 

this approach, an RE provider in a mass-based state could submit 
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as part of an eligibility application a delivery contract or 

power purchase agreement showing that the energy savings were 

generation was procured by the utility, and werewas treated as 

comparable to a generation resource used to serve regional load 

that included the rate-based state. This documentation would be 

sufficient demonstration to allow the RE generating resource to 

meet thethis additional geographic eligibility requirement for 

the amount of generation of ERCsin question. All quantified and 

verified RE MWhs submitted for ERC issuance would need to be 

associated with that power purchase contract or agreement, and 

this fact would need to be demonstrated in the monitoring and 

verificationM&V reports submitted for issuance of ERCs. 

 Under a state measures rate-based plan, a state could 

require that any eligible MWhs that the state claims from a 

mass-based state are the result of contracted arrangements 

between entities in the rate-based state and providers in the 

mass-based state. If the state plan was approved by the EPA, 

such demonstrations would need to be submitted with the state’s 

demonstration of how its state measures meet the CO2 emission 

performance rates or achieve the state rate-based CO2 emission 

goal for affected EGUs. 

 The ability for a rate-based state to count MWhs located in 

a mass-based state under the above conditions is limited to non-
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affected generatingRE. Rate-based states are not allowed to 

claim demand-side EE or any other emission reduction measures 

that were not included in the determination of the BSER located 

in mass-based states for ERC issuance. While this limits ratebased sources’ access to additional resources that are 

considered low- or zero-emitting, such as RE., providing that 

access would result in a risk of foregone reductions. Further, 

unlike RE, there is no obligation related to demand-side EE and 

other measures that were not included in the determination of 

the BSER incorporated in the CO2 emission performance rates or 

state rate-based goals which would necessitate facilitating 

access to those resources. This treatment also does not apply to 

fossil-fuel fired EGUs, such as NGCC units. If a mass-based 

emission limitstandard has been applied to an affected EGU, 

there is no valid way to calculate whether it has MWh that are 

eligible for crediting, as is possible under a rate-based plan. 

AsFinally, as stated earlier, commenters also expressed 

concern about the potential for a loss of emission reductions 

relative increases in emissions to occur given relative 

differences between sources and states. These differences could 

include states’ goals under either the rate- or mass-based 

approaches, or states’ accounting of new sources. These 

differences could induce increased generation in one state over 
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another because the costs of compliance and relative costs of 

generation would vary between states. There was particular 

concern regarding how these differences would provide incentives 

for building newincreasing generation at new fossil sources and 

expanding utilization of existing affected EGU generation in 

states that have less stringent goals., and that this movement 

of generation would result in increased emissions overall. This 

could potentially result in the achievement of performance rates 

but with fewer overall CO2 emissions reductions than projected 

nationally under the proposal. 

 In order to address these concerns, the EPA has determined 

final performance rates that serve to reduce relative 

differences between state goals, and thus the risk of leakage 

based upon those effects. In the proposal, goals differed 

significantly between states based upon individual assumptions 

included in the calculation. In the final rule, we are 

finalizing CO2 emission performance rates for fossil fuel-fired 

electric utility steam generating units and stationary 

combustion turbines that are applied consistently across all 

affected EGUs. Additionally, these finalized performance rates 

were calculated regionally, further narrowing the differences 

across states. As the same sector performance rates are applied 

to all states, any differences stem from the relative prevalence 
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of fossil fuel-fired electric utility steam generating units and 

stationary combustion turbines. 

Commenters also suggested that the issuance and trading of 

emission credits across states under a rate-based approach would 

result in incentives to create credits, through the development 

of RE for example, in certain states with higher state goals, 

and this could also be a source of increased overall emissions. 

They noted that RE siting would thus not occur in the most 

optimal locations. The commenters assumed that zero-emitting 

credits are denominated in mass units by multiplying the number 

of MWh by some emission rate: either the state goal rate, the 

current state emission rate, a regional emission rate, or a 

calculated marginal rate. If those rates were higher in any 

states, zero-emitting MWhs would create more mass-denominated 

credits in those states, and thus RE and demand-side EE would be 

more valuable. 

 The incentive to target the location of zero-emitting 

generation or energy savings between states based on variation 

in its emission reduction value has been minimized by the fact 

that states participating in rate-based interstate trading must 

adopt the same emission performance rates or rate-based state 

goals. It is further minimized, even outside of an interstate 

trading framework, by the nature of the accounting method 
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finalized in this rule. As explained above onregarding the 

general accounting approach and on the trading framework, we are 

adjusting rates using calculated MWhs, not based upon an 

emission reduction approximation as commenters outlined above. 

Not only does the method allow emission reductions to be 

accounted for as they occur across the grid, but it means the 

ERCs being traded across states represent one MWh of zeroemitting generation in whatever state it originated, and its 

value is unaffected by any emission rate associated with its 

state of origin. Thus, the finalized accounting and trading 

methods minimize the relative incentives for generating zeroemitting ERCs in a particular state based upon the rates that 

apply to that state.

3. Requirements for rate-based emission trading approaches 

 As with all approaches under the emission standards plan 

type, emission standards in a state plan that include a ratebased emission trading program must be quantifiable, verifiable, 

enforceable, non-duplicative and permanent.1294 A state plan using 

a rate-based emission trading approach must include emission 

standards for affected EGUs that include requirements specifying 

 

1294 These requirements are described in detail in section 

VIII.D.2.
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the rate-based emission standards and related implementation and 

compliance requirements and mechanisms.1295 These related 

requirements include those applicable to rate-based emission 

standards more broadly: CO2 emission monitoring, reporting, and 

recordkeeping requirements for affected EGUs, including 

requirements for monitoring and reporting of useful energy 

output. Related requirements for a rate-based emission trading 

program more specifically include provisions for issuance of 

ERCs by the state and/or its designated agent; provisions for 

tracking ERCs, from issuance through submission for compliance; 

and the administrative process for submission of ERCs by the 

owner or operator of an affected EGU to the state, in order to 

adjust its reported CO2 emission rate when demonstrating 

compliance with a rate-based emission standard.1296 These 

requirements specific to rate-based emission trading programs 

are design elements the EPA has determined are necessary to 

assure the integrity of a rate-based approach that includes an 

emission trading program, and therefore assures a state plan 

utilizing such an approach appropriately provides for the 

 

1295 As described below, these requirements would likely be 

provided in a state plan in the form of state regulations, but 

could potentially be provided in another form. 

1296 See section VIII.G.1 for a discussion of the accounting 

method used to adjust a CO2 emission rate. 
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implementation of rate-based emission standards in accordance 

with CAA section 111(d). 

The EPA will review a state plan submittal including a 

rate-based emission trading program to assure that the plan 

contains the design elements necessary to assure the integrity 

of a rate-based approach, and therefore provide for the 

implementation of rate-based emission standards. These design 

elements are discussed in more detail in this subsection, and 

the EPA for each design element has also provided what it views 

as an appropriate way for states to meet each such element so as 

to provide for the implementation of rate-based emission 

standards through an emission trading program. The EPA expects 

that state plans containing a rate-based emission trading 

program that includes components as substantively described for 

each of the design elements will be presumptively approvable (so 

long as the rate-based emission standards are also appropriately 

demonstrated to achieve the CO2 emission performance rates or 

state CO2 goal). States may submit a rate-based emission trading 

program with alternative components other than those described, 

so long as the program includes each of the required design 

elements and the state satisfactorily demonstrates in the state 

plan submittal that such alternative means of addressing the 

design elements are as adequately stringent as the presumptively 
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approvable approach as described, and therefore provide for the 

implementation of the state plan’s rate-based emission 

standards. 

A state may issue ERCs to an affected EGU that performs at 

a CO2 emission rate below a specified CO2 emission rate, as well 

as to providers of qualifying measures that provide substitute 

generation for affected EGUs or avoid the need for generation 

from affected EGUs. This latter category includes providers of 

qualifying RE and demand-side EE measures, as well as other 

types of measures, as discussed in section VIII.G.1.b.1297 

 ERCs may be used by an affected EGU to adjust its reported 

CO2 emission rate when demonstrating compliance with a rate-based 

emission limit. This adjustment is made by adding MWh to the 

denominator of an affected EGU’s reported CO2 emission rate, in 

the amount of submitted ERCs, resulting in a lower adjusted 

rate. To demonstrate compliance with a rate-based emission 

standard, an affected EGU would report its CO2 lb/MWh emission 

 

1297 As used in this section, the term “EE program” refers to an 

EE deployment program. An EE program involves deployment of 

multiple EE measures or EE projects, such as utility- or stateadministered EE incentive programs that accelerate the 

deployment of EE technologies and practices. As used in this 

section, the term “EE/RE project” refers to a discrete EE 

project (e.g., an EE upgrade to a commercial building or set of 

buildings) or a RE generator (e.g., a single wind turbine or 

group of turbines).
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rate to the state regulatory body, and would also surrender to 

the state any ERCs it wishes to use to adjust its reported 

emission rate. The state regulator would then cancel the 

submitted ERCs and add the MWh the ERCs represent to the 

denominator of the affected EGU’s reported CO2 lb/MWh emission 

rate. If the affected EGU’s adjusted CO2 emission rate is equal 

to or lower than its applicable emission rate standard, the 

affected EGU would be in compliance. 

a. Issuance of ERCs to affected EGUs. ERCs may be issued to 

affected EGUs that emit below a specified CO2 emission rate. For 

issuance of ERCs to affected EGUs, the state plan must specify 

the accounting method and administrative process for ERC 

issuance. This includes the calculation method for determining 

the number of ERCs to be issued to an affected EGU, based on 

reported CO2 emissions and MWh energy output, in comparison to a 

reference CO2 emission rate. The reference rate is a specified 

CO2 lb/MWh emission rate that an affected EGU’s reported CO2

emission rate is compared to, when determining the amount of 

ERCs that may be issued to an affected EGU. 

Following determination of the number of ERCs an affected 

EGU is eligible to receive, based on an affected EGU’s reported 

CO2 emission rate compared to a specified reference rate, the 

state regulatory body would issue those ERCs into a tracking 
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system account held by the owner or operator of the affected 

EGU. Tracking system requirements are addressed below at section 

VIII.G.3.c. 

The accounting method that may be applied in a state plan 

differs depending on whether a state plan includes a single 

rate-based emission standard that applies to all affected EGUs 

(e.g., if a plan is designed to meet a state rate-based CO2 goal) 

or separate rate-based emission standards that apply to 

subcategories of affected EGUs, namely fossil fuel-fired 

electric utility steam generating units and stationary 

combustion turbines. In both cases, ERCs are issued in MWh, 

based on the difference between an affected EGU’s reported CO2

emission rate (in CO2 lb/MWh) and a specified CO2 lb/MWh emission 

rate that the reported rate is compared to (referred to as a 

“reference rate”). The reference rate may be an affected EGU’s 

assigned CO2 emission limit rate or another CO2 emission rate, as 

described below. Where an affected EGU’s reported CO2 emission 

rate is lower than the specified reference CO2 emission rate, 

ERCs may be issued. 

Where a state plan includes emission standards in the form 

of a single rate-based emission standard that applies to all 

affected EGUs, the reference rate is the CO2 emission rate limit 

for affected EGUs. In this instance, ERCs may be issued based on 
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an affected EGU’s reported CO2 emission rate as a proportion of 

the emission limit rate. For example, if the emission rate limit 

is 2,000 lb CO2/MWh and the affected EGU emits at a rate of 1,000 

lb CO2/MWh, 0.5 MWh would be awarded for every MWh generated by 

the affected EGU. ERCs would be issued to affected EGUs in whole 

MWh increments. The calculation method is as follows: 

ERCs1298 = reported MWh by affected EGU1299 x ((CO2 emission 

rate limit for affected EGUs1300 – affected EGU reported CO2

emission rate1301)/ CO2 emission rate limit for affected EGUs) 

For the example above, the calculation is as follows: 

ERCs = MWh reported x (2,000 – 1,000)/2,000 = MWh reported 

x 0.5 

If the affected EGU in this example generated 1,000,000 MWh, 

500,000 ERCs would be issued. 

Where a state plan includes separate emission standards for 

subcategories of affected EGUs, specifically affected fossil 

fuel-fired electric utility steam generating units and 

stationary combustion turbines, the reference rate differs for 

 

1298 For all calculations in this section, where the result is a 

negative value, no ERCs would be issued.

1299 This term represents the reported MWh by the affected EGU on 

an annual basis. 

1300 This term represents the “reference rate.” 1301 This term represents the annual reported CO2 emission rate of 

the affected EGU.
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affected fossil fuel-fired electric utility steam generating 

units and stationary combustion turbines. 

For affected steam generating units, the reference CO2

emission rate is the assigned CO2 emission rate limit for steam 

generating units. 

For affected steam generating units, the following 

accounting method for generating ERCs applies: 

ERCs1302 = reported MWh x ((steam generating unit CO2

emission rate limit1303 – steam generating unit reported CO2

emission rate)/ steam generating unit CO2 emission rate limit). 

For affected stationary combustion turbines, the reference 

CO2 emission rate differs for “non-incremental” generation and 

“incremental” generation from the affected stationary combustion 

turbine. Incremental generation by an affected EGU is defined as 

annual energy generation, in MWh, that is greater than reported 

MWh generation by the EGU in 2012. For example, assume an 

affected stationary combustion turbine generated 1,000,000 MWh 

in 2012 and 1,100,000 MWh in 2022; the stationary combustion 

turbine’s incremental generation in 2022 is 100,000 MWh and its 

non-incremental generation is 1,000,000 MWh. 

 

1302 For all calculations in this section, where the result is a 

negative value, no ERCs would be issued. 

1303 The “reference rate.” 
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For affected stationary combustion turbines, the following 

accounting method for generating ERCs applies for nonincremental generation: 

ERCs = reported MWh x ((stationary combustion turbine CO2

emission rate limit1304 – stationary combustion turbine reported 

CO2 emission rate)/ stationary combustion turbine CO2 emission 

rate limit) 

Under this approach, ERC issuance is assessed based on the 

difference between the CO2 emission rate limit for affected 

stationary combustion turbines1305 and the reported CO2 emission 

rate of the affected stationary combustion turbine. 

For affected stationary combustion turbines, the following 

accounting method for generating ERCs applies for incremental

generation: 

ERCs = reported MWh x [((steam generating unit CO2 emission 

rate limit1306 – stationary combustion turbine reported CO2

emission rate)/ steam generating unit CO2 emission rate limit) + 

((stationary combustion turbine CO2 emission rate limit1307 - 

stationary combustion turbine reported CO2 emission rate)/ 

 

1304 The “reference rate.” 1305 This is the CO2 emission performance level for affected 

stationary combustion turbines in the emission guidelines.

1306 The “reference rate.” 1307 The “reference rate.”
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stationary combustion turbine CO2 emission rate limit)] 

Under this approach, ERC issuance is assessed based in part 

on the difference between the CO2 emission performance level for 

fossil steam generating units and the reported CO2 emission rate 

of the affected stationary combustion turbine. The calculation 

also accounts for the difference in an affected stationary 

combustion turbine’s reported CO2 emission rate and the CO2 rate 

limit for affected stationary combustion turbines.1308 This avoids 

over-crediting where an affected stationary combustion turbine 

emits above its assigned CO2 emission rate limit. Overall, this 

calculation method allows for issuance of ERCs based on the 

ability of incremental generation from affected stationary 

combustion turbines to substitute for generation from affected 

steam generating units (as represented in building block 2), 

while also respecting the fact that affected stationary 

combustion turbines must also meet an assigned CO2 emission rate 

limit for the entirety of its MWh energy output. 

For example, assume an affected stationary combustion 

turbine with a CO2 emission rate of 800 lb CO2/MWh; a stationary 

combustion turbine CO2 emission rate limit of 700 lb CO2/MWh; and 

a steam generating unit CO2 emission rate limit of 1,300 lb 

 

1308 This is the CO2 emission performance level for affected 

stationary combustion turbines in the emission guidelines. 
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CO2/MWh. For every incremental MWh of reported energy generation 

by an affected stationary combustion turbine, ERCs would be 

issued in the following amount: 

ERCs = reported incremental MWh x [(1,300 – 800)/1,300 + 

(700 – 800)/700] = reported incremental MWh x [0.38 + (-0.14)] = 

reported MWh x 0.241309

Thus, for every incremental MWh of reported energy 

generation by an affected stationary combustion turbine, 0.24 

ERCs would be generated. ERCs would be issued in whole MWh 

increments. 

These accounting requirements maintain consistency with the 

EPA’s application of BSER when calculating CO2 emission 

performance rates for affected stationary combustion turbine and 

steam generating units. In particular, this accounting treatment 

maintains consistency of accounting in a state rate-based CO2

emission standard with the EPA’s application of building block 2 

 

1309 This calculation accounts for incremental generation from the 

affected stationary combustion turbine, while acknowledging that 

stationary combustion turbine generation is low-emitting, but 

not non-emitting. The calculation also acknowledges that in this 

instance, the affected stationary combustion turbine’s reported 

CO2 emission rate is higher than its applicable emission rate 

limit. As a result, for every MWh of generation, the stationary 

combustion turbine accrues a compliance debit that must be met 

through submission of ERCs. This calculation avoids overcrediting for incremental generation by affected stationary 

combustion turbines, where an affected stationary combustion 

turbine emits above its assigned CO2 emission rate limit. 
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in calculating CO2 emission performance rates for affected fossil 

fuel-fired electric utility steam generating units and 

stationary combustion turbines, which is based on use of 

incremental generation from affected stationary combustion 

turbine to replace generation from affected steam generating 

units. 

b. Issuance of ERCs for RE, demand-side EE, and other measures. 

ERCs may be issued for qualifying measures.1310 For issuance of 

ERCs for qualifying measures, state plan requirements for ERC 

issuance must include a two-step process. In the first step of 

the process, a potential ERC provider submits an eligibility 

application for a qualifying program or project1311 to the 

administering state regulator (or its agent1312). The state 

 

1310 Qualifying measures that can be used to adjust the CO2

emission rate of an affected EGU are discussed at 

subsectionsection VIII.GK.1, and include RE, demand-side EE, and 

other measures, such as DSM, CHP and incremental nuclear 

generation.

1311 For example, for an EE/RE program or project, as described in 

this section for illustrative purposes. The requirements 

described in this section for EE/RE programs and projects also 

apply for all other eligible qualifying measures discussed in 

subsectionsection VIII.GK.1. 

1312 As used here, an agent is a party acting on behalf of the 

state, based on authority vested in it by the state, pursuant to 

the legal authority of the state. A state could designate an 

agent to provide certain limited administrative services, or 

could choose to vest an agent with greater authority. Where an 

agent issues an ERC on behalf of the state, such issuance would 

have the same legal effect as issuance of an ERC by the state. 
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regulator reviews the application to determine whether, in this 

example, an EE/RE program or project meets eligibility 

requirements for the issuance of ERCs.1313 An eligibility 

application must include a description of the program or 

project, a projection of the MWh generation or energy savings 

anticipated over the life of the program or project, and an EM&V 

plan that meets state requirements. The EM&V plan must describe 

how MWh of RE generation or energy savings resulting from the 

program or project will be quantified and verified.1314 A state, 

in its emission standard regulations, must include requirements 

for EM&V plans that are consistent with the requirements in the 

emission guidelines for EE/RE measures and other eligible 

measures, as discussed in section VIII.G.1 above, and section 

VIII.C.4 below. 

 

1313 The entity implementing the EE/RE program or project 

(referred to in the preamble as a “provider”) would submit the 

application. This is the identified entity to which ERCs would 

ultimately be issued, to a tracking system account held by the 

entity. Such entities could include a wide variety of parties 

that implement EE/RE programs and projects, including owners or 

operators of affected EGUs, electric distribution companies, 

independent power producers, energy service companies, 

administrators of state EE programs, and administrators of 

stateindustrial EE programs, among others. 

1314 The verification process includes confirmation that 

quantified MWh are non-duplicative and permanent (i.e., are not 

being used in any other state plan to demonstrate compliance 

with an emission standard or achievement of a state CO2 goal). 
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 The EPA has determined that state requirements for an 

eligibility application must include review of the application 

by an accredited independent verifier prior to submittal. This 

requirement builds on the approach used for assessing GHG offset 

projects, both in international emission trading programs and 

the GHG emission budget trading programs implemented by 

California and the RGGI participating states.1315 An assessment by 

an accredited independent verifier would be included as a 

component of an eligibility application. 

 The EPA has determined that independent verification 

requirements are necessary to ensure the integrity of state 

rate-based emission trading programs included in a state plan, 

given the wide range of eligible measures that may generate ERCs 

and the broad geographic locations in which those measures may 

occur. Inclusion of an independent verification component 

provides technical support for state regulatory bodies to ensure 

that eligibility applications and monitoring and verification 

reports are thoroughly reviewed prior to issuance of ERCs. 

 

1315 Information about the verification process for GHG offsets 

under the RGGI program, including verifier accreditation 

requirements and access to relevant documents, is available at 

http://www.rggi.org/market/offsets/verification. Similar 

information about the verification process for GHG offsets under 

the California program is available at 

http://www.arb.ca.gov/cc/capandtrade/offsets/verification/verifi

cation.htm. 
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 Rate-based emission trading programs used in a state plan 

must include requirements for independent verifiers that specify 

necessary qualifications and codes of conduct when providing 

verification services. State requirements must include 

accreditation requirements for independent verifiers that 

specify that only accredited verifiers may provide verification 

services and detail the requirements for accreditation and 

maintenance of accreditation status.1316 

 These requirements must ensure that verifiers have 

sufficient knowledge of the rate-based emission trading program 

rules, technical expertise, and knowledge of auditing, 

accounting, and information management practices. Accredited 

verifiers must be independent. Accredited verifiers may not 

provide verification services for any ERC provider for which 

they have a financial, management, or other interest.1317 Such 

 

1316 In this subsection, the term “verifier” is used 

interchangeably to refer to both a “verification body” (i.e., a 

verification company or organization) and a “verifier,” which is 

an individual that is a principal or employee of a verification 

body. 

1317 Accredited verification bodies and individual verifiers may 

not have any direct or indirect organizational or personal 

relationships with an ERC provider that would impact their 

impartiality in assessing the validity and accuracy of the 

information in an eligibility application or M&V report. In 

addition to this general requirement, the following specific 

requirements also apply. Accredited verifiers must have no 

direct or indirect financial interest in, or other financial 
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relationships constitute a conflict of interest (COI). COI 

situations may also arise as a result of personal relationships 

among individuals representing an ERC provider and an accredited 

verifier. State requirements must specify that a verification 

report will not be accepted as part of an eligibility 

application or M&V report where the accredited verification body 

or any individual verifier has a COI. Accredited verification 

bodies must have management protocols in place to identify and 

remedy any COI prior to provision of verification services. 

State requirements should specify that failure of an accredited 

verifier to identify and adequately address any COI prior to 

provision of verification services is grounds for revocation of 

 

relationships with, an ERC provider or any related program or 

project that seeks issuance of ERCs. Accredited verifiers must 

have no relationship with the implementer of a program or 

project that seeks the issuance of ERCs, or any related ERC 

provider, that would represent a COI. Accredited verifiers must 

have no role in the development and implementation of a program 

or project that seeks issuance of ERCs, beyond the provision of 

verification services. Accredited verifiers must not be 

compensated, directly or indirectly, in relation to the 

quantified and verified MWh in an M&V report or on the basis of 

program or project approval, ERC issuance, or the number of ERCs 

issued. Accredited verifiers may not hold ERCs, or other 

financial derivatives related to ERCs, or have a financial 

relationship with other parties that hold ERCs or other related 

financial derivatives. Verification reports must include an 

attestation by the accredited verifier that it assessed 

potential COI related to an ERC provider and adequately 

addressed any identified COI. 
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accreditation. State accreditation requirements should include 

periodic performance reviews by the administering state 

regulatory body of accredited verifiers, to ensure that 

verifiers are maintaining necessary technical and professional 

qualifications and are meeting program requirements for 

provision of verification services. State accreditation 

requirements may recognize in part accreditation by an outside 

organization other than the state, where such outside 

accreditation demonstrates that certain state requirements are 

met.1318 

The state’s eligibility requirements and application procedures 

must ensure that only eligible actions may generate ERCs and 

that documentation is submitted only once for each program or 

project, and to only one state program.1319 These provisions will 

ensure that actions that are eligible for the issuance of ERCs 

are “non-duplicative.”1320 The tracking system used to administer 

a state’s rate-based emission trading system must provide 

 

1318 An example is ANSI accreditation under ISO 14065:2013 for GHG 

validation and verification bodies. More information is 

available at 

https://www.ansica.org/wwwversion2/outside/GHGgeneral.asp?menuID

=200. 

1319 This includes ensuring that multiple parties do not submit an 

eligibility application for the same EE program or project, or 

for the same RE generator. 

1320 Emission standards must be “non-duplicative” as described in 

section VIII.D.2. 
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transparent, electronic, public access to information about 

program and project eligibility applications, including EM&V 

plans, and regulatory approval status. 

 In the second step of the process, following implementation 

of the RE/EE program or project, in this example, that was 

approved in step one, the RE/EE provider periodically submits a 

monitoring and verification (M&V) report to the state regulatory 

body documenting the results of the program or project in MWh of 

electric generation or energy savings.1321 These results are 

quantified according to the EM&V plan that was approved as part 

of step one. These results are verified by an accredited 

independent verifier, and its verification assessment must be 

included as part of the M&V report submitted to the state 

regulatory body. The administering state regulator (or its 

agent) then reviews the M&V report, and determines the number of 

ERCs (if any) that should be issued, based on the report. 

Finally, the state regulatory body (or its agent) issues ERCs to 

the provider of the approved program or project. These ERCs are 

issued to the tracking system account held by the program or 

project provider. 

 

1321 State rate-based emission trading program regulations should 

specify the frequency for submission of monitoring and 

verification reports for approved qualified measures that have 

been deemed eligible to generate ERCs. 
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 State requirements must ensure that only one ERC is issued 

for each verified MWh. This is addressed through registration in 

the tracking system of programs and projects that have been 

qualified for the issuance of ERCs, to ensure that documentation 

is submitted only once for each RE/EE action, and to only one 

state program.1322 The tracking system must provide transparent 

electronic public access to submitted M&V reports and regulatory 

approvals related to such reports.1323 Such reports are the basis 

for issuance of ERCs. 

c. Tracking system requirements. State requirements must include 

provisions to ensure that ERCs issued to any eligible entity are 

properly tracked from issuance to submission by affected EGUs 

for compliance (where ERCs are “surrendered” by the owner or 

operator of an affected EGU and “retired” or “cancelled” by the 

administering state regulatory body), to ensure they are only 

used once to meet a regulatory obligation. This is addressed 

through specified requirements for tracking system account 

holders, ERC issuance, ERC transfers among accounts, compliance 

 

1322 EE/RE programs and projects, and other eligible measures, 

with an approved eligibility application would be designated in 

a tracking system as qualified programs or projects. Qualified 

programs and projects may be issued ERCs, based on approved M&V 

reports. 

1323 This must include electronic Internet access to such 

information in the tracking system. 
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true-up for affected EGUs,1324 and an accompanying tracking system 

infrastructure design based on business rules specified in the 

emission trading program regulations. Each issued ERC must have 

a unique identifier (e.g., serial number) and the tracking 

system must provide for traceability of issued ERCs back to the 

program or project for which they were issued. 

The EPA received a number of comments from states and 

stakeholders about the value of the EPA’s support in developing 

and/or administering tracking systems to support state 

administration of rate-based emission trading systems. This 

could include regional systems and/or a national system. The EPA 

is exploring options for providing such support and is 

conducting an initial scoping assessment of tracking system 

support needs and functionality. 

d. Effect of improperly issued ERCs: Because the goal of this 

rulemaking is the actual reduction of CO2 emissions, it is 

fundamental that ERCs represent the MWh of energy generation or 

savings they purport to represent. To this end, only valid ERCs 

that actually meet the standards articulated in this rule may be 

used to satisfy any aspect of compliance by an affected EGU with 

 

1324 “Compliance true-up” refers to ERC submission by an owner or 

operator of an affected EGU to adjust a reported CO2 emission 

rate, and determination of whether the adjusted rate is equal to 

or lower than the applicable rate-based emission limitstandard. 
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emission standards. Despite safeguards included in the structure 

of ERC issuance and tracking systems, such as the review of 

eligibility applications and M&V reports, and state issuance of 

ERCs, ERCs may be issued that do not, in fact, represent 

eligible zero-emission MWh as required in the emission 

guidelines. A variety of situations may result in such improper 

ERC issuance, ranging from simple paperwork errors to outright 

fraud. 

It is thus essential that the ultimate responsibility for 

the validity of the ERC rest with the entity that must achieve 

compliance with an emission standard. An approvable state plan 

that allows affected EGUs to comply with their emission 

standards in part through reliance on ERCs must include 

provisions making clear that an affected EGU may only use 

properly issued, valid ERCs to demonstrate compliance with its 

emission standard. An EGU that submits for compliance with its 

emission standard an ERC that does not actually represent an 

eligible MWh of zero-emission generation is subject to CAA 

liability for failure to meet its emission standard for each day 

of the relevant compliance period, and must submit two properly 

issued, valid replacement ERCs to the state regulatory body 

within a specified period of time, in accordance with the 

emission guidelines. This is true regardless of the good faith 
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of the EGU in purchasing or obtaining the ERC. The state plan 

must also make clear that the EGU is also subject to CAA 

liability for failure to timely submit replacement ERCs. 

e. Considerations for ERC issuance. The EPA notes that stateadministered and state-overseen EE programs, such as those 

administered by state-regulated electric distribution utilities, 

could play a key role in supplying energy savings to a ratebased emission trading system in the form of ERCs. These 

programs have been the primary means for delivering EE programs 

and energy savings at scale, and also allow for a state to 

conduct a portfolio planning process to guide EE program design 

and focus in a manner that best provides multiple benefits to 

electricity ratepayers in a state. Such portfolio planning 

processes typically treat EE as an energy resource comparable to 

electricity generation. 

 The EPA also notes that non–ERC certificates may be issued 

by states and other bodies for MWh of energy generation and 

energy savings that are used to meet other state regulatory 

requirements, such as state RPS and EERS, or by individuals to 

make environmental or other claims in voluntary markets. 

 The EPA defines an ERC in the emission guidelines as a 

tradable compliance instrument that represents a zero-emission 

MWh from a qualifying measure that may be used to adjust the 
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reported CO2 emission rate of an affected EGU subject to a ratebased emission standard in an approved state plan under CAA 

section 111(d). The sole purpose of an ERC is for use by an 

affected EGU in demonstrating compliance with a rate-based 

emission standard in such an approved state plan. 

 An ERC is issued separately from any other instruments that 

may be issued for a MWh of energy generation or energy savings 

from a qualifying measure. Such other instruments may be issued 

for use in meeting other regulatory requirements (e.g., such as 

state RPS and EERS requirements) or for use in voluntary 

markets. An ERC may be issued based on the same data and 

verification requirements used by existing REC and EEC tracking 

systems for issuance of RECs and EECs. 

4. Evaluation, measurement and verification (EM&V) requirements 

for RE and demand-side EE resources used to adjust a CO2 rate 

This section identifies and discusses the EM&V criteria 

used to quantify MWh savings from demand-side EE and generation 

from zero-emitting RE.1325 These criteria apply in the context of 

both emission standard plans and state measures plans, as 

described below. The EPA is finalizing these criteria as 

 

1325 EM&V is defined to mean the set of procedures, methods, and 

analytic approaches used to quantify the MWh from demand-side EE 

and RE, and thereby ensure that the resulting savings and 

generation are quantifiable and verifiable. 
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applicable requirements in the context of state plans that 

employ a rate-based emission trading program. These criteria are 

described below. State plans must require that MWh savings from 

demand-side EE and generation from zero-emitting RE are 

quantified per these criteria.1326 

Additionally, with respect to these criteria, the EPA 

describes certain established standard industry practices that 

would be presumptively approvable as an approach to include 

these criteria in state plans. States must submit these criteria 

as specified, or alternatively, states may submit the standard 

industry practices described as presumptively approvable. States 

may also submit other means of meeting the criteria so long as 

the state satisfactorily demonstrates in the state plan 

submittal that such alternative means of addressing criteria are 

as adequately stringent as the presumptively approvable approach 

described here. 

As discussed in VIII.G.3., quantified and verified MWh of 

 

1326 For a rate based emission standards plan type, the 

requirement to quantify the MWh from demand-side EE and RE per 

the EM&V criteria must be included in the federally enforceable 

state plan. For a state measures plan implementing rate based 

state measures, applicable state laws must reflect the 

requirement to quantify the MWh from demand-side EE and RE per 

the EM&V criteria, and such state only requirements must be 

adequately described in the supporting documentation submitted 

with the state plan. 
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RE generation, and quantified and verified MWh avoided from 

implementing demand-side EE measures,1327 may be used to adjust a 

CO2 emission rate when demonstrating compliance with the emission 

guidelines. In states implementing emission standard type plans 

with rate-based trading, affected EGUs adjust their reported 

emission rate using ERCs, which represent MWh that are 

quantified and verified according to the EM&V criteria included 

in this section. Providers of EE and RE who seek to earn ERCs 

must develop EM&V plans outlining how they will quantify and 

verify the results of their efforts. These providers are then 

required to submit EM&V plans as part of their application to 

the state regulatory body for project approval.1328 

In states implementing state measures type plans, 

quantified and verified MWh of RE and EE may be used to adjust 

an emission rate through two pathways. First, if the state 

measures plan enables rate-based trading, the affected EGUs may 

use ERCs to adjust their reported rate (per the rate-based 

 

1327 In the context of demand-side EE, “measure” refers to an 

installed piece of equipment or system at an end-use energy 

consumer facility, a strategy intended to affect consumer energy 

use behaviors, or a modification of equipment, systems or 

operations that reduces the amount of energy that would 

otherwise have been used to deliver an equivalent or improved 

level of end-use service. 

1328 A full discussion of applicable requirements for the 

establishment and functioning of rate-based emissions trading 

systems is provided above, at section VIII.G.3. 
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emission standard approach). Alternatively, if the state 

measures plan elects to incorporate RE and demand-side EE 

outside of an ERC trading program – for example through adoption 

and implementation of an EERS or RPS – the state itself, rather 

than the project provider, uses the quantified and verified MWh 

of RE and EE to adjust the rate. 

If a state elects to implement a rate-based ERC trading 

program as part of its state measures approach, state 

regulations and project provider requirements must be identical 

to those outlined for emission standard plans. For a state 

measures plan, the ERC issuance and EM&V requirements must be 

adequately described in the submittal’s supporting materials to 

enable the EPA to determine whether the state measures plan 

satisfactorily demonstrates the ability of the affected EGUs to 

meet the applicable CO2 emission performance rate or state goal. 

For an emission standards plan, the ERC issuance and EM&V 

requirements would be submitted as a component for approval as 

part of the federally enforceable state plan. However, if the 

state elects to incorporate demand-side EE and RE policies, 

programs, and projects outside of an ERC trading program, the 

state itself, rather than the project provider, must demonstrate 

how it will quantify and verify the results of its efforts. In 

this case, the state must describe in its state plan submission 
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how the criteria described herein will be applied to specific 

programs and projects to demonstrate that reported annual MWh 

savings and generation are properly quantified and verified. 

The following discussion presents EM&V criteria for demandside RE and EE measures implemented through both types of state 

plan approaches, followed by a presentation of some additional 

considerations for states implementing RE and EE measures in the 

context of a state measures plan without rate-based trading. 

5. EM&V criteria for RE and demand-side EE resources used to 

adjust a CO2 rate 

The proposed rule stated that the EPA would establish EM&V 

criteria to help states, sources, and RE and EE providers 

quantify and verify MWh savings and generation resulting from RE 

and demand-side EE efforts. The proposal and associated “State 

Plans Considerations” TSD1329 suggested that the EPA’s EM&V 

criteria would leverage the industry-standard practices, 

protocols, and data-sets currently utilized by the majority of 

states currently implementing demand-side EE and RE programs. 

The EPA further noted that many state regulatory bodies and 

other entities already have significant EM&V infrastructure in 

 

1329 See discussion beginning on p. 34 of the State Plan 

Considerations TSD for the Clean Power Plan Proposed Rule: 

http://www2.epa.gov/carbon-pollution-standards/clean-power-planproposed-rule-state-plan-considerations. 
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place and have been applying, refining and enhancing their 

evaluation and associated quality assurance approaches for over 

30 years. The EPA took comment on whether this infrastructure is 

appropriate to use as the basis for establishing minimum EM&V 

criteria for use in rate-based state plans that include RE and 

demand-side EE. The majority of commenters addressing this 

question indicated that existing EM&V infrastructure is 

appropriate to assure quality, credibility, and integrity. Thus, 

the final EM&V criteria reflected herein are intended to be 

consistent with and leverage prevailing industry-standard 

evaluation practices. 

In addition, the EPA’s final criteria reflect several 

overarching objectives and principles offered by states, private 

organizations, and the public during the comment period. One of 

these is the importance of striking a reasonable balance between 

EM&V rigor and credibility on the one hand, and the costs 

associated with performance evaluation on the other. Another 

objective for the EPA’s criteria is to avoid excessive 

interference with EM&V practices that are already robust, 

transparent and working well. Therefore, the minimum criteria 

for EM&V in an approvable state plan establish a floor for EM&V 

practices to ensure credibility and certainty in savings 

estimates across jurisdictions. 
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a. Submittals. Applicable submittals include EM&V plans and EM&V 

reports. At the front end of a program or project, EM&V plans 

are required to document how applicable criteria will be 

addressed as EM&V is performed over the program or project 

period. After implementation has occurred, EM&V reports are 

required to document and describe how each of the criteria was 

applied on an ex-post basis. These reports also specify the 

resulting MWh savings or generation values per RE and EE program 

and project category. 

For demand-side EE, EM&V plans and reports for purposes of 

this final rule are intended to leverage and closely resemble 

EM&V plans that are already in routine use for a wide range of 

publicly or rate-payer funded EE programs and energy service 

company (ESCO) projects. For RE, EM&V plans similarly leverage 

resources and approaches to tracking systems for RE that are 

broadly applied. EM&V reports for RE are simply the existing 

output from these tracking systems. 

For all EM&V submittals addressing demand-side EE, the 

applicable metric is electricity savings, which is defined as a 

reduction in electricity consumption. EE savings must be 

determined and reported in units of MWh. The specific procedures 

and requirements for EM&V submittals in the context of an 

emission standard plan are outlined above in section VIII.G.3. 
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EM&V submittals for state measures plans are described below. 

b. EM&V criteria that apply to all demand-side EE used to adjust 

an emission rate. The following EM&V criteria apply to all 

demand-side EE used to adjust an emission rate. They are 

supplemented by the program and project specific provisions 

identified below. 

(1) Baseline definitions. A critical EM&V issue is the 

assumptions and approach used to determine baseline energy use. 

EM&V plans must describe the baselines to be used with clear 

documentation and discussion of the rationale, applicability, 

and relevant data sources, protocols, and guidance documents 

used for defining the baseline. 

(2) EM&V methods used to quantify the results of EE projects and 

programs. This section establishes criteria for the general 

types of EM&V methods that can EE providers can use to quantify 

savings from demand-side EE programs and projects that are used 

to generate ERCs. Consistent with EM&V practices at the state 

level, where PUCs typically allow utilities and other program 

administrators to use a range of EM&V methods that reflect 

applicable circumstances and on-the-ground conditions (versus 

mandating which methods must be used in a particular situation), 

the EPA is likewise providing flexibility for RE and EE 

providers to select from the following broad categories of EM&V 
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methods to determine savings. 

Two broad categories of EM&V methods are non-control group 

approaches such as project-based measurement and verification 

(M&V),1330 and control group approaches1331 such as randomized 

control trials (RCT). Regardless of the approach selected, a key 

criterion, supported by commenters and consistent with industrystandard practices, is that annual savings values must be 

determined on a regular basis – at intervals sufficient to 

credibly document annual savings – by application of one or more 

of the above-listed EM&V methods. Factors that should be taken 

into consideration when determining the appropriate interval 

include the characteristics of subject EE programs, projects, or 

measures; variability of the savings; the EM&V method used; and 

the relative scale and magnitude of savings. The EPA expects 

that EM&V using the above methods will occur at a minimum of 

four year intervals for building energy codes and product 

standards; every one, two or three years for different publicly 

or rate-payer funded EE programs; and annually for large 

 

1330 M&V is the process of using measurements to reliably 

determine energy and/or demand savings created within an 

individual facility. The International Performance Measurement 

and Verification Protocol (IPMVP) defines four M&V options used 

in the efficiency industry: two end-use metering approaches, 

energy use data (billing data) regression analysis, and 

calibrated computer simulation. 

1331 Also referred to as large-scale consumption data analysis. 
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individual commercial and industrial projects. For all demandside EE used to adjust an emissions rate, the selected method, 

associated assumptions, and data sources must be identified and 

described in EM&V plans. 

For control group methods, the key EM&V criteria is to 

follow industry standard protocols and guidelines such as those 

published by the SEE Action Network and the U.S. DOE’s Uniform 

Methods Protocols (UMP) project. Where feasible, the EPA seeks 

to encourage the use of RCT approaches to establishing control 

groups, as they involve random selection of comparison groups 

and are therefore less prone to selection bias. 

For M&V methods, the key criteria is that industry-standard 

protocols and guidelines are followed. These include the IPMVP, 

protocols published by the Federal Energy Management Program 

(FEMP), the American Society of Heating, Refrigeration and AirConditioning Engineers (ASHRAE), and the U.S. DOE’s UMP. 

(3) Key considerations for quantifying savings. Regardless of 

the approach used to quantify and verify MWh savings, EM&V plans 

must describe how they will address the following key 

considerations for quantifying savings: 

 How major changes in independent variable conditions 

(weather, occupancy, production rates, etc.) that affect 

energy consumption and savings estimates will be 
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analyzed. The effects of these changes can be calculated 

using either real-time conditions or normalized 

conditions that are reasonably expected to occur 

throughout the lifetime of the EE project or measure. 

 How the initial installation of EE will be verified for 

EE program categories that involve the installation of 

identifiable measures (e.g., most publicly or rate-payer 

funded EE programs and project-based EE evaluated siteby-site and CHP, but not programs that provide customers 

with information). A key criterion is that 

verification1332 is required within the first year of 

program implementation. All verification activities must 

be performed using industry-standard techniques (e.g., 

phone or mail surveys, document review, site inspections, 

spot or shot-term metering). For projects implemented as 

part of a program, verification can be performed using a 

sample of projects to represent the full program 

population. In these cases, sample sizes should be 

defined per the rigor criteria described herein. 

 

1332 Verification is an independent assessment to ensure that the 

EE measures have been installed correctly and have the potential 

to generate the predicted savings. Verification may also include 

assessment of baseline conditions and confirmation that the EE 

measures are operating correctly per their design intent. 
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 How avoided T&D systems losses will be included in EE 

savings values. Demand-side EE programs (other than T&D 

efficiency measures such as CVR and volt/VAR 

optimization1333) may adjust reported savings by using a 

T&D adder that is based on the lesser of 6 percent1334 of 

the site-level savings or the calculated statewide annual 

average T&D loss rate [estimated losses in MWh/(total 

electric supply – direct electricity use)]1335 expressed 

as a percentage and based on values in the most recent 

year and published US EIA State Electricity Profile. 

Since T&D efficiency measures such as CVR and volt/VAR 

may reduce both end-use consumption and line losses, MWh 

savings from T&D measures must be calculated on the basis 

of procedures identified in an EM&V plan. 

 How the duration of EE program or project electricity 

savings will be determined using annual verification 

 

1333 More information about these technologies is in section 

VIII.F.1 above. 

1334 6 percent is the national average losses from 1990-2012 (See: 

http://www.eia.gov/tools/faqs/faq.cfm?id=105&t=3). 

1335 Estimated losses in MWh, total electric supply, and direct 

electricity use values are available in the U.S. EIA’s State 

Electricity Profiles. See table on Supply and Disposition of 

Electricity (currently Table 10). Direct electricity use refers 

to the electricity generated at facilities that is not put onto 

the electricity grid, and therefore does not contribute to T&D 

losses.
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assessments, industry-standard persistence studies, 

deemed estimates of effective useful life (EUL), or a 

combination of all three. If deemed EUL estimates are 

used for determining the duration of savings, then zero 

savings must be assumed at the end of a program, project, 

or measure life. If project or program persistence 

studies are conducted at least every 5 years to determine 

the duration of savings, then savings can be counted as 

long as the verification activities indicate continued 

measure operation and performance. 

 How the rigor1336 of quantifying MWh savings values will 

be assessed, and the methods used to control the types of 

bias or error relevant inherent to the applied EM&V 

techniques. Rigor can be quantified using statistical 

indicators such as confidence and precision (for annual 

MWh savings, or for a representative sample of an EE 

program population), together with a written discussion 

of the EM&V approaches used, potential risks and biases, 

and related quality control measures that will be 

 

1336 Rigor refers to the level of effort expended to minimize 

uncertainty from factors such as sampling error and bias. The 

higher the level of rigor, the more confident one is that the 

results of the EM&V activities are both accurate and precise. 
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utilized. Sampling of populations is appropriate, 

provided that (a) the population estimates derived from 

sampling achieve industry-standard levels of precision 

and confidence (actual, not ex-ante values), and (b) 

applicable protocols and guidance documents are applied 

and cited. 

 How double counting will be avoided through the use of 

tracking and accounting procedures to ensure that two or 

more programs do not separately claim savings from the 

same EE project or measure (for example, two EGUs 

claiming savings from the same lighting retrofit). Other 

types of double counting must likewise be considered and 

avoided. 

(4) Use of EE EM&V protocols. A separate aspect of industrystandard EM&V practice addressed in the rule proposal is the use 

of one or more EM&V protocols, guidelines, and guidance. These 

resources serve to document the EM&V approaches listed above and 

provide instruction on their application in the field. In public 

comments, the EPA heard overwhelmingly that such protocols, 

guidelines, and guidance documents are currently in wide use, 

and that this use should be continued and encouraged in the 

context of state plans. The agency agrees with this observation 

and therefore supports their application in the context of 
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demand-side EE used to adjust an emission rate. The primary 

criteria are that EM&V plans must include a clear description 

and documentation of how the relevant protocols, guidelines, and 

guidance documents will be applied, as well as after-the-fact 

documentation in EM&V reports of how they were actually applied. 

c. Eligible demand-side EE programs and projects. During the 

comment period, the EPA received many requests from commenters 

for explicit consideration of the broad range of demand-side EE 

programs and projects that are currently being implemented by 

states and other entities across the country. Specifically, 

these commenters expressed interest in counting the resulting 

quantified and verified MWh savings towards the achievement of 

CO2 emission rate goals. Consistent with these perspectives, the 

EPA position is that any demand-side EE program and project that 

results in MWh savings is potentially eligible, provided that it 

meets the criteria for eligibility described in section 

VIII.G.1., and that supporting EM&V is rigorous, complete and 

consistent with the criteria provided in the emission guidelines 

and the state plan. 

Common demand-side EE programs and project types include: 

 Publicly or rate-payer funded customer-funded demand-side 

management programs 

 Project-based EE evaluated site-by-site, for example 
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those implemented by ESCOs at commercial buildings and 

industrial facilities 

 State and local government building energy code and 

compliance programs 

 State and local government incremental product energy 

standards 

A related technology that is eligible to generate MWh that 

can be counted towards a rate-based goal is CHP (more 

information about the eligibility and EM&V criteria for CHP is 

provided in section VIII.G.1.). 

The EPA recognizes that the programs and policies listed 

above will evolve and change over the rule period, as new 

technologies emerge and efficiency improves. The agency also 

expects that new EE program types will emerge and expand 

throughout the rule period, and that MWh savings resulting from 

these programs can similarly be considered if quantified and 

verified according to EM&V criteria specified in industrystandard protocols and guidance documents, and if documentation 

provided in EM&V plans and reports is transparent, credible and 

robust. 

d. Demand-side EE program- and project-specific EM&V provisions. 

In addition to the generally-applicable EM&V criteria specified 

above, EM&V plans and report submittals must include any 
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additional EM&V information needed to ensure that savings from 

the previously-listed programs and projects are quantifiable and 

verifiable. This requirement can be fulfilled by documenting in 

EM&V plans how industry-standard protocols, guidelines, and 

guidance documents that are relevant to such programs and 

projects will be applied on a forward-looking basis, and also by 

confirming in ex-post EM&V reports that they were, in fact, 

applied. The protocols, guidelines, and guidance documents that 

identify these provisions may currently exist, or may be 

developed during the course of the rule period as programmatic 

strategies and EM&V evolves. 

e. EM&V criteria that apply to non-affected CHP. To calculate a 

CHP unit’s creditable MWh, the electrical output is prorated 

based on the “incremental CO2 emission rate” of the CHP unit 

relative to the applicable CO2 emission rate for affected EGUs in 

the state, according to the equation described in section 

VIII.C.1. The EM&V criteria described in this section apply only 

to the MWh-output terms of the equation, consistent with the 

definition of EM&V as applied in this rule. The full set of 

accounting criteria for CHP is provided in VIII.G.1. 

For determining the creditable MWh from CHP, the measured 

output must be derived either from (1) a revenue quality meter 

that meets the applicable ANSI C-12 standard or equivalent, 
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which is the typical requirement for settlements with RTO and 

other control-area operators; or (2) for customer-sited CHP that 

is interconnected behind the customer meter, a revenue quality 

meter at the AC output of an inverter, where applicable, that is 

adjusted to reflect the energy delivered into either the 

transmission or distribution grid at the generator bus bar. 

For small systems, defined as individual CHP units with 

nameplate capacities below 10 kW where metered data are 

unavailable, generation output may be determined using either 

self-reporting of generation values1337 or generation-estimating 

software. In the latter case, calculations of system output must 

be based on the CHP unit’s capacity, estimated capacity factors, 

and an assessment of the local conditions that affect generation 

levels. All such input parameters and assumptions must be 

clearly described and documented. Regardless of whether selfreporting or generation-estimating software is used, CHP 

providers can report results without an intermediary provided 

that EM&V plans describe the rigorous quality control and fraud 

prevention measures that will be applied. 

 For small systems, generation output may be determined 

 

1337 Self-reporting means that the generator-owner can read its 

own meter and report MWh generated directly to a tracking 

system, without relying on an independent third party or other 

representative. 
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using either estimating software, algorithms, or self-reporting 

of generation values. In the latter case, EM&V plans must 

confirm that rigorous quality control and fraud prevention 

measures are in place. Small systems are defined as individual 

CHP units with nameplate capacities below 10 kW where metered 

data are unavailable. For CHP systems that directly serve onsite end-use electricity loads, avoided T&D system losses can be 

assessed as is commonly practiced with demand-side EE. Such 

calculations must apply the criteria described in section 

VIII.G.4.(b)(3) above. 

f. EM&V criteria that apply to all RE. This section describes 

the EM&V criteria associated with quantifying electricity 

generation from eligible RE, and for documenting these criteria 

in EM&V plans and reports. Consistent with prevailing views 

expressed in public comments, the EPA’s criteria are based on 

the presumption that the quantification of RE generation can 

leverage the infrastructure and documentation associated with 

participation in registries of renewable energy certifications 

(RECs). These registries typically include well-established 

procedures for registry operations, safeguards, and 

documentation, all of which support compliance demonstration 

with state RPS policies. 

The primary metric for all RE is electricity generation, in 
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units of MWh. Measured output must be derived either from (1) a 

revenue quality meter that meets the applicable ANSI C-12 

standard or equivalent, which is the typical requirement for 

settlements with RTO and other control-area operators; or (2) 

for customer-sited generators that are interconnected behind the 

customer meter, a revenue quality meter at the AC output of an 

inverter, adjusted to reflect the energy delivered into either 

the transmission or distribution grid at the generator bus bar. 

For RE units that are managed by regional transmission 

operators or other control area operators, metered generation 

data should be electronically collected by the control area’s 

energy management system, verified through an energy accounting 

or settlements process, and reported by the control area 

operator to the REC registry at least monthly. 

For RE units that do not go through a control area 

settlements process, metered data should be read and transmitted 

to the REC registry by an independent third party on a monthly 

basis, but at a minimum annually. Such data must be verified for 

reasonableness by the state or the REC registry. 

For small systems, defined as individual RE units with 

nameplate capacities below 10 kW where metered data are 

unavailable, generation output may be determined using either 

self-reporting of generation values or generation-estimating 
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software. In the latter case, calculations of system output must 

be based on the RE unit’s capacity, estimated capacity factors, 

and an assessment of the local conditions that affect generation 

levels. All such input parameters and assumptions must be 

clearly described and documented. In addition, each RE unit must 

be uniquely identified and recorded in a registry to avoid 

double counting. Such data must be verified for reasonableness 

by the state or the REC registry. Regardless of whether selfreporting or generation-estimating software is used, RE 

providers can report the result to the tracking system without 

an intermediary provided that EM&V plans describe the rigorous 

quality control and fraud prevention measures that will be 

applied. 

An additional consideration is that RE generation may be 

aggregated from multiple generators into a single MWh value for 

the group, provided the following criteria are met: each RE unit 

is uniquely identified in a tracking system (to ensure that 

double counting is avoided), the nameplate capacity of each RE 

unit is less than 150 kW, the aggregated RE units collectively 

have nameplate generating capacities less than 1.0 MW, the RE 

units being aggregated utilize the same technology/fuel type, 

and the RE unit’s generation data are based on the same metering 

or the same generation estimating software or algorithms. 
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An additional criterion that applies to distributed RE 

units that directly serve on-site end-use electricity loads is 

that avoided T&D system losses can be considered, as is commonly 

practiced with demand-side EE. Such calculations must apply the 

criteria specified for demand-side EE, as described in section 

VIII.G.4.(b)(3) above. 

g. Additional considerations for EM&V of RE and EE included in 

state measures type plans. As discussed in the introduction to 

this section, states implementing state measures type plans may 

use quantified and verified MWh of EE savings and RE generation 

to adjust an emission rate through two pathways. First, if the 

state measures plan enables rate-based trading, the affected 

EGUs may use ERCs to adjust their reported rate as applicable 

under the rate-based emission standard approach. In such cases, 

a state includes EM&V criteria (consistent with those discussed 

above) in its state plan requirements governing ERC issuance, 

trading and retirement. Second, if the state measures plan 

incorporates RE and demand-side EE policies, programs and 

projects outside of an ERC trading program – e.g., through 

adoption of an EERS or a RPS – the state itself, rather than the 

project provider, applies the quantified and verified MWh to 

adjust the reported emission rate used to demonstrate compliance 

with the emission guidelines. 
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In the case of a state measures plan relying on stand-alone 

RE and EE measures, a state must submit as part of its state 

plan a description of the RE and EE measures it intends to 

implement, as well as a discussion of how it intends to quantify 

the results of those measures consistent with the EMV criteria 

described herein. A key component of this discussion is the 

mechanisms and approaches the state intends apply to ensure that 

MWh savings and generation are independently and credibly 

quantified and verified. Such mechanisms and approaches must be 

consistent with industry-standard practices and functionally 

equivalent to the provisions for independent verifiers for ERC 

trading in the context of emission standard plans, as described 

section VIII.G.3. An additional and related component of the 

state plan is a forecast of expected RE generation and annual 

incremental and cumulative EE savings. 

For any state measures plan that incorporates demand-side 

EE and RE outside of an ERC trading program, an additional 

criterion is that states must report annual incremental and 

cumulative EE savings and RE generation to the EPA every year.1338

These data should be provided to the EPA in a summary format 

 

1338 Per section VIII.D, states that choose a state measures plan 

must submit an annual report no later than July 1 following the 

end of each calendar year in the interim period. 
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that documents total MWh savings and generation, and that is 

specified at the level of major policies, programs and projects. 

At state plan check-in intervals with the EPA (in 2025, 

2028 and 2030), states must provide the EPA with access to 

applicable program- and project-level EM&V reports used to 

compile total MWh savings and generation. EM&V reports must 

document how EM&V criteria were applied to quantify results. 

It should be noted that, in the case of state measures 

plans that utilize a mass-based allowance trading program to 

meet their goal, EM&V plans and reports are not required. This 

is true even if the state is actively implementing RE and 

demand-side EE programs and projects. This is because the 

emission effects of RE and EE are accounted for in measured 

stack emissions. 

h. Skill certification standards. Several commenters pointed out 

that skill certification standards can help to assure quality 

and credibility of demand-side EE and RE projects. The EPA 

agrees that in conjunction with other EM&V measures discussed in 

this section, requiring that workers be certified by either a 

party aligned with the Department of Energy’s (DOE) Better 

Building Workforce Guidelines and validated by a third party 

accrediting body recognized by DOE, or by an apprenticeship 

program that is registered with the federal Department of Labor 
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(DOL), Office of Apprenticeship or a state apprenticeship 

program approved by the DOL, or by another skill certification 

validated by a third party accrediting body can help to 

substantiate the authenticity of emission reductions due to 

demand-side EE and RE. The EPA encourages states to ask for a 

demonstration that the work is performed by a proficient 

workforce. 

H. Additional Considerations for State Plans 

1. Consideration of a facility’s “remaining useful life” and 

“other factors” 

This section discusses the way in which the final emission 

guidelines address the CAA section 111(d)(1) provision requiring 

the Administrator, in promulgating 111(d) regulations, to 

“permit the State in applying a standard of performance to any 

particular source under a [111(d)] plan . . . to take into 

consideration, among other factors, the remaining useful life of 

the existing source to which such standard applies.” 

The final guidelines permit a state, in developing its 

state plan, to fully consider and take into account the 

remaining useful life of an affected EGU and other factors in 

establishing the requirements that apply to that EGU, as 

discussed further below. Therefore, consideration of facilityspecific factors and in particular, remaining useful life, does 
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not justify a state making further adjustments to the 

performance rates or aggregate emission goal that the guidelines 

define for affected EGUs in a state and that must be achieved by 

the state plan. Thus, these guidelines do not provide for states 

to make additional goal adjustments based on remaining useful 

life and other facility-specific factors because they can fully 

consider these factors in designing their plans. 

a. Statutory and regulatory backdrop. This section describes the 

statutory and existing regulatory background concerning 

facility-specific considerations in implementation of section 

111(d). 

Section 111(d)(1)(A) requires states to submit a plan that 

“establishes standards of performance” for existing sources. 

Under section 111(d)(1)(B), the plan must also “provide for 

implementation and enforcement of such standards of 

performance.” Finally, the last sentence of section 111(d)(1) 

provides: “Regulations of the Administrator under this paragraph 

shall permit the State in applying a standard of performance to 

any particular source under a plan submitted under this 

paragraph to take into consideration, among other factors, the 

remaining useful life of the existing source to which such 

standard applies.” 
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The EPA’s 1975 implementing regulations1339 addressed a 

number of facility-specific factors that might affect 

requirements for an existing source under section 111(d). Those 

regulations provide that for designated pollutants, standards of 

performance in state plans must be as stringent as the EPA’s 

emission guidelines. Deviation from the standard might be 

appropriate where the state demonstrates with respect to a 

specific facility (or class of facilities): 

(1) Unreasonable cost of control resulting from plant 

age, location, or basic process design; 

(2) Physical impossibility of installing necessary 

control equipment; or 

(3) Other factors specific to the facility (or class 

of facilities) that make application of a less stringent 

standard or final compliance time significantly more 

reasonable. 

This provision was amended in 1995 (60 FR 65387, December 

19, 1995), and is now prefaced with the language “Unless 

otherwise specified in the applicable subpart on a case-bycase basis for particular designated facilities or classes 

of facilities.” 40 CFR 60.24(f). 

b. Our proposal regarding the implementing regulations. Our 

proposal stated that the reference to “[u]nreasonable cost 

of control resulting from plant age” in 60.24(f) 

 

1339 40 FR 53340 (Nov. 17, 1975). 
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“implements” the statutory provision on remaining useful 

life. We also stated that the implementing regulations 

“provide the EPA’s default structure for implementing the 

remaining useful life provision of CAA section 111(d).” We 

noted that the prefatory language “unless otherwise 

specified in the applicable subpart” gives the EPA 

discretion to alter the extent to which the implementing 

rules applied if appropriate for a particular source 

category and guidelines. We requested comment on our 

analysis of the existing implementing regulations and any 

implications for our regulatory text in respect to how 

these guidelines relate to those regulations. 

 Commenters noted, among other things, that the sentence 

concerning “remaining useful life” was added in the 1977 CAA 

Amendments and that therefore it could not be said that 

provisions from the 1975 implementing regulations “implement” 

the sentence. The EPA does not think as a general matter that it 

is necessarily impossible that a pre-statutory amendment rule 

could continue to serve as a reasonable implementation of a 

post-statutory amendment provision. However, we also think it is 

appropriate, as we suggested in the June 2014 proposal, to 

specify in the applicable subpart for these guidelines that the 

provisions in 60.24(f) should not apply to the class of 
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facilities covered by these guidelines. As a result, regardless 

of whether the implementing regulations appropriately implement 

the “remaining useful life” provision in general, the relevant 

consideration is that, as we now explain, these particular 

guidelines “permit the State in applying a standard of 

performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other 

factors, the remaining useful life of the existing source to 

which such standard applies.” 

c. How these emission guidelines permit states to consider 

remaining useful life and other facility-specific factors. The 

EPA notes that, in general, the implementing regulation 

provisions for remaining useful life and other facility-specific 

factors are relevant for emission guidelines in which the EPA 

specifies a presumptive standard of performance that must be 

fully and directly implemented by each individual existing 

source within a specified source category. Such guidelines are 

similar to a CAA section 111(b) standard in their form. For 

example, the EPA emission guidelines for sulfuric acid plants, 

phosphate fertilizer plants, primary aluminum plants, and Kraft 
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pulp plants specify emission limits for sources.1340 In the case 

of such emission guidelines, some individual sources, by virtue 

of their age or other unique circumstances, may warrant special 

accommodation. 

In these final guidelines for state plans to limit CO2 from 

affected EGUs, however, the agency does not specify presumptive 

performance rates for individual EGUs. Instead, these guidelines 

provide collective performance rates for two classes of affected 

EGUs (steam generating units and stationary combustion 

turbines), and give states the alternative of developing plans 

to achieve a state emission goal for the collective group of all 

affected EGUs in a state. Providing states with the ability to 

consider facility-specific factors such as remaining useful life 

in designing their state plans is one of the fundamental reasons 

that the EPA designed the final rule in this way. In addition, 

the significant revisions since proposal to address 

 

1340 See “Phosphate Fertilizer Plants; Final Guideline Document 

Availability,” 42 Fed. Reg.FR 12022 (Mar. 1, 1977); “Standards 

of Performance for New Stationary Sources; Emission Guideline 

for Sulfuric Acid Mist,” 42 Fed. Reg.FR 55796 (Oct. 18, 1977); 

“Kraft Pulp Mills, Notice of Availability of Final Guideline 

Document,” 44 Fed. Reg.FR 29828 (May 22, 1979); “Primary 

Aluminum Plants; Availability of Final Guideline Document,” 45 

Fed. Reg. 26,294FR 26294 (Apr. 17, 1980); “Standards of 

Performance for New Stationary Sources and Guidelines for 

Control of Existing Sources: Municipal Solid Waste Landfills, 

Final Rule,” 61 Fed. Reg.FR 9905 (Mar. 12, 1996). 

 
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achievability concerns (e.g., moving the start date from 2020 to 

2022, and other changes in interim and final state goals 

summarized in the next section) will help to ensure that states 

in practice can consider remaining useful life and other 

facility-specific factors in setting EGU requirements. Of 

course, EGUs vary considerably in age, so remaining useful life 

is potentially relevant to regulation of some units and not 

others. 

The guidelines capitalize on the inherent flexibility 

offered by aggregate EGU performance rates and by the state 

goals approach, allowing states flexibility on the form of the 

EGU standards that they include in CAA section 111(d) plans. A 

state could select a form of standards (e.g., marketable credits 

or permits, retirement of certain older facilities after their 

useful life, etc.) that avoids or diminishes concerns about 

facility-specific factors such as remaining useful life. Even if 

a state adopted the CO2 emission performance rates for fossil 

fuel-fired electric utility steam generating units and 

stationary combustion turbines, though, the state could take 

remaining useful life into consideration by allowing affected 

EGUs to comply using ERCs. In effect, under a trading program 

with repeating compliance periods, a facility with a short 

remaining useful life has a total outlay that is proportionately 
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smaller than a facility with a long remaining useful life, 

simply because the first facility would need to comply for fewer 

compliance periods and would need proportionately fewer ERCs 

than the second facility. Buying ERCs could avoid excessive upfront capital expenditures that might be unreasonable for a 

facility with a short remaining useful life, and would reduce 

the potential for stranded assets. 

In addition to providing states with flexibility on the 

form of the standards of performance in their plans, the 

guidelines leave to each state the design of the specific 

requirements that fall on each affected EGU in applying those 

standards. To the extent that an emission standard that a state 

may wish to adopt for affected EGUs raises facility-specific 

issues, the state may make adjustments to a particular 

facility’s requirements on facility-specific grounds, so long as 

any such adjustments are reflected (along with any necessary 

compensating emission reductions to meet the state goal) in the 

state’s CAA section 111(d) plan submission. 

Finally, we note that these guidelines permit states to use 

a rate or mass CO2 emission goal, and that each of these pathways 

allow states multiple design choices. Under either pathway 

states can take into consideration remaining useful life and 

seek to avoid stranded assets. 
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d. Why remaining useful life and other facility-specific factors 

do not warrant adjustments in the guidelines’ performance rates 

and state goals. Under the final guidelines, remaining useful 

life and other facility-specific considerations do not provide a 

basis for adjusting the CO2 emission performance rates, or the 

state’s rate-based or mass-based CO2 emission goals, nor do they 

affect the state’s obligation to develop and submit an 

approvable CAA section 111(d) plan that adopts the CO2 emission 

performance rates or achieves the goal by the applicable 

deadline. After considering public comments discussed below and 

in the response to comments document, the EPA has retained this 

aspect of the proposed rule for the reasons described below. 

As noted above, the final guidelines provide aggregate 

emission goals for affected EGUs in each state, in addition to 

the CO2 emission performance rates. The guidelines also reflect a 

number of changes from proposal to address concerns about 

achievability of proposed state goals that were raised in public 

comments, many of which were explicitly prompted by 

consideration of the remaining useful life issue. The result is 

to afford states with broad flexibility to design requirements 

for affected EGUs to achieve the CO2 emission performance rates 

or state CO2 emission goals in ways that avoid requiring major 

capital expenditures, or imposing unreasonable costs, on those 
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affected EGUs that have a limited remaining useful life. State 

plans may use any combination of the emissions reduction methods 

represented by the building blocks, and may also choose to 

employ emission reduction methods that were not assumed in 

calculating state goals. 

To be more specific, the EPA notes that a state is not 

required to achieve the same level of emission reductions with 

respect to any one building block as assumed in the EPA’s BSER 

analysis. A state may use any combination of measures, including 

those not specifically factored into the BSER by the EPA. The 

EPA has estimated reasonable rather than maximum possible 

implementation levels for each building block in order to 

establish overall state goals that are achievable while allowing 

states to take advantage of the flexibility to pursue some 

building blocks more aggressively, and others less aggressively, 

than is reflected in the goal computations, according to each 

state’s needs and preferences. The guidelines provide further 

flexibility by allowing state plans to use emission reduction 

methods not reflected in the BSER. A description of multiple 

emission reduction methods is provided in section VIII.G. 

f. Response to key comments on remaining useful life. In 

response to the proposed rule, some commenters said that 

stringent and binding state goals do not, as a practical matter, 
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provide states with the flexibility on EGU requirements that the 

EPA claimed at proposal, and take away states’ ability to 

consider remaining useful life for individual units. Some said 

the EPA’s presumption at proposal that the issue of remaining 

useful life would arise infrequently is inaccurate because the 

EPA focused on capital investments late in a plant’s useful life 

and did not consider stranded assets from retirement of coalfired generation before the end of its useful life, or from 

retirement of EGUs that recently installed pollution controls. 

Commenters provided multiple examples of individual power 

plants, including relatively new plants, which they asserted 

would be forced to shut down under the proposal. One commenter 

said that the EPA’s Integrated Planning Model outputs for the 

proposal demonstrate that integrated operation of the four 

building blocks would result in retirement of sources before the 

end of their useful life. A number of commenters raised concerns 

that the proposed interim goal would cause plant retirements and 

stranded assets. A number of commenters also asserted that the 

proposal would cause retirement of EGUs that recently invested 

in pollution controls to comply with requirements such as MATS 

or Best Available Retrofit Technology requirements of the 

Regional Haze program. 

The EPA shares the goal of avoiding stranded assets. 
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Although nothing in section 111(d) explicitly bars a guideline 

that results in some facilities becoming uneconomic before the 

end of their useful lives, the EPA nonetheless has striven to 

design the guidelines so as to give states flexibility to 

develop plans that allow power companies to recover their 

investments in generation units. 

In addition, the EPA is addressing the key comments above 

by making changes to state goals and its goal-setting 

methodology. These changes include: 

 Starting the interim goal period in 2022 rather than 

2020, allowing more gradual progress toward the final 

goal 

 Revising the goal-setting formula and the state goals 

themselves 

 Updating analyses of achievable levels of improvement 

through the building blocks that together represent the 

BSER, while keeping them at reasonable, rather than 

maximum, levels

 Providing an explicit phase-in schedule for meeting the 

revised interim goals, while also allowing a state the 

option of choosing its own emission improvement 

trajectory 

The final guidelines also contain changes to avoid certain 
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inconsistencies between the goal-setting methodology and 

accounting of reductions under state plans (e.g., interstate 

effects of RE programs) that could have made state goals less 

achievable for some states. 

Together, these changes help to ensure that the state goals 

established in the final guidelines are achievable considering 

cost, and that states can, as a practical matter, consider the 

toolbox of available emission reduction methods that the final 

guidelines allow and choose the best way to achieve their state 

goals. 

Several commenters said that that the statute does not 

authorize the EPA to require other facilities to achieve greater 

reductions to compensate for a facility that warrants relief 

based on remaining useful life. One said that consideration of 

remaining useful life and other relevant factors is a one-way 

ratchet that provides relief to sources that cannot achieve the 

BSER, and that the EPA turns that approach on its head by 

prohibiting a state from providing such relief to a specific 

facility unless it can identify another facility to “punish” by 

requiring additional emissions reductions to offset that relief. 

The EPA disagrees with these comments, many of which appear 

to be predicated on an approach not taken in this rule: 

requiring states to set presumptive standards for individual 
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affected EGUs. The EPA is not establishing BSER for individual 

facilities, and then requiring better-than-BSER from some 

facilities to make up to worse-than-BSER performance that a 

state authorizes for other facilities because of a short 

remaining useful life. Rather, as previously noted, the 

guidelines set aggregate performance rates and state goals that 

represent the aggregate emission level of affected EGUs in each 

state based on estimates of the aggregate impact of applying the 

BSER. In estimating the amount of improvement achievable through 

each building block e.g., improvement in heat rate or amount of 

generation shift to lower-emitting EGUs), the EPA relies on 

estimating the average achievable level rather than attempting 

to estimate the level achievable by each and every affected EGU. 

Thus, the fact that an individual facility may be unable, for 

example, to achieve the average level of heat rate improvement 

assumed in goal-setting is consistent with the EPA’s analysis, 

and does not undermine the EPA’s determination of state goals. 

An additional reason that the EPA believes that 

consideration of remaining useful life and other facilityspecific factors does not warrant adjustments to state goals is 

that the design of the guidelines does not mandate that states 

impose requirements that would call for substantial capital 

investments at affected EGUs late in their useful life. Of the 
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building blocks considered by the EPA in developing state goals, 

only the first block, heat rate improvements, involves capital 

investments at the affected EGUs. The other building blocks – 

generation shifts among affected EGUs, and addition of new RE 

generating capacity – do not generally involve capital 

investments by the owner/operator at an affected EGU. 

In the case of heat rate improvements at affected EGUs, 

states can choose whether to require a greater or lesser degree 

of heat rate improvement than the percentage improvement assumed 

in the EPA’s BSER determination, either because of the remaining 

useful life of one or more EGUs, other source-specific factors 

that the state deemed appropriate to consider, or any other 

relevant reasons. The agency also notes that any capital 

expenditures would be much smaller than capital expenditures 

required for example, for purchase and installation of scrubbers 

to remove sulfur dioxide; a fleet-wide average cost for heat 

rate improvements based primarily on best practices at coalfired generating units would not likely exceed $100/kW, compared 

with a typical SO2 wet scrubber cost of $500/kw (costs vary with 

unit size).1341 In addition, the proposed guidelines allow states 

 

1341 Heat rate improvement methods and related capital costs are 

discussed in the GHG Abatement Measures TSD; SO2 scrubber capital 

costs are from the documentation for the EPA’s IPM Base Case 
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to regulate affected EGUs through flexible regulatory approaches 

that do not require affected EGUs to incur large capital costs 

(e.g., averaging and trading programs). Under the EPA’s proposed

approach - establishing state goals and providing states with 

flexibility in plan design – states have flexibility to make 

exactly the kind of judgments necessary to avoid requiring 

capital investments that would result in stranded assets. 

Remaining useful life and other factors, because of their 

facility-specific nature, are potentially relevant as states 

determine requirements that are directly applicable to affected 

EGUs. If relief is due a particular facility, the state has an 

available toolbox of emission reduction methods that it can use 

to develop a section 111(d) plan that will achieve the CO2

emission performance rates or state CO2 emission goals on time. 

The EPA therefore concludes that the remaining useful life of 

affected EGUs, and the other facility-specific factors 

identified in the existing implementing regulations, should not 

be regarded as a basis for adjusting the CO2 emission performance 

rates or a state CO2 emission goal, and should not relieve a 

state of its obligation to develop and submit an approvable plan 

 

v5.13, Chapter 5, Table 5-3, available at 

http://www.epa.gov/airmarkets/documents/ipm/Chapter_5.pdf. 
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that achieves that goal on time. 

g. Legal issues regarding remaining useful life. Section 

111(d)(1) requires the EPA in promulgating section 111(d) 

regulations to “permit the State in applying a standard of 

performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other 

factors, the remaining useful life of the existing source to 

which such standard applies.” Here, we discuss the legal basis 

for determining that the emission guidelines are consistent with 

this statutory requirement. 

First, the phrase “remaining useful life” also appears in 

the visibility provisions of section 169A. There, in determining 

best available retrofit technology (BART), the state (or the 

EPA) must take into consideration (among other factors) “the 

remaining useful life of the source.” 42 USC 7491(g)(2); see 

also id. (g)(1) (reasonable progress). In the context of the 

visibility program, we have interpreted this provision to mean 

that the remaining useful life should be considered when 

calculating the annualized costs of retrofit controls. See 40 

CFR Pt. 51, App. Y, IV.D.4.k.1. This annualized cost is then 

used to determine a cost effectiveness, in dollars per ton of 

pollutant removed on an annual basis. As a result, a technology 

with a large initial capital cost that might have a reasonable 
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cost-effectiveness for a facility with a long remaining useful 

life would have a much higher and possibly unreasonable costeffectiveness for a facility with a short remaining useful life. 

 However, section 111(d)(1) is different than section 

169A(g)(2) and need not be interpreted in the same way. The 

requirement in section 169A(g)(2) is a mandatory duty to 

consider remaining useful life in determining BART. Section 

111(d)(1), in contrast, merely requires that EPA emission 

guidelines permit states to take into account remaining useful 

life (among other factors), and section 111(d)(1) does not 

specify how the EPA must permit that. Furthermore, section 

111(d)(1) does not suggest that states must be given carte 

blanche to consider remaining useful life in any way that can be 

imagined. Thus, there is a gap in the statute (just as there is 

in section 169A(g)(2)) for the EPA to fill by determining how 

states might consider remaining useful life. As detailed in 

section VIII.B.6, these guidelines permit states to take into 

account remaining useful life in a number of reasonable ways and 

thus the guidelines satisfy the statutory obligation. 

 Even if the EPA were to consider the provision in section 

111(d)(1) in the same light as section 169A(g)(2), we would note 

(as discussed in detail in VIII.B.6 above) that (for example) a 

trading program under these section 111(d) guidelines only 
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requires compliance on a periodic basis and does not require any 

initial capital expenditures. Thus, over the life of the 

facility, a facility with a short remaining useful life will 

need fewer total credits or allowances than an otherwise 

comparable facility with a long remaining useful life, but the 

annualized cost to the two facilities is the same. In other 

words, under a trading program remaining useful life of a source 

is automatically accounted for in the way it is accounted for 

under the visibility program. 

 Some commenters stated that the EPA’s interpretation of 

remaining useful life is impermissible. These commenters claimed 

that states, if they wish to take into account remaining useful 

life at one affected EGU, must relax the stringency of the 

emission standard for that EGU. Then, the state would be 

compelled to increase the stringency of emission standards at 

other affected EGUs in order to achieve the state performance 

goal. According to these commenters, section 111(d) does not 

allow this outcome. 

 First, the commenters are mistaken in their premise. As 

discussed in section VIII.B.6 and in the example immediately 

above, states can impose the exact same emission standards on 

two affected EGUs and still take into account remaining useful 

life through the availability of trading. In other words, states 
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need not relax an emission standard here and strengthen an 

emission standard there in order to take into account remaining 

useful life. Thus, these guidelines permit states to take into 

account remaining useful life without any of the effects 

commenters are concerned about. 

 Second, even if states decide to relax emission standards 

at one EGU, on the basis of remaining useful life or any other 

factor, nothing in the last sentence of section 111(d)(1) 

prohibits these guidelines from requiring the state plan to 

still meet the state performance goal. In fact, that sentence is 

completely silent on the issue. Thus, there is a gap in the 

statute to fill not only with respect to the ways in which 

remaining useful life can be considered, but the concomitant 

effects if a state chooses to consider remaining useful life in 

a particular way. In this case the concomitant effect of a state 

relaxing one emission standard may be that the state must make 

up for it elsewhere in order to meet the goal, but nothing in 

section 111(d)(1), including the statutory requirement to permit 

consideration of remaining useful life, prohibits that outcome. 

2. Electric reliability

The final rule features overall flexibility, a long 

planning and implementation horizon, and the widest possible 

range of options for states and affected EGUs to achieve the CO2
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emissions goal. This design reflects, among other things, the 

EPA’s commitment to ensuring that the final rule does not 

interfere with the reliability of the nation’s electricity 

supply. Comments from state, regional and federal reliability 

entities, power companies and others, as well as consultation 

with the Federal Energy Regulatory Commission (FERC), which 

conducted one national and three regional technical conferences 

on the proposed rule in which the EPA participated, helped 

inform a number of changes made in this final rule to address 

reliability. 

 As discussed throughout the preamble and TSDs, the 

electricity sector is undergoing a period of intense change. 

While the change in the resource mix has accelerated in recent 

years, wind, solar, other RE, and EE resources have been 

reliably participating in the electric sector for a number of 

years. Many of the potential changes to the electric system that 

the final rule may encourage, such as shifts to cleaner sources 

of power and efforts to reduce electricity demand, are already 

well underway in the electric industry. To the extent that the 

final rule accelerates these changes, there are multiple 

features in the electricity system that ensure that electric 

system reliability will be maintained. Electric system 

reliability is continually being considered and planned for. For 
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example, in the Energy Policy Act of 2005, Congress added a 

section to the Federal Power Act to make reliability standards 

mandatory and enforceable by FERC and the North American 

Electric Reliability Corporation (NERC), the Electric 

Reliability Organization which FERC designated and oversees. 

Along with its standards development work, NERC conducts annual 

reliability assessments via a 10-year forecast and winter and 

summer forecasts; audits owners, operators and users for 

preparedness; and educates and trains industry personnel.

Numerous other entities such as FERC, DOE, state PUCs, 

ISOs/RTOs, and other planning authorities also consider the 

reliability of the electric system. There are also numerous 

remedies that are routinely employed when there is a specific 

local or regional reliability issue. These include transmission 

system upgrades, installation of new generating capacity, 

calling on demand response, and other demand-side actions. 

Additionally, planning authorities and system operators 

constantly consider, plan for, and monitor the reliability of 

the electricity system with both a long-term and short-term 

perspective. Over the last century, the electric industry’s 

efforts regarding electric system reliability have become 

multidimensional, comprehensive, and sophisticated. Under this 

approach, planning authorities plan the system to assure the 
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availability of sufficient generation, transmission, and 

distribution capacity to meet system needs in a way that 

minimizes the likelihood of equipment failure.1342 Long-term 

system planning happens at both the local and regional levels 

with all segments of the electric system needing to operate 

together in an efficient and reliable manner. In the short-term, 

electric system operators operate the system within safe 

operating margins and work to restore the system quickly if a 

disruption occurs.1343 Mandatory reliability standards apply to 

how the bulk electric system is planned and operated. For 

example, transmission operators and balancing authorities have 

to develop, maintain, and implement a set of plans to mitigate 

operating emergencies.1344 

The EPA’s approach in this final rule is consistent with 

our commitment to ensuring that the final rule does not 

interfere with the reliability of the nation’s electricity 

supply. Starting with the proposal, many aspects of the final 

rule’s design were intended to support system reliability, 

 

1342 Casazza, J. and Delea, F., Understanding Electric Power 

Systems: An Overview of the Technology, the Marketplace, and 

Government Regulations, IEEE Press, at 160 (2010). 1343 Id. 1344 NERC Reliability Standard EOP-001-2.1b — Emergency Operations 

Planning, available at 

http://www.nerc.net/standardsreports/standardssummary.aspx. 
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especially the long compliance period and the basic design that 

allows states flexibility to include a large variety of 

approaches and measures to achieve the environmental goals in a 

way that is tailored to each state’s energy resources and 

policies. Indeed, as with numerous prior CAA regulations 

affecting the electric power sector, environmental requirements 

for this industry are accommodated within the existing extensive 

framework established by federal and state law to ensure that 

electricity production and delivery are balanced on an ongoing 

basis and planned sufficiently to ensure reliability and 

affordability into the future. Changes that the EPA is making in 

this final rule respond directly to the comments and the 

suggestions we received on these issues and provide further 

assurance that implementation of the final rule will not create 

reliability concerns. 

First, the final rule allows significant flexibility in how 

the applicable CO2 emission performance rates or the statewide 

CO2 goals are met. Given the differing characteristics of the 

electric grid within each state and region, there are many paths 

to meeting the final rule’s requirements that can be taken while 

continuing to maintain a reliable electricity supply. As further 

described elsewhere in Section VIII, states can develop plans to 

meet the CO2 emission performance rates or state CO2 emission 
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goals by choosing from a variety of state plan types and 

approaches that afford states and affected EGUs appropriate 

flexibility. EE and other non-BSER approaches can strengthen a 

state’s ability to establish a plan to meet the CO2 emission 

performance rates or state CO2 emission goals by providing a 

considerable amount of headroom above the levels of the rates 

and goals. EE especially, because it reduces load, can provide 

assurance that reliability can and will be maintained. 

Second, the final rule provides sufficient time to ensure 

system reliability. The final rule retains the 2030 date for the 

final period, which commenters largely supported as reasonable 

and not a concern for reliability, and addresses one of the key 

issues that commenters pointed to as a reliability-related 

concern by both moving the start of the interim period from 2020 

to 2022 and adjusting the interim goals to provide a less 

dramatic initial reduction requirement and a more gradual glide 

path to the final 2030 goals. As a result of these changes, the 

states themselves will have a meaningful opportunity – which 

many commenters suggested the timing and stringency of the 

proposal failed to create despite our intent to do so – to 

determine the timing, cadence and sequence of actions needed for 

states and sources to meet final rule requirements while 

accommodating the ongoing activity needed to ensure system 
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reliability. The final rule provides more than six years before 

reductions are required and an eight-year period from 2022 to 

2029 to meet interim goals. 

Third, we are including in the final rule a requirement 

that each state demonstrate in its state plan submittal that it 

has considered reliability issues in developing its plan. This 

was suggested by a number of commenters, and we agree it is an 

essential element. 

Fourth, in response to a variety of comments, we are 

providing a reliability safety mechanism that provides a path 

for a state to come to the EPA during an immediate unforeseen, 

emergency situation that threatens reliability to inform the EPA 

that an affected EGU or EGUs may need to temporarily deviate 

from specific state plan requirements to respond to this kind of 

reliability concern. 

Finally, the final rule provides a mechanism for a state to 

seek a revision to its plan in order to address changes in 

circumstances that could have reliability impacts if not 

accommodated in the plan. The long compliance timeframe, with 

several interim steps, naturally provides opportunities for 

states, working with their utilities and reliability entities, 

to assess how implementation is proceeding, identify unforeseen 

changes that may warrant plan revisions, and work with the EPA 
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to make necessary revisions.

We provide more details about these various elements of the 

final rule, as well as other features of the rule that support 

system reliability, below. 

a. Summary of key comments. The EPA received a number of 

comments regarding the proposed rule and electric reliability. 

Many commenters provided specific, useful ideas regarding 

changes that could be made to the proposal to specifically 

address their reliability concerns. For example, many commenters 

state that allowing additional time to comply could help in 

meeting the final rule requirements while addressing their 

reliability concerns. Some commenters suggest that additional 

time would allow them to evaluate potential reliability impacts 

and system changes that need to be made to comply with final 

rule requirements while allowing affected EGUs time to meet 

interim CO2 emissions goals. The EPA also received comment that 

market-based approaches have features that could help support 

reliability, and therefore we should encourage states to join or 

form regional market-based programs. Commenters also stated that 

the EPA should require states to consult with grid operators who 

would analyze the impact of state plans on reliability. A number 

of commenters also suggested that the EPA should include some 

sort of reliability safety valve in the final rule. We note that 
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many participants at the FERC technical conferences on the 

proposed rule also discussed a reliability safety valve in great 

detail with many suggestions for how such a reliability 

mechanism could be designed. The EPA appreciates these and all 

the comments we received regarding the interaction of the 

proposal and electric reliability. We carefully considered all 

comments and incorporated many of the suggested changes in this 

final rule. 

b. Final rule flexibility. In issuing this final rule, the EPA 

considered public comments on the potential interaction between 

the proposal and electric reliability. While we have made every 

effort to develop guidelines that would steer clear of potential 

reliability disruptions, a number of commenters argued that the 

possibility of an unanticipated reliability event cannot be 

entirely eliminated. Of course, even in the absence of these 

guidelines, the electric system will not completely avoid 

reliability issues. The EPA designed the final rule to ensure to 

the greatest extent possible that actions taken by states and 

affected EGUs to comply with the final rule do not increase 

potential reliability issues or complicate their resolution. In 

fact, to the extent that meeting final rule requirements results 

in the reduction of demand, upgrades in transmission efficiency 

and infrastructure, and investment in new, more efficient 
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technologies, the outcome could be that the system is more 

robust and faces fewer risks to electric reliability. 

However many commenters expressed concern that 

notwithstanding these flexibilities, the proposed plan 

development schedule may not leave sufficient time to conduct 

reliability planning between the development of state plans and 

the proposed start of the interim period in 2020. To address 

these concerns and to support a more effective reliability 

planning process, the EPA is moving the start of the interim 

period from 2020 to 2022. The final rule also provides the 

states with up to three years to adopt and submit their final 

state plans. This timing gives system operators the opportunity 

to do what they have already been doing; looking ahead to 

forecast potential contingencies that pose reliability risks and 

identifying those actions needed to mitigate those risks. The 

final rule allows states to develop a pathway over the interim 

period that reflects their own circumstances, such as reflecting 

planned additions and changes in generation mix. Because 

achievement of the emission rates or goals can be demonstrated 

over several years, state plans can accommodate situations where

for example, it may take time to develop new generation, 

pipelines, or transmission while still providing many options 

for meeting the final rule requirements and planning for the 
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reliability of the system. 

c. Considering reliability during state plan development 

process. Under CAA section 111(d)(1)(B), state plans must 

provide for the implementation and enforcement of standards of 

performance for affected EGUs. The EPA is requiring that each 

state demonstrate as part of its state plan submission that it 

has considered reliability issues while developing its plan in 

order to ensure that standards of performance can be implemented 

and enforced. If system reliability is threatened, the ability 

of affected EGUs to meet the requirements of this final rule 

could be compromised if they are required to operate beyond the 

emission standards set in state plans in order to maintain the 

reliability of the electric grid. The requirement that states 

consider reliability as part of the development of state plans 

is designed to ensure that state plans are flexible enough to 

avoid this kind of potential conflict between maintaining 

reliability and implementing emission standards for affected 

EGUs. 

A number of commenters, notably ISOs and RTOs, pointed out 

that planning and anticipation of change are among the essential 

ingredients of ensuring the ongoing reliability of the 

electricity system. To that end, they recommended that as states 

are developing state plans, their activity include the 
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consideration of the reliability needs of the region in which 

affected EGUs operate and of the potential impact of actions to 

be taken in compliance with state plans. Therefore, we are 

requiring that each state demonstrate in its final state plan 

submittal that it has considered reliability issues in 

developing its plan. One particularly effective way in which a 

state can make this demonstration is by consulting with the 

relevant ISOs/RTOs or other planning authorities as they develop 

their plans and documenting this consultation process in their 

state plan submissions. If a state chooses to consider 

reliability through consultation with the ISO/RTO or other 

planning authority, the state should request that the planning 

authority review the state plan at least once during the plan 

development stage and provide its assessment of any reliability 

implications of the plan. While following the recommendations of 

the planning authority would not be mandatory, the state should 

document its consultation process, any response and 

recommendations from the planning authority, and the state’s 

response to those recommendations in its state plan submittal to 

the EPA. This consultation is designed to inform how the state 

might adjust its plan for meeting the CO2 reduction goal required 

under this guideline; the consultation is not a basis for 

relaxing that goal. While we consider this process to be an 
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effective way for a state to demonstrate that it considered 

reliability in developing its state plan, a state may provide 

other comparable support for a demonstration that it has 

considered reliability during the state plan development 

process.1345 The EPA believes that this requirement to demonstrate 

consideration of reliability will provide an essential 

reliability evaluation in the state plan development process. It 

should further help states avoid any conflicts between state 

plans and the maintenance of reliability during implementation 

of the state plan and associated emission standards. 

d. State plan modifications. If, during the implementation of a 

state plan, a reliability issue cannot be addressed within the 

range of actions or mechanisms encompassed in an approved state 

plan, the state can submit a plan revision to the EPA to amend 

the timeframe over which reductions must be made in its plan. In 

such a circumstance, the state plan may need to be adjusted to 

enable affected EGUs to continue to meet final rule requirements 

without causing an otherwise unmanageable reliability threat. 

Whether or not these circumstances occur will depend in part 

upon how each state designs its state plan. States that design 

 

1345 While the EPA is requiring that the states demonstrate that 

they have considered reliability in developing their plans, 

state plan submissions will not be evaluated substantively 

regarding reliability impacts. 
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plans with a good deal of flexibility, such as market-based 

plans or multi-state plans, are less likely to face a potential 

conflict between state plan requirements and the maintenance of 

reliability. States that participate in multi-state programs 

will be better able to weather unexpected risks to reliability. 

Events not anticipated at the time of the final plan 

submittal - such as the retirement of a large low or zeroemitting unit - may trigger the request for state plan 

revisions. It may also be the case that facility-specific 

emissions standards in a state plan are proving to be too 

inflexible to allow the plan to accommodate market or other 

changes in the power sector. In such instances, there should be 

a lead time between the announced retirement of the unit and the 

need to amend the state plan. Therefore, the state should be 

able to utilize the revisions process that the EPA provides. 

The EPA will review a plan revision per the requirements of 

40 CFR part 60. If the state’s request for a state plan revision 

must be addressed promptly to assure a reliable supply of 

electricity, the state must document the risks to reliability 

that would be addressed by the plan revision by providing the 

EPA with a separate analysis of the reliability risk from the 

ISO/RTO or other planning authority. This analysis should be 

accompanied by a statement from the ISO/RTO or other 
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planning/reliability authority that there are no practicable 

alternative resolutions to the reliability risk. In this case, 

the EPA will conduct an expedited review of the state plan 

revision. 

e. Reliability safety valve. Many commenters expressed concerns 

that a serious, unforeseen event could occur during the final 

rule implementation period that would require a quick response 

by system operators and affected EGUs in order to maintain 

system reliability. It is highly unlikely that there would be a 

conflict between activities undertaken under an approved state 

plan and the maintenance of electric reliability, except in the 

case of a state plan that puts relatively inflexible 

requirements on specific plants. While some have pointed out 

severe weather or other short-term events as potentially 

conflicting with state plans, we note that most of those events 

are of short duration and would not require major adjustments to 

emission standards on affected EGUs or state plans. For example, 

during an event like the extreme cold experienced in periods of 

the winter of 2013-2014, affected EGUs may need to briefly run 

at a higher level to accommodate increased demand and/or shortterm unavailability of other generators. However, because 

compliance can be demonstrated over 2-3 years, such a short-term 

event would not cause affected EGUs to be out of compliance with 
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their applicable requirements. States can ensure that this is 

true by drafting plans that allow adequate compliance 

flexibility to accommodate such short-term events. 

We recognize, however, that there are potential system 

emergencies that cannot be anticipated that could cause a severe 

stress on the electricity system for a length of time such that 

the multi-year requirements in a state plan may not be 

achievable by certain affected EGUs without posing an otherwise 

unmanageable risk to reliability. There could be extremely 

serious events, outside the control of affected EGUs, that occur 

that require an affected EGU, or EGUs, to temporarily deviate 

from specific state plan requirements to respond to this kind of 

reliability concern. For example, 1) a catastrophic event such 

as a geomagnetic disturbance caused by solar flares damages 

critical or vulnerable equipment necessary for reliable grid 

operation and a higher emitting resource needs to operate at 

increased levels until an alternative solution can be found; or 

2) a major storm floods and causes severe damage to a large NGCC 

plant in a city with limited access to transmission, 

necessitating that another much higher emitting plant is needed 

to operate until the NGCC plant is repaired; or 3) a serious act 

of sabotage damages an important substation and it will take 

time to work around the problem, and in the meantime a high 
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emitting plant will need to run until transmission access is 

restored; or 4) a large nuclear unit must cease generating due 

to a substantial public safety issue and therefore causes other 

affected EGUs to run at higher levels in the short-term until a 

longer-term solution can be found. This is not an all-inclusive 

list, but it is illustrative of the kind of unforeseeable, 

emergency situation, caused by an extraordinary, unanticipated, 

potentially catastrophic event that, in the case of a state plan 

that imposes inflexible, obligations on individual EGUs 

(especially with short averaging times), may trigger the need 

for immediate, short-term relief from those facility-specific 

requirements. In such an instance, the final rule provides a 

process to ensure that system reliability will not be 

compromised. 

Under such a circumstance, for states using the emissions 

standards plan type, the state must notify the EPA that it is 

necessary to modify the emission standards for an affected EGU 

or EGUs so that for a maximum of 90 days, the EGU or EGUs may 

operate at an emission standard that is above the emission 

standard specified in the relevant state plan but that the CO2

emission performance rates or the state CO2 emission goal will 

still be met. The EPA will consider this reliability safety 

valve to be an approved short–term modification to the state 
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plan without needing to go through the full state plan revision 

process if the state provides proper notification to the EPA. 

The notification to the EPA must be in writing and must include 

a full description of the reliability concern and why the 

affected EGU (or EGUs) needs to operate under modified emission 

standards from those originally imposed on it by the state plan. 

The state must also describe in its notification to the EPA how 

it is coordinating or will coordinate, with relevant planning 

authorities to alleviate the problem in an expedited manner. The 

state should also include a written concurrence from the 

relevant planning authority supporting the temporary 

modification request or an explanation of why this kind of 

concurrence cannot be provided. Additionally, if the relevant 

planning authority has conducted a system-wide or other analysis 

of the reliability concern, the state should include that 

information in its request. 

It is important to note that in such an instance requiring 

a short-term modification to the state plan, the state and 

affected EGUS must continue monitoring and reporting their 

emissions and generation pursuant to requirements in this final 

rule and under the state plan. Additionally, a short-term 

modification to the state plan is specific to the emissions 

standards for the affected EGU(s) needing to operate in a way 
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that ensures system reliability, but such a modification may not 

alter or abrogate the overall obligations under approved state 

plans for the requisite state goal or performance rates to be 

met by affected EGUs. 

At the end of this period of 90 days or less, the state 

must notify the EPA as to whether the reliability concern has 

been addressed and that it is requiring the affected EGU, or 

EGUs, to meet the original emissions standards in the state plan 

approved prior to the short-term modification going forward. It 

must also notify the EPA as to how the CO2 emission performance 

rates or state CO2 emission goals will be met going forward and 

enumerate how it will make up for any emission reductions that 

were lost during the safety valve period. If there still is a 

serious, ongoing reliability issue, the state must provide to 

the EPA a notice that it will be submitting a state plan 

revision. At the end of this period of 90 days or less, the 

emission standards originally approved under the state plan must 

be back in effect for the affected EGUs. 

The EPA intends for this reliability safety valve to be 

used only in exceptional cases and only once by a state. As 

discussed earlier, we are providing states with the flexibility 

to design a program that is appropriate for its electricity 

needs. This flexibility means that a conflict between the 
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requirements of the state plan and maintenance of reliability 

should be extremely rare. If, however, the state finds that 

problems remain after imposition of the reliability safety 

valve, the state must submit a revision to its state plan. 

3. Consideration of effects to employment and economic 

development 

Labor markets respond in complex ways to state policies in 

a way that depends a wide range of factors (e.g., available 

local labor supply, broader labor market trends). Employment 

effects in a state will depend upon the particular steps that 

each state takes in their plan, as well as broader trends at the 

regional and national level. For most state plans, the precise 

effects will often be very hard to quantify because they will 

depend on choices made by utilities and others as the plans are 

implemented. The EPA’s illustrative analysis highlights the 

likelihood for some additional job loss in sectors related to 

coal that are attributable to implementation of this rule. At 

the same time, the EPA’s illustrative analysis highlights that 

there will be new jobs in the utility power sector associated 

with both improving the efficiency of fossil fuel-fired power 

plants and construction of new natural gas-fired and renewable 

power production, and new jobs in the RE and demand-side EE 

sectors. Consideration of these effects in the context of the 
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particulars of the state plan can help states craft plans that, 

to the extent possible, meet multiple environmental and economic 

goals. 

The Partnership for Opportunity and Workforce and Economic 

Revitalization (POWER) Initiative is a new interagency effort 

led by the Economic Development Administration in the Department 

of Commerce that specially targets economic development 

assistance to communities affected by changes in the coal 

industry and the utility power sector and may be of assistance 

to communities that experience job losses.1346 In addition, the 

Department of Commerce, Department of Labor (DOL), Small 

Business Administration, and the Appalachian Regional Commission 

have together created an initiative to issue grants to 

partnerships of regionally-driven economic development and 

workforce development organizations in impacted coal 

communities.1347 

4. Workforce considerations 

Some stakeholders commented that, to ensure that emission 

reductions are realized, it is important that construction, 

operations and other skilled work undertaken pursuant to state 

 

1346 http://www.eda.gov/power/. 1347 https://www.whitehouse.gov/the-press-office/2015/03/27/factsheet-partnerships-opportunity-and-workforce-and-economicrevitaliz. 
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plans is performed to specifications, and is effective, safe, 

and timely. The EPA agrees and encourages states to ask for a 

demonstration that the work is performed by a proficient 

workforce. A good way to ensure such a workforce is to require 

that workers have been certified by: 1) an 

apprenticeship program that is registered with the U.S. DOL, 

Office of Apprenticeship or a state apprenticeship program 

approved by the DOL; 2) a skill certification aligned with the 

U.S. DOE Better Building Workforce Guidelines and validated by a 

third party accrediting body recognized by DOE; or 3) other 

skill certification validated by a third party accrediting 

body. 

5. Tenth Amendment legal considerations 

Some commenters have raised concerns that the emission 

guidelines and requirements for 111(d) state plans violate 

principles of federalism embodied in the U.S. Constitution, 

particularly the Tenth Amendment. These commenters claim that 

states will be unconstitutionally “coerced” or “commandeered” 

into taking certain actions in order to avoid the prospect of 

either a federal 111(d) plan applying to sources in the state, 

or of losing federal funds. 

 We disagree on both fronts. First, the prospect of a 

federal plan applying to sources in a state does not “coerce” or 
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“commandeer” that state into submitting its own satisfactory 

plan. Far from violating principles of federalism, this rule 

provides states with the initial opportunity to submit a 

satisfactory state plan, and provides states flexibility in 

developing that plan. If a state declines to take advantage of 

that opportunity, affected EGUs in that state will instead be 

subject to a federal plan that satisfies statutory 

requirements.1348 This approach is consistent with ordinary 

cooperative federalism regimes that federal courts have 

routinely upheld against Tenth Amendment challenges.1349 

 Second, states that decline to take certain actions under 

this rule will not face the prospect of sanctions, such as 

withdrawn federal highway funds. CAA section 111 does not 

 

1348 Among other things, a federal plan will implement standards 

of performance subject to specific statutory requirements. See 

42 U.S.C. § 7411(a)(1). The APA and CAA would prohibit the 

imposition of any federal plan that is “arbitrary, capricious, 

an abuse of discretion, or otherwise not in accordance with 

law.” 5 U.S.C. § 706(2)(a). Particularly given these independent 

constraints on the EPA’s authority with respect to any potential 

federal plan, the prospect of any such plan would not commandeer 

states or coerce them into submitting their own state plans. 

1349 See, e.g., Hodel v. Va. Surface Mining & Reclamation Ass’n, 

Inc., 452 U.S. 264, 283–93 (1981); Texas v. EPA, 726 F.3d 180, 

196–97 (D.C. Cir. 2013) (noting that “Supreme Court precedent 

repeatedly affirm[s] the constitutionality of federal statutes 

that allow States to administer federal programs but provide for 

direct federal administration if a State chooses not to 

administer it”). 
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contain sanctions provisions, and we are finalizing revisions to 

the implementing regulations making explicit that the EPA will 

not withhold federal funds from a state on account of that 

state’s failure to submit or implement an approvable 111(d) 

state plan. 

Some commenters pointed to section 110(m) as a possible 

source of the EPA’s sanction authority.1350 Section 110(m) grants 

the EPA discretionary authority to withhold some federal highway 

funds under certain conditions. However, section 110(m) requires 

the EPA to adopt regulations to “establish criteria for 

exercising” this discretionary authority, and the only EPA 

regulations implementing section 110(m) apply to SIPs submitted 

under section 110.1351

The EPA never intended to even imply that we would 

contemplate using this authority to encourage state 

participation in this rule under section 111. To the contrary, 

we believe that imposition of a federal plan rather than 

sanctions is the appropriate path in the context of this 

 

1350 Other commenters point to CAA section 179 as a possible 

direct source of this sanctions authority. However, the 

mandatory sanctions outlined in section 179 clearly apply only 

in the contextcontexts of nonattainment SIPs. and responses to 

SIP Calls made under CAA section 110(k)(5). See 42 U.S.C. 

§ 7509(a). 

1351 40 CFR 52.30 (defining “plan or plan item”). 
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program. Accordingly, regardless of whether the EPA could 

theoretically apply discretionary sanctions against states in 

the section 111(d) context, the rule today forbids the agency 

from exercising any such authority. We have included in this 

rule a provision that prohibits the agency from imposing 

sanctions in the event that a state fails to submit or implement 

a satisfactory plan under this rule. As states consider whether 

to take advantage of the opportunity to develop state plans, 

they can be assured that the EPA will not withdraw federal 

funding should they decline to participate. 

I. Resources for States to Consider in Developing Plans 

 As part of the stakeholder outreach and comment processes, 

the EPA asked states what the agency could do to facilitate 

state plan development and implementation. In addition, after 

the comment period closed, the EPA continued to consult with 

state organizations including the Association of Air Pollution 

Control Agencies (AAPCA), Environmental Council of the States 

(ECOS), National Association of Clean Air Agencies (NACAA), 

National Association of Regulatory Utility Commissioners 

(NARUC), National Association of State Energy Officials (NASEO) 

and the National Governors Association (NGA). 

Some states indicated that they wanted the EPA to create 

resources to assist with state plan development, especially 
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resources related to accounting for RE and demand-side EE in 

state plans. They requested clear methodologies for estimating 

emission reductions from RE and demand-side EE policies and 

programs so that these could be included as part of their 

compliance strategies. Stakeholders said that these tools and 

metrics should build upon the EPA’s “Roadmap for Incorporating 

Energy Efficiency/Renewable Energy Policies and Programs into 

State and Tribal Implementation Plans,” as well as the State 

Energy Efficiency Action Network’s “Energy Efficiency Program 

Impact Evaluation Guide.” In addition, stakeholders requested 

clear guidance on how to measure the impacts of RE and demandside EE programs using established EM&V protocols. 

The EPA also heard that states would like guidance on plan 

development to be released at the same time as this final rule. 

This guidance should include allowable programs and policies for 

compliance, examples of compliance pathways, clear information 

on multi-state plan development, and identification of tools. 

As a result of this feedback, in consultation with U.S. DOE 

and other federal agencies, the EPA continued to refine its 

toolbox of decision support resources at: http://www2.epa.gov/ 

www2.epa.gov/cleanpowerplantoolbox. The site includes 

information on regulatory requirements, including state plan 

guidance and state plan decision support. The state plan 
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guidance section serves as a central repository for the final 

emission guidelines, RIA, guidance documents, TSDs and other 

supporting materials. The state plan decision support section 

includes information to help states evaluate different 

approaches and measures they might consider as they initiate 

plan development. This section includes, for example, a summary 

of existing state climate and RE and demand-side EE policies and 

programs, information on electric utility actions that reduce 

CO2, and tools and information to estimate the emissions impact 

of RE and demand-side EE programs. 

The EPA notes that our inclusion of a measure in the 

toolbox does not mean that a state plan must include that 

measure. In fact, inclusion of measures provided at the website 

does not necessarily imply the approvability of an approach or 

method for use in a state plan. States will need to demonstrate 

that any measure included in a state plan meets all relevant 

criteria and adequately addresses elements of the plan 

components discussed in section VIII.D of this preamble. 

IX. Community and Environmental Justice Considerations

Climate change is an environmental justice issue. Certain 

people and communities are more vulnerable to the health and 

economic impacts of climate change than others, including low 

income communities, communities of color, and indigenous 
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communities. Limited resources make some communities less able 

to either adapt to anticipated changes or recover from the 

impacts. Existing health disparities, including an already high 

burden of chronic health conditions, and other inequities in 

these communities contribute to their increased vulnerability. 

Climate change impacts add to the cumulative stresses currently 

faced by these populations.1352

The purpose of this rulemaking is to substantially reduce 

emissions of CO2 from fossil-fired power plants in the United 

States. These emissions contribute to climate change, which has 

been documented to cause adverse health and economic impacts to 

communities in the United States, as well as globally (a more 

robust discussion of how the agency satisfied Executive Order 

12898 can be found in section XII.J of this preamble). This rule 

is one significant step that, along with other domestic programs 

(such as the tailpipe standards and fuel efficiency requirements 

for light, medium, and heavy duty motor vehicles) and programs 

that other countries are putting in place, will begin to address 

the global phenomenon of climate change. 

 

1352 USGCRP 2014: Melillo, Jerry M., Terese (T.C.) Richmond, and 

Gary W. Yohe, Eds., 2014: Climate Change Impacts in the United 

States: The Third National Climate Assessment. U.S. Global 

Change Research Program, 841 pp. 
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The EPA has received extensive input and has had numerous 

discussions with community members and representatives of 

environmental justice advocacy organizations throughout this 

rulemaking. We have heard that this rule is vitally important to 

residents of vulnerable and overburdened communities as it 

directly addresses climate change, which is an issue of concern 

for communities. Additionally, we have heard concerns that the 

plans that states will develop to implement the emission 

guidelines must be sensitive to and protect against the 

possibility of disproportionate impact on those communities that 

live near power plants. We received feedback that it is critical 

that states provide meaningful opportunities for public 

participation in the development of their plans and that they 

pay attention to how their plans may affect overburdened 

communities. We have also heard concerns about potential copollutant increases in communities due to operational and 

efficiency changes as a result of some affected EGUs potentially 

being dispatched more intensively in the future than they were 

in the past. We have also heard concerns about the potential for 

this rulemaking to have disproportionate high and adverse human 

health or environmental effects on affected communities. 

Stakeholders have also strongly conveyed to us that low income 

communities represent tremendous opportunities for deployment of 
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energy efficiency (EE) and renewable energy (RE) compliance 

options, but that focused strategies are essential to ensure 

robust adoption of these technologies by low income communities. 

As the scientific literature presented in section II.A of 

this preamble and the Executive Order 12898 discussion in 

section XII.J of this preamble outline, low-income communities 

and some communities of color are especially vulnerable to the 

health and other adverse impacts of climate change. The EPA 

believes that all communities, including low-income communities 

and communities of color, will benefit from this final rule 

because this action directly addresses the impacts of climate 

change by limiting GHG emissions through the establishment of CO2 

emission guidelines for existing affected fossil fuel-fired EGUs 

and provides significant co-benefit reductions in conventional 

air pollutants. 

 This rule can affect vulnerable communities in several 

ways. First, this rule will reduce the adverse impacts of 

climate change that can affect vulnerable communities 

disproportionally. These are impacts at global and national 

scales and reductions of CO2 anywhere will benefit communities 

everywhere. To the extent that this rule is an important step in 

the global effort to address climate change, vulnerable 

communities are important beneficiaries. 
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The second way this rule can affect communities is through 

the co-benefit reductions in criteria and hazardous air 

pollutants (PM, NOx, and mercury, for example) that will occur 

as a result of a shift to a cleaner and more efficient power 

sector. Our analysis shows projected reductions of XXX,XXX tons 

in 2030 across the country. Impacts from emissions of these 

pollutants are at local and regional scales, and these 

reductions will lead to improved public health both in the 

communities where the facilities reducing emissions are located 

as well as many miles downwind of those facilities. Therefore, 

low income communities, communities of color, and indigenous 

communities are already more vulnerable to the adverse public 

health impacts of climate change and therefore will especially 

benefit from the reductions in air pollutants as a result of 

this rule. 

Other impacts that may be anticipated from this rule can 

affect communities in various ways. The electricity sector is, 

and will continue to be, investing more in renewable energy (RE) 

and in energy efficiency (EE). These trends may impact affected 

communities in at least two ways. First, the expansion of RE and 

EE both provide opportunities for job creation and investment in 

communities. Second, shifts in how electricity is produced and 

used may lead to changes in the cost of electricity and 
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consequent electricity bills. A significant barrier to the 

adoption of EE and RE by affected communities is the higher 

upfront cost (e.g., of purchasing a more efficient appliance or 

installing rooftop solar panels). It is important that 

communities impacted by state plans are able to access EE and RE 

so that they can take advantage of these opportunities to lower 

their electricity bills. The EPA believes it is important for 

states to consider these potential impacts on affected 

communities as they are developing their plans. 

Environmental justice stakeholders are nonetheless 

concerned about possible local increases in pollution that may 

arise from increased dispatch of certain units. 

In the remainder of this section of the preamble, we 

address these many issues and the results of an analysis we 

conducted to assess the proximity of vulnerable communities to 

fossil fuel- fired power plants in the United States. 

Additionally, we discuss one of the most important ways to 

minimize potential adverse impacts — of whatever kind − on 

vulnerable communities: a robust public engagement process for 

state plan development that provides meaningful opportunities 

for participation, evaluation of potential impacts, and a 

discussion of ways to address then. Furthermore, we explain 

changes we have made to the rule to address these issues. 
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These final emission guidelines will be implemented by each 

state upon the EPA’s approval of a state plan. The EPA has 

included a number of conditions to help ensure that affected 

communities will be able to participate meaningfully in the 

development of state plans and that this action will not have 

potential disproportionately high and adverse human health or 

environmental effects on communities, including low-income 

communities and communities of color. The conditions outlined in 

this section of the preamble were considered as part of the 

EPA’s analysis under Executive Order 12898. 

In this section we provide an overview of the actions that 

the agency is taking to help ensure that vulnerable communities 

are not disproportionately impacted by this rulemaking.1353As 

described in the Executive Summary, climate change is an 

environmental justice issue. Low-income communities and 

 

1353 In this preamble, the EPA discusses environmental justice in 

two sections. Section XI.J specifically addresses how the agency 

has met the directives under Executive Order 12898. The EPA 

defines environmental justice as the fair treatment and 

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. This section of the preamble 

addresses actions that the agency is taking related to 

environmental justice and other issues (e.g., increased 

electricity costs) that may affect communities covered by 

Executive Order 12898 as well as other communities.
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communities of color already overburdened with pollution are 

likely to be disproportionately affected by, and less resilient 

to, the impacts of climate change. This rulemaking will provide 

broad benefit to communities across the nation, as its purpose 

is to reduce greenhouse gases, the most significant driver of 

climate change. While addressing climate change will provide 

broad benefits, it is particularly beneficial to low-income 

populations and some communities of color (in particular, 

populations defined jointly by ethnic/racial characteristics and 

geographic location) where people are most vulnerable to the 

impacts of climate change (a more robust discussion of the 

impacts of climate change on vulnerable communities is provided 

in the Executive Order 12898 section XII.J of this preamble). 

While climate change is a global phenomenon, the adverse effects 

of climate change can be very localized, as impacts such as 

storms, flooding, droughts, and the like are experienced in 

individual communities. 

Vulnerable communities also often receive more than their 

fair share of conventional air pollution, with the attendant 

adverse health impacts. The changes in electricity generation 

that will result from this rule will further benefit communities 

by reducing existing air pollution that directly contributes to 

adverse localized health effects. These air quality improvements 
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will be achieved through this rule because the electric 

generating units that emit the most greenhouse gases also have 

the highest emissions of conventional pollutants, such as SO2, 

NOx, fine particles, and HAP. These pollutants are known to 

contribute to adverse health outcomes, including the development 

of heart or lung diseases, such as asthma and bronchitis, 

increased susceptibility to respiratory and cardiac symptoms, 

greater numbers of emergency room visits and hospital 

admissions, and premature deaths.1354 The EPA expects that the 

reductions in utilization of higher-emitting units likely to 

occur during the implementation of state plans will produce 

significant reductions in emissions of conventional pollutants, 

particularly in those communities already overburdened by 

pollution, which are often low-income communities, communities 

of color, and indigenous communities. These reductions will have 

beneficial effects on air quality and public health both locally 

and regionally. Further, this rulemaking complements other 

actions already taken by the EPA to reduce conventional 

pollutant emissions and improve health outcomes for overburdened 

communities. 

 

1354 Six Common Air Pollutants. 

http://www.epa.gov/oaqps001/urbanair/ 
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By reducing millions of tons of CO2 emissions that are 

contributing to global greenhouse gas levels and providing 

strong leadership to encourage meaningful reductions by 

countries across the globe, this rule is a significant step to 

address health and economic impacts of climate change that will 

fall disproportionately on vulnerable communities. By reducing 

millions of tons of conventional air pollutants, the rule will 

lead to better air quality and improved health in those 

communities. We heard from many commenters who recognize and 

welcome those benefits. 

There are other ways in which the actions that result from 

this rulemaking may affect communities in positive or 

potentially adverse ways and we also heard about these from 

commenters. 

While the agency expects overall emission decreases as a 

result of this rulemaking, we recognize that some EGUs may 

operate more frequently, as a result of this rulemaking. To the 

extent that we project increases in utilization as a result of 

this rulemaking, we expect these increases to occur generally in 

lower-emitting NGCC units, which have minimal or no emissions of 

SO2 and HAP, lower emissions of particulate matter, and much 

lower emissions of NOx compared to higher-emitting steam units. 

We acknowledge the concerns that have been raised on this point 
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but also the difficulty in anticipating prior to plan 

implementation where those impacts might occur. In addition to 

providing for a robust state planning process with opportunity 

for meaningful input, the EPA is encouraging states to evaluate 

the actual impacts of their plans once implemented and, as 

described below, the EPA intends to conduct an assessment of 

whether and where emission increases may that may result from 

plan implementation and to work with states to mitigate adverse 

impacts, if any, in overburdened communities. 

In addition to the many positive anticipated health benefits 

of this rulemaking, it also will increase the use of clean 

energy and will encourage energy efficiency. These changes in 

the electricity generation system, which are already occurring 

but may be accelerated by this program, are expected to have 

other positive benefits for communities. The electricity sector 

is, and will continue to be, investing more in RE and EE. The 

construction of renewable generation and the implementation of 

energy efficiency programs such as residential weatherization 

will bring investment and employment opportunities to the 

communities where they take place. We recognize that certain 

communities whose economies may be affected by changes in the 

utility and related sectors may be particularly impacted by the 

final rule. The EPA encourages states to make an effort to 
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engage with these communities, including workers and their 

representatives in these sectors, including energy efficiency. 

It is important to ensure that all communities share in the 

benefits of this program. And while we estimate that its 

benefits will greatly exceed its costs (as noted in the RIA for 

this rulemaking), it is also important to ensure that to the 

extent there are increases in electricity costs, that those do 

not fall disproportionately on those least able to afford them. 

The EPA has engaged with community groups throughout this 

rulemaking, and we received many comments on the issues outlined 

above from community groups, environmental justice 

organizations, faith-based organizations, public health 

organizations, and others.1355 This input has informed this final 

rulemaking and prompted the EPA to consider other steps that the 

agency can take in the short and long term to assist states and 

stakeholders to consider environmental justice and impacts to 

communities in plan development and implementation. 

It has also prompted us to work with our federal partners 

to make sure that states and communities have information on 

federal resources available to assist communities. We describe 

these resources below, as well as resources that the EPA will be 

 

1355 Detailed information on the outreach conducted as part of 

this rulemaking is provided in section I of this preamble. 
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providing to assist communities in accessing EE/RE and financial 

assistance programs. In our discussion below we also provide 

models of programs that other states are currently using to 

assist communities in accessing available resources that states 

could use when developing their plans. 

Finally, and importantly, we recognize that communities 

must be able to participate meaningfully in state plan 

development. In this section, we discuss the requirements in the 

final rule for states, as they develop their plans, to provide 

opportunities for public involvement, and resources available to 

states and communities to enhance the success of the public 

process. 

A. Proximity Analysis 

To further The EPA is committed to assisting states and 

communities to 

develop plans that ensure that this rulemaking does not 

have any 

potential disproportionately high and there are no 

disproportionate, adverse human health or environmental 

effectsimpacts on vulnerableoverburdened communities. To provide 

information fundamental to beginning that process, the EPA has 

conducted ana proximity analysis for this final rulemaking that 

summarizes demographic data on the communities located near 
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power plants (a proximity analysis)..1356 The EPA understands 

that, in order to prevent any potential disproportionately, high 

and adverse human health or environmental effects on these 

communities, both states and communities must have information 

on the communities living near facilities, including demographic 

data, and that accessing and using census data files requires 

expertise that some community groups may lack. Therefore, the 

EPA used census data from the American Community Survey (ACS) 

2008-2012 to conduct a proximity analysis for this rulemaking, 

and thethat can be used by states and communities as they 

develop state plans and as they later assess the final plans’ 

impacts. The analysis and its results are presented in the EJ 

Screening Report for the Clean Power Plan, which is located in 

the docket for this rulemaking. at EPA-HQ-OAR-2013-0602. 

The proximity analysis provides detailed demographic 

information on the communities located within a 3-mile radius of 

each affected power plant in the United States. Included in the 

analysis is the breakdown by percentage of community 

characteristics such as income and minority status. The analysis 

shows a higher percentage of communities of color and low-income 

communities living near power plants than national averages. It 

 

1356 The proximity analysis was conducted using the EPA’s 

environmental justice mapping and screening tool, EJSCREEN. 
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is important to note that the impacts of power plant emissions 

are not limited to a 3-mile radius and the impacts of both 

potential increases and decreases in power plant emissions can 

be felt many miles away. Still, being aware of the 

characteristics of communities closest to power plants is a 

starting point in understanding how changes in the plant’s air 

emissions may affect the air quality experienced by some of 

those already experiencing environmental burdens. 

Although overall there is a higher fraction of communities 

of color and low-income populations living near power plants 

than national averages, there are differences between rural and 

urban power plants. There are many rural power plants that are 

located near small communities with relatively few persons of 

color but high percentages of low-income populations and lower 

percentages of communities of color. In urban areas, nearby 

communities tend to be both low-income communities and 

communities of color. In light of this difference between rural 

and urban communities proximate to power plants and in order to 

adequately capture both the low-income and minority aspects 

central to environmental justice considerations, we use the 

terms “vulnerable” or “overburdened” when referring to these 

communities. Our intent is for these terms to be understood in 

an expansive sense, in order to capture the full scope of 
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communities, including indigenous communities most often located 

in rural areas, thatare central to our environmental justice and 

community considerations.

As stated in the Executive Order 12898 discussion located 

in section XII.J of this preamble, the EPA believes that all 

communities will benefit from this final rulemaking because this 

action directly addresses the impacts of climate change by 

limiting GHG emissions through the establishment of CO2 emission 

guidelines for existing affected fossil fuel-fired power plants. 

The EPA also believes that the information provided in the 

proximity analysis will promote engagement between 

affectedvulnerable communities and their states and will be 

useful for states as they begin developing their plans. In 

addition to providing the proximity analysis in the docket of 

this rulemaking, the EPA will disseminate the proximity analysis 

to states and will make it publicly available on its Clean Power 

Plan (CPP) Community Portal. Furthermore, the EPA has also 

created an interactive mapping tool that illustrates where power 

plants are located and provides information on a state level. 

This tool is available at: 

http://cleanpowerplanmaps.epa.gov/CleanPowerPlan/. 

A. Title VI 
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States that are recipients of EPA financial assistance must 

comply with all federal nondiscrimination statutes that together 

prohibit discrimination on the bases of race, color, national 

origin (including limited-English proficiency), disability, sex 

and age. These laws include: Additionally, the EPA encourages 

states to conduct their own analyses of community considerations 

when developing their plans. Each state is uniquely 

knowledgeable about its own communities and well-positioned to 

consider the possible impacts of plans on vulnerable communities 

within its state. Conducting state-specific analyses would not 

only help states assess possible impacts of plan options, but it 

would also enhance a state’s understanding of the means to 

engage these communities that would most effectively reach them 

and lead to valuable exchanges of information and concerns. A 

state analysis, together with the proximity analysis conducted 

by the EPA, would provide a solid foundation for engagement 

between a state and its communities. 

Such state-specific analyses need not be exhaustive. An

examination of the options a state is considering for its plan, 

and any projections of likely resulting increases in power plant 

emissions affecting low-income populations, communities of color 

populations, or indigenous communities, would be informative for 

communities. The analyses could include available air quality 
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monitoring data and information from air quality models, and, if 

available, take into account information about local health 

vulnerabilities such as asthma rates or access to healthcare. 

Alternatively, a simple analysis may consider expected EGU 

utilization in geographic proximity to overburdened communities. 

The EPA will provide states with information on its publicly 

available environmental justice screening and mapping tool, EJ 

SCREEN, which they may use in conducting a state-specific 

analysis. The EPA will also provide states with resources 

containing examples of analyses that other states have conducted 

to examine the impacts of their programs on overburdened 

communities. Additionally, the EPA encourages states to submit a 

copy of their analysis if they choose to conduct one, with their 

initial and final plan submittals. 

Title VI of the Civil Rights Act of 1964; Section 504 of 

the Rehabilitation Act of 1973; Section 13 of the Federal Water 

Pollution Control Act Amendments of 1972; Title IX of the 

Education Act Amendments of 1972; and the Age Discrimination Act 

of 1975. Compliance with these nondiscrimination statutes is a 

recipient’s separate and distinct obligation from compliance 

with environmental regulations. In other words, all recipients 

are required to ensure that all aspects of their implementation 
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plans of the Clean Power Plant guidance do not violate any of 

the federal nondiscrimination statutes, including Title VI. 

The EPA’s Office of Civil Rights (OCR) is responsible for 

carrying out compliance with these federal nondiscrimination 

statutes and does so through a variety of means 

including: complaint investigation; agency-initiated compliance 

reviews; pre-grant award assurances and audits; and technical 

assistance and outreach activities. Anyone who believes that any 

of the federal nondiscrimination laws enforced by OCR have been 

violated by a recipient of EPA financial assistance may file an 

administrative complaint with EPA’s OCR. 

B. Community Engagement in State Plan Development 

Additionally, meaningful public involvement as described in 

EPA’s 2006 Public Involvement Guidance (71 Fed. Reg. 14,207) 

should play a pivotal role to ensure that the state 

implementation plans of the Clean Power Plant guidance do not 

violate any of the federal nondiscrimination statutes. States 

should seek opportunities to enhance public involvement in the 

environmental decision-making process, including providing 

access to limited English proficient individuals, as a means of 

hearing and considering communities’ concerns early in the 

process which may potentially reduce the chances of a Title VI 

complaint being filed about a recipient’s actions. 
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As highlighted above the EPA is requiring that states 

engage with all stakeholders throughout the state plan 

development process and that states consider and address all 

feedback received as they create their final plans. In 

sectionsections VIII.D-E of this preamble, the EPA notesexplains

that states need to ensure that there is meaningful involvement 

for all members of the public engage meaningfully with 

communities and other stakeholders during the initial and final 

plan submittal process. Thisprocesses. Meaningful engagement 

includes providing the opportunity for public outreach to 

vulnerable communities, sharing information and soliciting input 

on state plan development and on any accompanying assessments 

such as those described above, and selecting methods for 

engagement to support communities’ involvement at critical 

junctures in plan formulation and implementation. This 

engagement also includes providing the public the opportunity to 

comment on the state’s draftinitial submittal and responding to 

significant comments received (, including comments from 

vulnerable communities potentially impacted by their plan),, as 

well as conducting a public hearing and responding to comments 

before a final state plan is submitted. Additionally, the EPA 

expects that states will conduct outreach meetings, which could 

include public hearings or listening sessions, before the 
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initial submittal is made. The EPA also encourages states to 

provide background information about their proposed final state 

plan or their initial state plan in the appropriate languages in 

advance of their public hearing and at their public hearing. The 

EPA recommends that states provide translators and other 

resources at their public hearings, to ensure that members of 

the public can provide oral feedback. 

In the initial submittal, the final rule requires that 

states provide information to the agency about the community 

engagement they have undertaken and the means by which they 

intend to involve vulnerable communities and other stakeholders 

as they develop their final plan. Furthermore, as noted in 

section VIII.E of this preamble, in determining if states are 

eligible for a 2-year extension for submission of final plans, 

the EPA will requirerule requires that states demonstrate 

thathow they are activelymeaningfully engaging 

affectedvulnerable communities and other interested stakeholders

as part of their public participation process. The steps that 

states could take to demonstrate that they are actively engaging 

the public, including communities affected by their planThe EPA 

consulted its May 2015, Guidance on Considering Environmental 

Justice During the Development of Regulatory Actions, when 

crafting this rulemaking and recommends that states consult it 
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to assist them in engaging meaningfully with vulnerable 

communities.1357 Additionally, states in their initial submittal 

and 2017 update must show how they identified the communities 

with whom they are engaging as they develop their plans. Some 

suggested actions that states could take to engage actively with 

the public, including conducting meaningful engagement with 

vulnerable communities, are outlined in section VIII.E of this 

preamble. Additionally, as outlined in section VIII.D of this 

preamble, the final plan submitted by states shouldmust include 

an overview of the public hearing(s) conducted and information 

on how the state ensured that the hearing(s) were accessible to 

stakeholders including vulnerable communities that may be 

potentially impacted by their plan. 

It is important to the EPA that affected communities have 

the information needed to The EPA is committed to supporting 

states in effectively engage with states during the state plan 

development process. At the same time, it is important to the 

EPA that states also have support in engaging with affected 

communities throughout the state plan development process. As a 

result, theengaging with communities as they develop and 

 

1357 Guidance on Considering Environmental Justice During the 

Development of Regulatory Actions. 

http://epa.gov/environmentaljustice/resources/policy/considering

-ej-in-rulemaking-guide-final.pdf. May 2015. 
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implement their plans. The EPA will provide training and other 

resources throughout the implementation process that will assist 

affected communities and states as they engage with one 

anotherstates and communities in understanding plan requirements 

and options for plan development. These trainings will be a 

continuation of those that the EPA has already conducted with 

communities and states both pre- and post-proposal. The EPA will 

be reachingreach out to a wide variety of community 

stakeholders, including groups representing lowincomeenvironmental justice communities and communities of 

color, faith-based organizations, academic organizations working 

with communitiesvulnerable and overburdened communities, 

affordable housing advocates, public health professionals, 

public health organizations, and other community stakeholders. 

As noted in section VIII.C of this preamble, the EPA will 

encourage multi-state partnerships. Multi-state partnerships, 

like the Regional Greenhouse Gas Initiative (RGGI), have 

demonstrated their ability to invest in EE/RE programs and 

direct energy bill assistance programs in communities.1358 For 

example, from 2008-2013, RGGI invested over $1 billion in 

 

1358 Investment of RGGI Proceeds through 2013. 

http://www.rggi.org/docs/ProceedsReport/Investment-RGGIProceeds-Through-2013.pdf 
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auction proceeds towards various policy priorities.1359 Investment 

into energy efficiency programs made up 62% of cumulative RGGI 

investments through 2013.1360 These investments are projected to 

earn an expected return of more than $2.3 billion in lifetime 

energy bill savings for 1.2 million households and 17,550 

businesses.1361 Additionally, investments in clean and renewable 

energy make up 8% of cumulative investments and these 

investments are expected to yield a return of more than $240 

million in lifetime energy bill savings to 7,000 participating 

households and 250 businesses.1362 Furthermore, direct bill 

assistance makes up 15% of cumulative investments, these 

investments have returned more than $140 million in bill savings 

to more than 2.4 million households, much of which is targeted 

towards low income families.1363 

C. Providing Communities with Access to Additional Resources 

In addition to providing resources to states, the EPA 

encourages states in the writing of their plans to useto be 

aware of existing efforts undertaken by other state models that 

helpstates aimed at providing low -income communities access the 

 

1359 Ibid. 1360 Ibid. 1361 Ibid. 1362 Ibid. 1363 Ibid.
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benefits of energy efficiency, renewable energy, and to 

financial assistance programs. and technical assistance programs 

for EE and RE, and to consider similar approaches that may make 

sense for their own states. The EPA encourages states to 

consider targeting economic development resources to communities 

that are likely to be negatively affected by ongoing changes in 

the utility and related sectors in support of efforts to 

diversify their economies, attract new sources of investment, 

and create new jobs. 

One example of such a program is Thetargeted at low-income 

communities is the Maryland EmPOWER Low Income Energy Efficiency 

Program (LIEEP).1364 The LIEEP program administered by the 

Maryland Department of Housing and Community Development (DHCD) 

helps low -income households through free installation of energy 

conservation materials (i.e., installation, hot water system 

improvements, lighting retrofits, furnace cleaning, tuning and 

safety repairs, refrigerator retrofits, etc.).1365 Funding for 

this program is provided by EmPOWER Maryland partners: Baltimore 

Gas and Electric, Southern Maryland Electric Cooperative, 

 

1364 EmPOWER Maryland Low Income Energy Efficiency Programs 

(LIEEP). 

http://www.mdhousing.org/website/Programs/lieep/Default.aspx. 

1365 Ibid. 
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Delmarva Power, Allegheny Energy and Pepco.1366 This program is 

available to both homeowners and renters.1367 Additionally, the 

Maryland Department of Housing provides low -income families 

with home heating bill assistance and furnace repairs and 

replacements through the Maryland Energy Assistance Program 

(MEAP).1368 Maryland’s Electric Universal Service Program (EUSP) 

helps low-income electric customers with their electric bills.1369

Another example of a program is EmPower New York, which 

provides no-cost energy solutions to low-income populations.1370

Currently there are about 100,000 people who are receiving 

assistance. Both homeowners and renters are eligible to receive 

assistance under this program. The types of assistance available 

include energy efficiency upgrades (plugging leaks, adding 

insulation, replacing inefficient refrigerators and freezers and 

new energy-efficient lighting). Other states, like the State of 

Colorado’s Energy Outreach Colorado program, offer similar 

resources for low-income populations. 1371

 

1366 Ibid. 1367 Ibid. 1368 Energy Assistance. 

http://www.dhr.state.md.us/blog/?page_id=4326. 

1369 Ibid. 1370 EmPower New York. http://www.nyserda.ny.gov/AllPrograms/Programs/EmPower-New-York 

1371 Energy Outreach Colorado. http://www.energyoutreach.org/about 
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In 2013, the New York State Energy and Research Development 

Authority (NYSERDA) was able to secure a triple-A rated 

financial guarantee from the state’s Clean Water State Revolving 

Fund (SRF) for a $24 million bond issue. Proceeds funded 

residential energy efficiency loans that were available to all 

utility customers, including low-income households. SRF 

eligibility was based on the beneficial impact of EE investment 

in reducing atmospheric deposition on impaired water bodies 

consistent with Section 319 of the Clean Water Act. 

 As discussed below, there are also many federal programs 

that can help low-income populations access the benefits of 

renewable energy, energy efficiency, and the economic benefits 

of a cleaner energy economy. 

In the coming months, the EPA will continue to provide 

information and resources for affected communities and states on 

existing federal, state, local, and other financial assistance 

programs to encourage EE/RE opportunities that are already 

available to communities. The For example the EPA will also

provide a catalog of current or recent state and local programs 

that have successfully helped communities adopt EE/RE measures. 

The goal of these resources is to help affectedvulnerable

communities gain the benefits of this rulemaking by encouraging 

that states use these types of tools in their state plans. The 
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use of these RE/EE tools can also help low-income households 

reduce their electricity consumption and bills. 

Additionally, theThe EPA recognizes the potential impacts 

that this rulemaking could have on jobs in communities. 

Therefore, in section VIII.HG of this preamble, the EPA has 

outlined that states, in designing their state plans, should 

consider the effects of their plans on employment and overall 

economic development to assure thatrealize the opportunities for 

economic growth and jobs that the plans offer are manifested..

To the extent possible, states should try to assure that 

communities that canmay be expected to experience job losses can 

also take advantage of the opportunities for job growth or 

otherwise transition to healthy, sustainable economic growth 

(e.g., with regard to installingdelivering energy efficiency 

measures and installing rooftop solar panels). Additionally, as 

part of the resources that we will be providing to states and 

affectedlow-income communities, the EPA will provide information 

on the White House’s Partnership Administration’s Partnerships 

for Opportunity and Workforce and Economic Revitalization 

(POWER) Initiative and other programs that specially 

targetsspecifically target economic development assistance to 
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communities affected by changes in the coal industry and the 

utility power sector.1372 

D. Federal Programs and Resources Available to Communities 

Federal agencies have a history of bringing energy 

efficiency and renewable energy to low-income 

communities. Earlier this summer, the Administration announced a 

new initiative to scale up access to solar energy and cut energy 

bills for all Americans, in particular low- and moderate-income 

communities, and to create a more inclusive solar workforce. As 

part of this new initiative, the U.S. Department of Energy 

(DOE), the U.S. Department of Housing and Urban Development 

(HUD), U.S. Department of Agriculture (USDA), and the EPA 

launched a National Community Solar Partnership to unlock access 

to solar energy for the nearly 50 percent of households and 

businesses that are renters or do not have adequate roof space 

to install solar systems, with a focus on low- and moderateincome communities. The Administration also set a goal to 

install 300 megawatts (MW) of renewable energy in federally 

subsidized housing by 2020 and plants to provide technical 

assistance to make it easier to install solar energy on 

affordable housing, including clarifying how to use federal 

 

1372 http://www.eda.gov/power/.
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funding for energy efficiency and renewable energy. To continue 

enhancing employment opportunities in the solar industry for all 

Americans, AmeriCorps is providing funding to deploy solar 

energy and create jobs in underserved communities, and DOE is 

working to expand solar energy education and opportunities for 

job training. 

These recent announcements build on the many existing 

federal programs and resources available to improve energy 

efficiency and accelerate the deployment of renewable energy in 

vulnerable communities. Some examples of these resources 

include: the Department of Energy’s Weatherization Assistance 

Program, Health and Human Service’s Low Income Home Energy 

Assistance Program, the Department of Agriculture’s Energy 

Efficiency and Conservation Loan Program, High Cost Energy Grant 

Program, and the Rural Housing Service’s Multi-Family Housing 

Program. 

HUD supports energy efficiency improvements and the 

deployment of renewable energy on affordable housing through its 

Energy Efficient Mortgage Program, Multifamily Property Assessed 

Clean Energy Pilot with the State of California, PowerSaver 

Program, and the use of Section 108 Community Development Block 

Grants. The Department of Treasury provides several tax credits 
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to support renewable energy development and energy efficiency in 

low-income communities, including the New Markets Tax Credit 

Program and the Low-Income Housing Tax Credit. The EPA’s REPowering America’s Land Initiative promotes the reuse of 

potentially contaminated lands, landfills and mine sites – many 

of which are in low-income communities – for renewable energy 

through a combination of tailored redevelopment tools for 

communities and developers, as well as site-specific technical 

support. The EPA’s Green Power Partnership is increasing 

community use of renewable electricity across the country and in 

low-income communities. The EPA partners with energy efficiency 

programs throughout the country that leverage ENERGY STAR to 

deliver broad consumer energy-saving benefits, of particular 

value to low-income households who can least afford high energy 

bills. ENERGY STAR also works with houses of worship to reduce 

energy costs – savings that can then be repurposed to their 

community mission, including programs and assistance to 

residents in low-income communities. The EPA will be working 

with these federal partners and others to ensure that states and 

vulnerable communities have access to information on these 

programs and their resources. 

The federal government also has a number of programs to 

expand employment opportunities in the energy sector, including 
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for underserved populations. Examples of these include HUD, DOE, 

and the Department of Education’s “STEM, Energy, and Economic 

Development” program; DOE’s Diversity in Science and Technology 

Advances National Clean Energy in Solar (DISTANCE-Solar) 

Program; Grid Engineering for Accelerated Renewable Energy 

Deployment (GEARED); the Department of Labor’s Trade Adjustment 

Assistance Community College and Career Training (TAACCCT), 

Apprenticeship USA Advancing Apprenticeships in the Energy 

Field, Job Corps Green Training and Greening of Centers, and 

YouthBuild; and the EPA’s Environmental Workforce Development 

and Job Training (EWDJT) program. 

E. Multi-pollutant planning and Co-Pollutants 

As outlined in the final Clean Power Plan, states and 

sources have continued obligations to meet all other CAA 

requirements addressing conventional pollutants . Because the 

CAA envisions control of these other pollutants as a continuous 

process (through provisions such as periodic review of the NAAQS 

and residual risk requirements under the MACT program), the EPA 

believes that the Clean Power Plan provides an opportunity for 

states to consider strategies for meeting future CAA planning 

obligations as they develop their plans under this rulemaking. 

Multi-pollutant strategies that incorporate criteria pollutant 
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reductions over the planning horizons specific to particular 

states, jointly with strategies for reducing CO2 emissions from 

affected EGUs needed to meet Clean Power Plan requirements over 

the time horizon of this rule, may accomplish greater 

environmental results with lower long-term costs. Such 

strategies may also provide opportunities for states, 

communities, and affected facilities to consider the most 

effective means of meeting these obligations while limiting or 

eliminating localized emission increases that would otherwise 

affect overburdened communities. Furthermore, this type of 

multi-pollutant approach has been suggested by states and 

regulated sources in past rulemakings as a tool to determine the 

best system of emission reductions. The EPA recommends that 

states consider such strategies in consultation with their 

communities, affected facilities, and other stakeholders.

As a result of this rulemaking, and as stated in section 

XI.F of this preamble, the EPA expects that most of America will 

benefit from improved air quality for PM2.5, ozone, and HAP, as 

well as greenhouse gases. Nonetheless, due to operational and 

efficiency changes, some affected EGUs may be dispatched more 

intensively in the future than they were in the past. While the 

EPA will approve state plans, it is the states that have the 

ultimate responsibility to implement the guidelines of this 
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rulemaking in order to meet their goals; as a result the EPA 

cannot predict localized emission increases or decreases. While 

there may be increases of co-pollutants at some facilities, it 

is important to remember that affected EGUs will still have to 

comply with other CAA rulemakings in addition to the guidelines 

in this final rulemaking. As noted in the NSR discussion in 

section X.A of this preamble, a state’s CAA section 111(d) plan 

may require an affected EGU to undertake physical or operational 

changes to improve its efficiency, which could result in an 

increase in the unit’s dispatch and an increase in the unit’s 

annual emissions of GHGs and/or other regulated pollutants. 

However, a state can take steps to avoid increased utilization 

of particular affected EGUs (i.e., dispatching other units) and 

associated emissions of regulated pollutants whose environmental 

effects would be more localized around the affected EGU. To the 

extent that states take this path, there would be no 

disproportionate impacts in the areas near such affected EGUs. 

For those affected EGUs in a permitting situation for which 

the EPA is the permit reviewing authority, the EPA will consider 

environmental justice issues, as required by Executive Order 

12898. 

Air quality in a given area, even in locations near 

emission sources, is influenced by is affected by emissions 
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from nearby sources and in partmay be influenced by emissions 

that travel hundreds of miles and mix with emissions from other 

sources.1373 In the Cross-State Air Pollution Rule the EPA used 

its authority to reduce emissions that significantly contribute 

to downwind exposures. The regulatory impact analysisRIA for the 

final Cross-State Air Pollution Rule anticipates substantial 

health benefits for the population across a wide region. 

ThereforeSimilarly, the EPA believes that, like the Cross-State 

Air Pollution Rule, this rulemaking will result in significant 

health benefits because it will reduce co-pollutant emissions of 

SO2 and NOx on a regional and national basis.1374 Thus, localized 

increases in NOx emissions may well be more than offset by NOx 

decreases elsewhere in the region that produce a net improvement 

in ozone and particulate concentrations across the area.

Another effect of the final CO2 emission guidelines for 

affected existing fossil fuel-fired EGUs willmay be increased 

utilization of other, unmodified EGUs - in particular, high 

efficiency gas-fired EGUs - with relatively low GHG emissions 

per unit of electrical output. These plants willmay operate more 

hours during the year and could emit pollutants, including 

pollutants whose environmental effects would be localized/ and

 

1373 76 FR 48348. 1374 76 FR 48347. 
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or regional rather than global as is the case with GHG 

emissions. Changes in utilization already occur in response to 

energy demands and evolving energy sources, but the final CO2 

emission guidelines for affected existing fossil fuel-fired EGUs 

can be expected to cause more such changes. Increased 

utilization of solid fossil fuel-fired units generally would not 

increase peak concentrations of PM2.5, NOx, or ozone around such 

EGUs to levels higher than those that are already occurring 

because peak hourly or daily emissions generally would not 

change; however, increased utilization may make periods of 

relatively high concentrations more frequent. It should be noted 

that the gas-fired sources likely to be dispatched more 

frequently have very low emissions of primary PM, SO2, and HAP 

per unit of electrical output; therefore and that they must 

continue to comply with other CAA requirements that directly 

address the conventional pollutants, including federal emission 

standards, rules included in state implementation plans, and 

conditions in Title V operating permits, in addition to the 

guidelines in this final rulemaking. Therefore, local (or 

regional) air quality for these pollutants is not likely to be 

significantly affected. 

For natural gas-fired EGUs, the EPA found that regulation 

of HAP emissions “is not appropriate or necessary because the 
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impacts due to HAP emissions from such units are negligible 

based on the results of the study documented in the utility 

RTC.”1375 Because gas-fired EGUs emit essentially no mercury, 

increased utilization will not increase methylmercurymethyl 

mercury concentrations in water bodies near these affected EGUs. 

In studies done by DOE/NETL comparing cost and performance of 

coal- and NGCC-fired generation, they assumed SO2, NOXNOx, PM 

(and Hg) emissions to be “negligible.” Their studies predict NOx 

emissions from a NGCC unit to be approximately 10 times lower 

than a subcritical or supercritical coal-fired boiler.1376 Many, 

although not all, NGCC units are also very well controlled for 

emissions of NOx through the application of after combustion 

controls such as selective catalytic reduction. 

Depending on the design of the state plan, the state may be 

able to predict which affected EGUs may increase generation 

and/or may cause increases in emissions and should address any 

concerns about localized NOx concentrations in the design of the 

CAA section 111(d) program, or separately from the CAA section 

 

1375 65 FR 79831. 1376 “Cost and Performance Baseline for Fossil Energy Plants 

Volume 1: Bituminous Coal and Natural Gas to Electricity” Rev 

2a, September 2013 Revision 2, November 2010 DOE/NETL-2010/1397.
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111(d) program planning process but before such program is 

implemented. 

Existing tracking systems will also allow states and the 

EPA to be aware of affected EGUs whose utilization has increased 

most significantly, and to assess whether air quality has 

changed in the communities around such affected EGUs. There are 

multiple mechanisms in the CAA to address situations where there 

is an existing air quality problem or where one may develop. 

Additionally, states will have to comply with the National 

Ambient Air Quality Standards (NAAQS) and other EPA rulemakings 

that come into effect during this same compliance period to 

protect public health and the environment. 

F. Assessing Impacts of State Plan Implementation 

It is important to the EPA that the implementation of state 

plans be assessed in order to identify whether they cause any 

adverse impacts on communities already overburdened by 

disproportionate environmental harms and risks. The EPA will 

conduct its own assessment during the implementation phase of 

this rulemaking to determine whether the implementation of state 

plans developed pursuant to this rulemaking and other air 

quality rules are, in fact, reducing emissions and improving air 

quality in all areas or whether there are localized air quality 

impacts that need to be addressed under other CAA authorities. 
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Furthermore, the EPA recommends that states conduct evaluations 

of their own to determine the impacts of their plans on 

overburdened communities. An example of one such approach to 

assessing a state plan for reducing greenhouse gases is the 

California Air Resources Board’s (CARB), First Update on the 

Climate Change Scoping Plan: Building on the Framework Pursuant 

to AB32: The California Global Warming Solutions Act of 2006, 

which outlines ongoing evaluations that it will conduct to 

determine the impacts of its programs (throughout the 

implementation stages) on overburdened communities.1377 CARB’s 

Adaptive Management Plan for the Cap-and-Trade Program is one 

particular evaluation, which is intended to assess any localized 

emissions increases resulting from the program so that the state 

can appropriately respond.1378 The EPA recommends that states 

consider CARB’s approaches and other programs as models for 

conducting ongoing assessments of the impacts of their state 

plans on overburdened communities. The EPA will provide training 

for states and communities on resources that they can use to 

 

1377 First Update on the Climate Change Scoping Plan: Building on 

the Framework Pursuant to AB32: The California Global Warming 

Solutions Act of 2006. 

http://www.arb.ca.gov/cc/scopingplan/2013_update/first_update_cl

imate_change_scoping_plan.pdf. May 2014. 

1378 Adaptive Management Plan for the Cap-and-Trade Regulation. 

http://www.arb.ca.gov/cc/capandtrade/adaptive_management/plan.pd

f. October 2011. 
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assess options for plan development and implementation that 

appropriately consider localized impacts, especially effects of 

co-pollutants, as well as training on how to develop and carry 

out these evaluations. 

This training will include guidance in accessing the 

publicly available information that sources and states currently 

report that can help with ongoing assessments of state plan 

impacts. For example, unit-specific emissions data and air 

quality monitoring data are readily available. This information, 

together with the assessment that the EPA will conduct in the 

implementation phase of this rulemaking and other analyses that 

states may develop, will enable states and communities to 

monitor any disproportionate emissions that may result in 

adverse impacts and to address them. 

C.G. EPA Continued Engagement 

The EPA is committed to helping ensure that this action 

will not have potential disproportionately high 

anddisproportionate adverse human health or environmental 

effects on vulnerable communities. Throughout the implementation 

processphase of this rulemaking, the agency will continue to 

provide trainings and resources to assist affected communities 

and states as they engage with one another. In addition, the 

agencyAdditionally, we will provide states with recommendations 
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on best practices for engaging with vulnerable communities. The 

EPA, through its outreach efforts during the implementation

phase of this rulemaking, , will continue to solicit feedback 

from affected communities and states on topics for which they 

would like additional trainings and resources. 

Additionally, theThe EPA will also provide states with 

resources containing examples of analyses that other states have 

conducted to examine the impacts of their programs on 

communities.vulnerable communities, as well as information on 

its publicly available environmental justice screening and 

mapping tool, EJ SCREEN. States can are encouraged to use this 

preliminary information as well as other available information 

to conduct their own analyses. As described above, the EPA will 

assess the impacts of their own if they so choose. this 

rulemaking during its implementation. The EPA will house this 

assessment, along with the proximity analysis and other 

information generated throughout the implementation process, on 

its Clean Power Plan (CPP) Community Portal that will be linked 

to this rulemaking’s website (www.epa.gov/cleanpowerplan). In 

addition, the EPA has expanded its set of resources that are 

being developed to help states and communities understand the 

breadth of policy options and programs that have successfully 

brought EE/RE to overburdened communities. The EPA is committed 
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to continuing its engagement with states and communities from 

the beginning of plan development through plan implementation.

A more detailed discussion concerning the application of 

Executive Order 12898 in this rulemaking can be found in section 

XI.J of this preamble. A summary of the EPA’s interactions with 

communities is in the EJ Screening Report for the Clean Power 

Plan, available in the docket of this rulemaking. Furthermore, 

the EPA’s responses to public comments, including comments 

received from communities, are provided in the response to 

comments documents located in the docket for this rulemaking. 

B. Summary of Changes Made 

As described above, the EPA made several changes in this 

Final rule that reflect comments from communities and other 

stakeholders. In response to such input, the EPA has conducted a 

proximity analysis for this rulemaking and provided the report 

in the docket. Additionally, the EPA has added a number of 

provisions in the state plan section that address community 

engagement and involvement throughout the implementation 

process. The EPA will continue outreach efforts and will 

continue to reach out to affected communities on topics that 

they are interested in learning more about. 

 In summary, the EPA in this final rulemaking has designed 

an integrative approach that helps to ensure that vulnerable 
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communities are not disproportionately impacted by this 

rulemaking. The proximity analysis that the agency has conducted 

for this rulemaking is a central component of this approach. Not 

only is the proximity analysis a useful tool to help identify 

overburdened communities that may be impacted by this 

rulemaking, states can use this tool as they engage with 

communities in the development of their plans, consider a multipollutant approach, help low-income communities access EE/RE and 

financial assistance programs and assess the impacts of their 

state plans. Additionally, in order to continue to ensure that 

vulnerable communities are not disproportionately impacted by 

this rulemaking, the EPA will also be conducting its own 

assessment during the implementation phase. Furthermore, the EPA 

will continue to engage with communities and states throughout 

the implementation phase of this rulemaking to help ensure that 

vulnerable communities are not disproportionately impacted. 

X. Interactions with Other EPA Programs and Rules 

 

A. Implications for the New Source Review Program 

The new source review (NSR) program is a preconstruction 

permitting program that requires major stationary sources of air 

pollution to obtain permits prior to beginning construction. The 

requirements of the NSR program apply both to new construction 

and to modifications of existing major sources. Generally, a 
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source triggers these permitting requirements as a result of a 

modification when it undertakes a physical or operational change 

that results in a significant emission increase and a net 

emissions increase. NSR regulations define what constitutes a 

significant net emissions increase, and the concept is 

pollutant-specific. For As a result of the decision in Utility 

Air Regulatory Group (UARG) v. Environmental Protection Agency 

(EPA), 134 S. Ct. 2427 (2014), a modification that increases 

only GHG emissions, the prevention of significant deterioration 

(PSD) applicability analysis is described in above the 

Prevention of Significant Deterioration and Title V Greenhouse 

Gas Tailoring Rule (FR 75 31514, June 3, 2010). As a general 

matterapplicable level will not trigger the requirement to 

obtain a PSD permit. Under existing EPA regulations, a modifying 

major stationary source would trigger PSD permitting 

requirements for GHGs if it emits GHGs in excess of 100,000 tons 

per year of carbon dioxide equivalents (CO2e), and it undergoes a 

change or change in the method of operation (modification) 

resulting that results in a significant increase in anthe 

emissions of a pollutant other than GHGs and results in a GHG

emissions increase of 75,000 tons per year CO2e as well as ana 

GHG emissions increase on a mass basis. Once it has been 

determined that a change triggers the requirements of the NSR 
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program, the source must obtain a permit prior to making the 

change. The pollutant(s) at issue and the air quality 

designation of the area where the facility is located or 

proposed to be built determine the specific permitting 

requirements. 

As part of its CAA section 111(d) plan, a state may impose 

requirements that require an affected EGU to undertake a 

physical or operational change to improve the unit’s efficiency 

that results in an increase in the unit’s dispatch and an 

increase in the unit’s annual emissions. If the emissions 

increase associated with the unit’s changes exceeds the 

thresholds in the NSR regulations discussed above for one or 

more regulated NSR pollutants, including the netting analysis, 

the changes would trigger NSR.

While there may be instances in which an NSR permit would 

be required, we expect those situations to be few. As previously 

discussed in this preamble, states have considerable flexibility 

in selecting varied measures as they develop their plans to meet 

the goals of the emissionsemission guidelines. One of these 

flexibilities is the ability of the state to establish 

theemission standards of performance in their CAA section 111(d) 

plans in such a way so that their affected sources, in complying 

with those standards, in fact would not have emissions increases 
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that trigger NSR. To achieve this, the state would need to 

conduct an analysis consistent with the NSR regulatory 

requirements that supports its determination that as long as 

affected sources comply with the emission standards of 

performance in their CAA section 111(d) plan, the source’s 

emissions would not increase in a way that trigger NSR 

requirements. 

For example, a state could decide to adjust itsuse demandside measures or increase reliance on renewable energy as a way 

of reducing the future emissions of an affected source initially 

predicted (without such alterations) to increase its emissions 

as a result of a CAA section 111(d) plan requirement. In other 

words, a state plan’s incorporation of expanded use of cleaner 

generation or demand-side measures could yield the result that 

units that would otherwise be projected to trigger NSR through a 

physical change that might result in increased dispatch would 

not, in fact, increase their emissions, due to reduced demand 

for their operation. The state could also, as part of its CAA 

section 111(d) plan, develop conditions for a source expected to 

trigger NSR that would limit the unit’s ability to move up in 

the dispatch enough to result in a significant net emissions 
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increase that would trigger NSR (effectively establishing a 

synthetic minor limit). 1379

In addition, in this final rule, we have also adjusted the 

date of the period for mandatory reductions to 2022, instead of 

2020, and provided states with flexibility with respect to the 

glide path. This obviates concerns that there is insufficient 

time for sources that may need permits to obtain them and allows 

additional planning time for these changes to be undertaken in a 

manner that does not trigger PSD. As a result of such 

flexibility and anticipated state involvement, we expect that a 

limited number of affected sources would trigger NSR when states 

implement their plans. 

B. Implications for the Title V Program 

In the preamble to the June 18, 2014 proposal, the EPA 

discussed the issue of excessive title V fees resulting 

inadvertently as a consequence of the promulgation of the first 

 

1379 Certain stationary sources that emit or have the potential to 

emit a pollutant at a level that is equal to or greater than 

specified thresholds are subject to major source requirements. 

See, e.g., CAA sections 165(a)(1), 169(1), 501(2), 502(a). A 

synthetic minor limitation is a legally and practicably 

enforceable restriction that has the effect of limiting 

emissions below the relevant level and that a source voluntarily 

obtains to avoid major stationary source requirements, such as 

the PSD or titleTitle V permitting programs. See, e.g., 40 CFR 

52.21(b)(4), 51.166(b)(4), 70.2 (definition of “potential to 

emit”). 
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section 111 standard to regulate GHGs. Specifically, the EPA 

explained that when the first section 111 standard is 

promulgated for GHGs, if we do not revise 40 CFR parts 70 and 71 

(the operating permit rule), then certain permitting authorities 

would be required to charge emissions-based fees for GHGs, 

resulting in fees that would be far in excess of what is 

required to cover the reasonable costs of the permitting 

programs. To avoid this situation, the EPA proposed as part of 

the re-proposed carbon pollution standards for newly constructed 

fossil fuel-fired power plants (70 FR 1429-1519; January 8, 

2014) to exempt GHGs from the list of air pollutants that are 

subject to fee calculation requirements under the operating 

permit rules. Also, we proposed several options to impose a 

smaller fee adjustment for GHGs that would be reasonable and 

designed to recover the costs of addressing GHGs in permitting 

without being excessive. 

In a separate action in today’s Federal Register [INSERT 

THE FEDERAL REGISTER REFERENCE FOR THE FINAL GHG NEW SOURCE 

RULE], the EPA is finalizing changes to the operating permits 

rules to address the title V fee issue. In particular, we are 

taking final action to exempt GHGs from emissions-based fee 

calculation requirements under the operating permit rules. In 

addition, we are also finalizing a modest GHG fee adjustment to 
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recover the costs of addressing GHGs in permitting. The GHG 

adjustments we are finalizing are based on accounting for the 

number of permit actions that require a GHG assessment in a 

given period, rather than accounting for emissions levels of 

GHGs. Finally, the EPA is also finalizing the addition of text 

within 40 CFR part 60, subpart TTTT, to clarify that the fee 

pollutant for operating permit purposes is GHG (as defined in 40 

CFR 70.2 and 71.2) to add clarity to our regulations and to 

avoid the potential need for possible future rulemakings to 

adjust the title V fee regulations if any constituent of GHG, 

other than CO2, becomes subject to regulation under CAA section 

111 for the first time. 

This title V fee issue is a one-time occurrence resulting 

from the promulgation of the first CAA section 111 standard to 

regulate GHGs (the standards of performance for new, modified, 

and reconstructed EGUs, also promulgated in today’s Federal 

Register). The title V fee issue is not an issue for any other 

subsequent CAA section 111 regulations, such as this section 

111(d) standard; thus, there is no need to address any title V 

fee issues in this final rule as part of this action. 

In the proposal, the EPA discussed that the section 111 

rules would have no effect on the applicability thresholds for 

GHG under the operating permit rules. After the proposal for 
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this rulemaking was published, the United States Supreme Court 

issued its opinion in UARG v EPA, 134 S.Ct. 2427 (June 23, 

2014), and in accordance with that decision, the D.C. Circuit 

subsequently issued an amended judgment in Coalition for 

Responsible Regulation, Inc. v. Environmental Protection Agency, 

Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir., April 10, 

2015). Those decisions support the same overall conclusion, as 

the EPA discussed in the proposal, with respect to the effect of 

this final section 111 rule on the applicability thresholds for 

GHGs under the operating permits rules, though for different 

reasons. 

With respect to title V, the Supreme Court said that EPA 

may not treat GHGs as an air pollutant for purposes of 

determining whether a source is a major source required to 

obtain a title V operating permit. In accordance with that 

decision, the D.C. Circuit’s amended judgment vacated the title 

V regulations under review in that case to the extent that they 

require a stationary source to obtain a title V permit solely 

because the source emits or has the potential to emit GHGs above 

the applicable major source thresholds. The D.C. Circuit also 

directed the EPA to consider whether any further revisions to 

its regulations are appropriate in light of UARG v. EPA, and, if 

so, to undertake to make such revisions. These court decisions 
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make clear that promulgation of CAA section 111 requirements for 

GHGs will not result in EPA imposing a requirement that 

stationary sources obtain a title V permit solely because such 

sources emit or have the potential to emit GHGs above the 

applicable major source thresholds. 

C. Interactions with Other EPA Rules

Fossil fuel-fired EGUs are, or potentially will be, 

impacted by several other recently finalized or proposed EPA 

rules.1380 The EPA recognizes the importance of assuring that each 

of the rules described below can achieve its intended 

environmental objectives in a commonsense, cost-effective 

manner, consistent with underlying statutory requirements, and 

while assuring a reliable power system. Executive Order 13563, 

“Improving Regulation and Regulatory Review,” issued on January 

18, 2011, states that “[i]n developing regulatory actions and 

identifying appropriate approaches, each agency shall attempt to 

promote... coordination, simplification, and harmonization. Each 

agency shall also seek to identify, as appropriate, means to 

achieve regulatory goals that are designed to promote 

innovation.” Within the EPA, we are paying careful attention to 

 

1380 We discuss other rulemakings solely for background purposes. 

The effort to coordinate rulemakings is not a defense to a 

violation of the CAA. Sources cannot defer compliance with 

existing requirements because of other upcoming regulations. 
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the interrelatedness and potential impacts on the industry, 

reliability and cost that these various rulemakings can have. 

1. Mercury and Air Toxics Standards (MATS) 

On February 16, 2012, the EPA issued the MATS rule (77 FR 

9304) to reduce emissions of toxic air pollutants from new and 

existing coal- and oil-fired EGUs. The MATS rule will reduce 

emissions of heavy metals, including mercury, arsenic, chromium, 

and nickel; and acid gases, including hydrochloric acid and 

hydrofluoric acid. These toxic air pollutants, also known as 

hazardous air pollutants or air toxics, are known to cause, or 

suspected of causing, damage nervous system damage, cancer, and 

other serious health effects. The MATS rule will also reduce SO2

and fine particle pollution, which will reduce particle 

concentrations in the air and prevent thousands of premature 

deaths and tens of thousands of heart attacks, bronchitis cases 

and asthma episodes. 

New or reconstructed EGUs (i.e., sources that commence 

construction or reconstruction after May 3, 2011) subject to the 

MATS rule are required to comply by April 16, 2012 or upon 

startup, whichever is later. 

Existing sources subject to the MATS rule were required to 

begin meeting the rule’s requirements on April 16, 2015. 

Controls that will achieve the MATS performance standards are 
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being installed on many units. Certain units, especially those 

that operate infrequently, may be considered not worth investing 

in given today’s electricity market, and are closing. The final 

MATS rule provided a foundation on which states and other 

permitting authorities could rely in granting an additional, 

fourth year for compliance provided for by the CAA. States 

report that these fourth year extensions are being granted. In 

addition, the EPA issued an enforcement policy that provides a 

clear pathway for reliability-critical units to receive an 

administrative order that includes a compliance schedule of up 

to an additional year, if it is needed to ensure electricity 

reliability. 

2. Cross-State Air Pollution Rule (CSAPR) 

The CSAPR requires states to take action to improve air 

quality by reducing SO2 and NOX emissions that cross state lines. 

These pollutants react in the atmosphere to form fine particles 

and ground-level ozone and are transported long distances, 

making it difficult for other states to attain and maintain the 

NAAQS. The first phase of CSAPR became effective on January 1, 

2015, for SO2 and annual NOX, and May 1, 2015, for ozone season 

NOX. The second phase will become effective on January 1, 2017, 

for SO2 and annual NOx, and May 1, 2017, for ozone season NOx. 

Many of the power plants participating in CSAPR have taken 
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actions to reduce hazardous air pollutants for MATS compliance 

that will also reduce SO2 and/or NOx. In this way these two rules 

are complementary. Compliance with one helps facilities comply 

with the other. 

3. Requirements for Cooling Water Intake Structures at Power 

Plants (316(b) Rule)

On May 19, 2014, the EPA issued a final rule under section 

316(b) of the Clean Water Act (CWA) (33 U.S.C. section 1326(b))

(referred to hereinafter as the 316(b) rule.) The rule was 

published on August 15, 2014 (79 FR 48300; August 15, 2014), and 

became effective October 14, 2014. The 316(b) rule establishes 

new standards to reduce injury and death of fish and other 

aquatic life caused by cooling water intake structures at 

existing power plants and manufacturing facilities.1381 The 316(b) 

rule subjects existing power plants and manufacturing facilities 

that withdraw in excess of 2 million gallons per day) of cooling 

water, and use at least 25 percent of that water for cooling 

purposes, to a national standard designed to reduce the number 

of fish destroyed through impingement and a national standard 

 

1381 CWA section 316(b) provides that standards applicable to 

point sources under sections 301 and 306 of the Act must require 

that the location, design, construction and capacity of cooling 

water intake structures reflect the best technology available 

for minimizing adverse environmental impacts. 
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for establishing entrainment reduction requirements. All 

facilities subject to the rule must submit information on their 

operations for use by the permit authority in determining 316(b) 

permit conditions. Certain plants that withdraw very large 

volumes of water will also be required to conduct additional 

studies for use by the permit authority in determining the sitespecific entrainment reduction measures for such facilities. The 

rule provides significant flexibility for compliance with the 

impingement standards and, as a result, is not projected to 

impose a substantial cost burden on affected facilities. With 

respect to entrainment, the rule calls upon the permitting 

authority to establish appropriate entrainment reduction 

measures, taking into account, among other factors, remaining 

useful plant life and quantified and qualitative social benefits 

and cost. The permit writer may also consider impacts on the 

reliability of energy delivery within the facility’s immediate 

area. Existing sources subject to the 316(b) rule are required 

to comply with the impingement requirements as soon as 

practicable after the entrainment requirements are determined. 

They must comply with applicable site-specific entrainment 

reduction controls based on the schedule of requirements 

established by the permitting authority. 
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4. Disposal of Coal Combustion Residuals from Electric Utilities 

(CCR Rule) 

On December 19, 2014, the EPA issued the final rule for the 

disposal of coal combustion residuals from electric utilities. 

The rule provides a comprehensive set of requirements for the 

safe disposal of coal combustion residuals (CCRs), commonly 

known as coal ash, from coal-fired power plants. The CCR rule is 

the culmination of extensive study on the effects of coal ash on 

the environment and public health. The CCR rule establishes 

technical requirements for existing and new CCR landfills and 

surface impoundments under Subtitle D of the Resource 

Conservation and Recovery Act, the nation's primary law for 

regulating solid waste. 

These regulations address the risks from coal ash disposal 

-- leaking of contaminants into ground water, blowing of 

contaminants into the air as dust, and the catastrophic failure 

of coal ash surface impoundments by establishing requirements 

for where CCR landfills and surface impoundments may be located, 

how they must be designed, operated and monitored, when they 

must be inspected, and how they must be closed and cared for 

after closure. Additionally, the CCR rule sets out recordkeeping 

and reporting requirements, as well as the requirement for each 

facility to establish and post specific information to a 
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publicly-accessible website. The final rule also supports the 

responsible recycling of CCRs by distinguishing safe, beneficial 

use from disposal. 

5. Steam Electric Effluent Limitation Guidelines and Standards 

(SE ELG Rule) 

The EPA is reviewing public comments and working to 

finalize the proposed SE ELG rule which will impact existing 

fossil fuel-fired EGUs. In 2013, the EPA proposed the SE ELG 

rule (78 FR 34432; June 7, 2013) to strengthen the controls on 

discharges from certain steam electric power plants by revising 

technology-based effluent limitations guidelines and standards 

for the steam electric power generating point source category. 

The current regulations, which were last updated in 1982, do not 

adequately address the toxic pollutants discharged from the 

electric power industry, nor have they kept pace with process 

changes that have occurred over the last three decades. Existing 

steam electric power plants currently contribute 50-60 percent 

of all toxic pollutants discharged to surface waters by all 

industrial categories regulated in the United States under the 

CWA. Furthermore, power plant discharges to surface waters are 

expected to increase as pollutants are increasingly captured by 

air pollution controls and transferred to wastewater discharges. 

The proposed regulation, which includes new requirements for 
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both existing and new generating units, would reduce impacts to 

human health and the environment by reducing the amount of toxic 

metals and other pollutants currently discharged to surface 

waters from power plants. The EPA intends to take final action 

on the proposed rule by September 30, 2015. 

The EPA is endeavoring to enable EGUs to comply with 

applicable obligations under other power sector rules as 

efficiently as possible (e.g., by facilitating their ability to 

coordinate planning and investment decisions with respect to 

those rules) and, where possible, implement integrated 

compliance strategies. For example, in the proposed SE ELG rule, 

the EPA describes its thinking on how it might effectively 

harmonize the potential requirements of that rule with the 

requirements of the final CCR rule. Because these two rules 

affect similar units and may be met with similar compliance 

strategies, common-sense implementation timeframes were 

established in the CCR final rule so that utilities would not be 

required to make major decisions about CCR units without first 

understanding the implications that such decisions would have 

for meeting the surface water protection requirements of the 

final ELG rule. The EPA is taking into account these new CCR 

requirements for coal ash as it develops the final SE ELG rule. 

The EPA's goal in harmonizing the SE ELG and CCR rules is to 
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minimize the overall complexity of the two regulatory structures 

and avoid creating unnecessary burden. 

6. Other EPA Rules 

In addition to the power sector rules discussed above, the 

development of SIPs for criteria pollutants (ozone, PM2.5, and 

SO2) and regional haze may also have implications for existing 

fossil-fired EGUs. 

Regarding ozone, the proposal included a discussion of the 

June 6, 2013, proposed implementation rule for the 2008 ozone 

National Ambient Air Quality Standards (NAAQS), addressing the 

statutory requirements for areas EPA has designated as 

nonattainment for the 2008 ozone NAAQS. The final implementation 

rule for the 2008 ozone NAAQS was signed on February 13, 2015, 

and published on March 6, 2015, with an effective date of April 

6, 2015. In general, the 2008 ozone NAAQS implementation rule 

interprets applicable statutory requirements and provides 

flexibility to states to minimize administrative burdens 

associated with developing and implementing plans to meet and 

maintain the NAAQS. The rule establishes due dates for 

attainment plans and clarifies attainment dates for each ozone 

nonattainment area according to its classification based on air 

quality thresholds, with attainment dates starting in July 2015 

through July 2032 depending on an area’s classification. 
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On November 25, 2014, the EPA Administrator signed the 

proposed rulemaking for the 2015 revisions to the ozone NAAQS. 

The proposal was published in the Federal Register on December 

17, 2014 (79 FR 75234). The Administrator proposed to revise the 

primary ozone standard to a level in the range of 0.065 to 0.070 

ppm and took comment on lower levels including 0.060 ppm and on 

retaining the current standard of 0.075 ppm. Among other things, 

the ozone NAAQS proposal also proposed to retain the current 

indicator, averaging time, and form of the standard and included 

a proposed secondary ozone NAAQS in the 0.065 to 0.070 ppm 

range. 

The proposal also outlined the key implementation 

milestones requiring revised state implementation plans, with 

due dates starting in October 2018 for infrastructure and 

interstate transport SIPs, attainment plans due 2020-21, and 

attainment dates of 2020-37. The EPA is under a court order to 

finalize its review of the ozone NAAQS by October 1, 2015. 

 Some commenters expressed concern with the potential 

impact proposed revisions to the ozone NAAQS could have on state 

planning efforts and affected entities’ ability to comply with 

any potentially new requirements associated with a revised ozone 

NAAQS and those related to the 111(d) emissionsemission

guidelines. In particular, commenters raised issues with a 
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potentially more stringent ozone standard and the permitting and 

state planning implications this may create. While there was no 

discussion of the proposed revisions to the ozone NAAQS in the 

111(d) emissionsemission guidelines proposal, commenters 

expressed a desire for the EPA to coordinate promulgation of the 

final 111(d) emissionsemission guidelines (and any other climate 

regulations) with the potential revision to the ozone standard 

to provide certainty and flexibility for states and affected 

sources. 

While it is premature to speculate about the outcome of the 

ozone NAAQS review and how a more stringent ozone NAAQS may 

impact sources of ozone precursor emissions, including EGUs, we 

believe the planning and compliance timeframes that would follow 

from a revised ozone NAAQS and the timeframes we are finalizing 

today for submittal of the CAA section 111(d) state plans will 

allow considerable time for coordination by states in the 

development of their respective plans, as needed. As stated in 

the proposal, the EPA is prepared to work with states to assist 

them in coordinating their efforts across these planning 

processes. 

Regarding PM2.5 NAAQS implementation, the proposal stated 

that the EPA was developing a proposed implementation rule to 

provide guidance to states on the development of SIPs for the 
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2012 PM2.5 NAAQS. The proposed PM2.5 SIP requirements rule was 

signed on March 10, 2015, and published on March 23, 2015 (80 FR 

15340). The proposal addresses a number of requirements 

including attainment plan due dates, attainment dates and 

attainment date extension criteria for Moderate and Serious 

nonattainment areas; determination criteria for Reasonably 

Available Control Measures (RACM) for Moderate areas and Best 

Available Control Measures (BACM) for Serious areas; plans for 

demonstrating reasonable further progress and for meeting 

periodic quantitative milestones; and criteria for reclassifying 

a Moderate nonattainment area to Serious. The EPA is planning to 

finalize the PM2.5 implementation rule in early 2016. 

There are currently only 9 areas designated nonattainment 

for the 2012 PM2.5 NAAQS, with an effective date of April 15, 

2015. Since the attainment plans for these areas must be 

completed and submitted to the EPA in September 2016, we expect 

that the four states with such areas should have already decided 

on their approach to implementing the 2012 PM2.5 NAAQS when they 

begin to develop their plans for implementing the 111(d) 

guidelines, and will be able to coordinate the two. 

Related to the SO2 NAAQS, and as stated in the proposal, the 

SO2 NAAQS was revised in June 2010 to protect public health from 

the short-term effects of SO2 exposure. In July 2013, the EPA 
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designated 29 areas in 16 states as nonattainment for the SO2

NAAQS. The EPA based these nonattainment designations on the 

most recent set of certified air quality monitoring data as well 

as an assessment of nearby emission sources and weather patterns 

that contribute to the monitored levels. The date for attainment 

plans for these areas to be completed and submitted to the EPA 

was April 2015. As such, we expect states with such areas to 

have already decided on their approach to implementing the SO2

NAAQS as they start planning for implementation of the 111(d) 

guidelines, which should allow for coordination and 

consideration of SO2 related air quality measures into their 

111(d) planning. The EPA intends to address the designations for 

all other areas in three separate actions in the future.1382 These 

designations must be completed by no later than July 2, 2016, 

December 31, 2017, and December 31, 2020 with attainment plans 

due between 2018 and 2022. 

 

1382 The EPA has developed a comprehensive implementation strategy 

for these future actions that focuses resources on identifying 

and addressing unhealthy levels of SO2 in areas where people are 

most likely to be exposed to violations of the standard. The 

strategy is available at 

http://www.epa.gov/airquality/sulfurdioxide/implement.html, and 

the associated area designations schedule is at 

http://www.epa.gov/airquality/sulfurdioxide/designations/pdfs/20

1503Schedule.pdf. 
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Regarding requirements under the regional haze program, 

several affected EGUs have deadlines in the 2016-2021 timeframe 

to install controls to comply with the Best Available Retrofit 

Technology (BART) and reasonable progress requirements of the 

Regional Haze Rule. Soon after these deadlines, some of the same 

affected EGUs may be required to reduce their utilization, 

convert into natural gas-fired facilities, or shut down entirely 

as a result of state 111(d) plans. Some commenters have 

expressed concern that for these affected EGUs, specifically 

those that choose to retire, the capital equipment installed to 

comply with the Regional Haze Rule would likely become stranded 

assets. 

While the EPA is providing considerable flexibility for 

states and sources under the final 111(d) emissionsemission

guidelines, the EPA acknowledges the possibility that some 

sources could ultimately be faced with the potential for 

stranded assets as a result of state 111(d) plans. For these 

sources, however, states have the option of developing BART 

alternatives that replace control requirements that would 

otherwise result in stranded assets at a particular EGU with the 

aggregate emission reductions that will result from retirements, 

fuel switching, reduced utilization, or lesser controls at 

multiple EGUs. 
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In fact, the EPA already has experience working with states 

to account for these very types of changed circumstances.1383 The 

EPA will continue to work with states to explore options for 

integrating compliance requirements across multiple regulatory 

programs, as warranted. 

The EPA believes that CAA section 111(d) efforts and 

actions will tend to contribute to overall air quality 

improvements and thus should be complementary to criteria 

pollutant and regional haze SIP efforts. 

7. Final Rule Flexibilities 

As discussed in Section VIII of this preamble, the EPA is 

providing states flexibility in developing approvable plans 

under CAA section 111(d), including the ability to impose 

source-by-source limitations reflecting the BSER performance 

 

1383 For example, Oregon replaced its BART determination for the 

Boardman Coal Plant with a new requirement that accounted for a 

planned shutdown before the EPA took action on the state’s SIP 

submission (76 FR 12661). Washington similarly replaced its BART 

determination for the TransAlta Centralia Power Plant before the 

EPA took action on the state’s SIP submission (77 FR 72742). 

Oklahoma submitted a SIP revision with a new BART determination 

for the AEP/PSO Northeastern Power Station, which included 

enforceable requirements for reduced utilization and early unit 

retirements, to replace a FIP that had been promulgated by the 

EPA (79 FR 12944). Finally, the EPA finalized a BART 

determination for Unit 3 at the Dave Johnston Power Plant in 

Wyoming that included two compliance options, one of which 

included a federally enforceable retirement date and less costly 

controls.
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rates to each affected EGU or to adopt rate-based or mass-based 

emission performance goals, and to rely on a wide range of CO2

emission reduction measures, including measures that are not 

part of the BSER. The EPA is also providing states considerable 

flexibility with respect to the timeframes for plan development 

and implementation, with up to 3 years permitted for final plans 

to be submitted after the GHG emission guidelines are finalized, 

and up to 15 years for all emission reduction measures to be 

fully implemented. The EPA is establishing an 8-year interim 

period over which to achieve the full required reductions to 

meet the CO2 performance rates, and this begins in 2022, more 

than seven years from the June 18, 2014 date of proposal of the 

rulemaking. The 8-year interim period from 2022 through 2029, is 

separated into three steps, 2022-2024, 2025-2027, and 2028-2029, 

each associated with its own interim CO2 emission performance 

rates. 

In light of these broad flexibilities, we believe that 

states will have ample opportunity, when developing and 

implementing their CAA section 111(d) plans, to coordinate their 

response to this requirement with source and state responses to 

any obligations that may be applicable to affected EGUs as a 

result of the MATS, CSAPR, 316(b), SE ELG and CCR rules, all of 

which are or soon will be final rules. In addition, we believe 
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that states will be able to design CAA section 111(d) plans that 

use innovative, cost-effective regulatory strategies, that spark 

investment and innovation across a wide variety of clean energy 

technologies, and that will help reduce cost and ensure 

reliability, while also ensuring that all applicable 

environmental requirements are met.1384 We also believe that the 

broad flexibilities in this action will enable states and 

affected EGUs to build on their longstanding, successful records 

of complying with multiple CAA, CWA, and other environmental 

requirements, while assuring an adequate, affordable, and 

reliable supply of electricity. 

XI. Impacts of the Final Action1385 

A. What are the air impacts?

 

1384 It should be noted that regulatory obligations imposed upon 

states and sources operate independently under different 

statutes and sections of statutes; the EPA expects that states 

and sources will take advantage of available flexibilities as 

appropriate, but will comply with all relevant legal 

requirements. 

1385 The impacts presented in this section of the preamble 

represent an illustrative implementation of the guidelines. As 

states implement the final guidelines, they have sufficient 

flexibility to adopt different state-level or regional 

approaches that may yield different costs, benefits, and 

environmental impacts. For example, states may use the 

flexibilities described in these guidelines to find approaches 

that are more cost -effective for their particular state or 

choose approaches that shift the balance of co-benefits and 

impacts to match broader state priorities. 
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The EPA anticipates significant emission reductions under 

the final guidelines for the utility power sector. When compared 

to 2005, CO2 emissions are projected to be reduced by 

approximately [X] percent in 2020, [X] percent in 2025, and [X] 

percent in 2030. The final guidelines are projected to result in 

substantial co-benefits through reductions of SO2, PM2.5 and NOX

that will have direct public health benefits by lowering ambient 

levels of these pollutants and ozone. Table 11 shows expected CO2 

and other air pollutant emissions in the base case and 

reductions under the final guidelines for 2020, 2025, and 

2030.In the final emission guidelines, the EPA has translated 

the source category-specific CO2 emission performance rates into 

equivalent state-level rate-based and mass-based CO2 goals in 

order to maximize the range of choices that states will have in 

developing their plans. Because of the range of choices 

available to states and the lack of a priori knowledge about the 

specific choices states will make in response to the final 

goals, the Regulatory Impact Analysis (RIA) for this final 

action presents two scenarios designed to achieve these goals, 
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which we term the “rate-based” illustrative plan approach and 

the “mass-based” illustrative plan approach.1386

Under the rate-based approach, when compared to 2005, CO2

emissions are projected to be reduced by approximately 22 

percent in 2020, 28 percent in 2025, and 32 percent in 2030. 

Under the mass-based approach, when compared to 2005, CO2

emissions are projected to be reduced by approximately 23 

percent in 2020, 29 percent in 2025, and 32 percent in 2030. The 

final guidelines are projected to result in substantial cobenefits through reductions of SO2, NOX and PM2.5 that will have 

direct public health benefits by lowering ambient levels of 

these pollutants and ozone. Tables 15 and 16 show expected CO2 

and other air pollutant emissions in the base case and 

reductions under the final guidelines for 2020, 2025, and 2030 

for the rate-based and mass-based approaches, respectively. 

 

1386 It is important to note that the differences between the 

analytical results for the rate-based and mass-based 

illustrative plan approaches presented in the RIA may not be 

indicative of likely differences between the approaches if 

implemented by states and affected EGUs in response to the final 

guidelines. If one approach performs differently than the other 

on a given metric during a given time period, this does not 

imply this will apply in all instances.
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Table 1115. Summary of CO2 and Other Air Pollutant Emission 

Reductions under Final Guidelinesfrom the Base Case under Ratebased Illustrative Plan Approach

 

CO2 (million 

metric 

(millions 

short tons) 

SO2

(thousands 

of 

(thousand 

short tons) 

NOX

(thousands 

of

(thousand 

 short tons) 

P

M

2

.

5 

(

t

h

o

u

s

a

n

d

s

o

f

t

o

n

s

)

2020 Final Guidelines 

Base Case [X]2,155 [X]1,311 [X]1,333

[

X

]

Final Guidelines [X]2,085 [X]1,297 [X]1,282

[

X

]

Emissions Reductions [X]69 [X]14 [X]50

[

X

]

2025 Final Guidelines 

Base Case [X]2,165 [X]1,275 [X]1,302

[

X

]

Final Guidelines [X]1,933 [X]1,097 [X]1,138

[

X

]

Emissions Reductions [X]232 [X]178 [X]165

[

X

]

Deleted Cells

Deleted Cells

Deleted Cells
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2030 Final Guidelines 

Base Case [X]2,227 [X]1,314 [X]1,293

[

X

]

Final Guidelines [X]1,812 [X]996 [X]1,011

[

X

]

Emissions Reductions [X]415 [X]318 [X]282

[

X

]

Source: Integrated Planning Model, 2015. 

Note: Emissions may not sum due to rounding. 

Table 16. Summary of CO2 and Other Air Pollutant Emission 

Reductions from the Base Case under Mass-based Illustrative Plan 

Approach 

 

CO2

(million 

short tons) 

SO2

(thousand 

short tons) 

NOX 

(thousand 

short tons) 

2020 Final Guidelines 

Base Case 2,155 1,311 1,333 

Final Guidelines 2,073 1,257 1,272 

Emissions Reductions 81 54 60 

2025 Final Guidelines 

Base Case 2,165 1,275 1,302 

Final Guidelines 1,901 1,090 1,100 

Emissions Reductions 265 185 203 

2030 Final Guidelines 

Base Case 2,227 1,314 1,293 

Final Guidelines 1,814 1,034 1,015 

Emissions Reductions 413 280 278 

Source: Integrated Planning Model, 2015. 

Note: Emissions may not sum due to rounding. 

The reductions in Table 11Tables 15 and 16 do not account 

for reductions in hazardous air pollutants (HAPs) that may occur 

as a result of this rule. For instance, the fine particulate 

reductions presented above do not reflect all of the reductions 

in many heavy metal particulates. 

Deleted Cells
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B. Endangered Species Act 

As explained in the preamble to the proposed rule (79 FR at 

34933-934), the EPA has carefully considered the requirements of 

section 7(a)(2) of the Endangered Species Act (ESA) and 

applicable ESA regulations, and reviewed relevant ESA case law 

and guidance, to determine whether consultation with the U.S. 

Fish and Wildlife Service (FWS) and/or National Marine Fisheries 

Service (together, the Services) is required by the ESA. The EPA 

proposed to conclude that the requirements of ESA section 

7(a)(2) would not be triggered by promulgation of the rule, and 

we now finalize that determination in this final rule. 

Section 7(a)(2) of the ESA requires federal agencies, in 

consultation with one or both of the Services (depending on the 

species at issue), to ensure that actions they authorize, fund, 

or carry out are not likely to jeopardize the continued 

existence of federally listed endangered or threatened species 

or result in the destruction or adverse modification of 

designated critical habitat of such species. 16 U.S.C. 

1536(a)(2). Under relevant implementing regulations, section 

7(a)(2) applies only to actions where there is discretionary 

federal involvement or control. 50 CFR 402.03. Further, under 

the regulations consultation is required only for actions that 

“may affect” listed species or designated critical habitat. 50 
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CFR section 402.14. Consultation is not required where the 

action has no effect on such species or habitat. Under this 

standard, it is the federal agency taking the action that 

evaluates the action and determines whether consultation is 

required. See 51 FR 19926, 19949 (June 3, 1986). Effects of an 

action include both the direct and indirect effects that will be 

added to the environmental baseline. 50 CFR 402.02. Direct 

effects are the direct or immediate effects of an action on a 

listed species or its habitat.1387 Indirect effects are those that 

are “caused by the proposed action, and are later in time, 

andbut still are reasonably certain to occur..” Id. To trigger 

athe consultation requirement, there must thus be a causal 

connection between the federal action, the effect in question, 

and the listed species, and if the effect is indirect, it must 

be reasonably certain to occur. 

The EPA notes that the projected environmental effects of 

this rule are positive: reductions in overall GHG emissions, and 

reductions in PM and ozone-precursor emissions (SO2 and NOX). 

However, theThe EPA recognizes that beneficial effects to listed 

 

1387 See Endangered Species Consultation Handbook, U.S. Fish & 

Wildlife Service and National Marine Fisheries Service at 4-25 

(March 1998) (providing examples of direct effects: e.g., 

driving an off road vehicle through the nesting habitat of a 

listed species of bird and destroying a ground nest; building a 

housing unit and destroying the habitat of a listed species). 
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species can, as a general matter, result in a “may affect” 

determination under the ESA. However, the EPA’s assessment that 

the rule will have an overall net positive environmental effect 

by virtue of reducing emissions of certain air pollutants does 

not address whether the rule may affect any listed species or 

designated critical habitat for ESA section 7(a)(2) purposes and 

does not constitute any finding of effects for that purpose. The

fact that the rule will have overall positive effects on the 

national and global environment does not mean that the rule may 

affect any listed species in its habitat or the designated 

critical habitat of such species within the meaning of ESA 

section 7(a)(2) or the implementing regulations or require ESA 

consultation. The EPA has considered various types of potential 

effects in reaching the conclusion that ESA consultation is not 

required for this rule. 

With respect to the projected GHG emission reductions, the 

EPA considered in detail in the proposal why such reductions do 

not trigger ESA consultation requirements under section 7(a)(2). 

As explained in the proposal, in reaching this conclusion the 

EPA was mindful of significant legal and technical analysis 

undertaken by FWS and the U.S. Department of the Interior (DOI) 

in the context of listing the polar bear as a threatened species 

under the ESA. In that context, in 2008, FWS and DOI expressed 
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the view that the best scientific data available were 

insufficient to draw a causal connection between GHG emissions 

and effects on the species in its habitat.1388 The DOI Solicitor 

concluded that where the effect at issue is climate change, 

proposed actions involving GHG emissions cannot pass the “may 

affect” test of the section 7 regulations and thus are not 

subject to ESA consultation. 

TheAs described in the proposal, the EPA has also 

previously considered issues relating to GHG emissions in 

connection with the requirements of ESA section 7(a)(2).) and 

has supplemented DOI’s analysis with additional consideration of 

GHG modeling tools and data regarding listed species. Although 

the GHG emission reductions projected for this final rule are 

large (estimated reductions of [X]about 415 million metricshort

tons of CO2 in 2030 relative to the base case under the ratebased illustrative plan approach– see Table 1114 above), the EPA 

evaluated larger reductions in assessing this same issue in the 

context of the light duty vehicle GHG emission standards for 

 

1388 See, e.g., 73 FR 28212, 28300 (May 15, 2008); Memorandum from 

David Longly Bernhardt, Solicitor, U.S. Department of the 

Interior re: ‘‘Guidance on the Applicability of the Endangered 

Species Act’s Consultation Requirements to Proposed Actions 

Involving the Emission of Greenhouse Gases’’ (Oct. 3, 2008). 
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model years 2012-2016 and 2017-2025. There the agency projected 

emission reductions roughly double and four times those 

projected here over the lifetimes of the model years in 

question1389 which are roughly five to six times those projected 

above and, based on air quality modeling of potential 

environmental effects, concluded that “EPA knows of no modeling 

tool which can link these small, time-attenuated changes in 

global metrics to particular effects on listed species in 

particular areas. Extrapolating from global metric to local 

effect with such small numbers, and accounting for further links 

in a causative chain, remain beyond current modeling 

capabilities.” EPA, Light Duty Vehicle Greenhouse Gas Standards 

and Corporate Average Fuel Economy Standards, Response to 

Comment Document for Joint Rulemaking at 4-102 (Docket EPA-OARHQ-2009-4782). The EPA reached this conclusion after evaluating 

issues relating to potential improvements relevant to both 

temperature and oceanographic pH outputs. The EPA's ultimate 

finding was that “any potential for a specific impact on listed 

species in their habitats associated with these very small 

changes in average global temperature and ocean pH is too remote 

to trigger the threshold for ESA section 7(a)(2).”Id. The EPA 

 

1389 See 75 FR at 25438 Table I.C 2–4 (May 7, 2010); 77 FR at 

62894 Table III–68 (Oct. 15, 2012). 
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believes that the same conclusion applies to the present rule, 

given that the projected CO2 emission reductions are less than 

those projected for either of the light duty vehicle rules. See, 

e.g., Ground Zero Center for Non-Violent Action v. U.S. Dept. of 

Navy, 383 F. 3d 1082, 1091-92 (9th Cir. 2004) (where the 

likelihood of jeopardy to a species from a federal action is 

extremely remote, ESA does not require consultation). The EPA’s 

conclusion is entirely consistent with DOI’s analysis regarding 

ESA requirements in the context of federal actions involving GHG 

emissions.1390

With regard to non-GHG air emissions, the EPA also projects 

substantial reductions of SO2 and NOX as a collateral consequence 

 

1390 The EPA has received correspondence from a U.S. Senator and a 

Member of the U.S. House of Representatives noting that the 

Services have identified several listed species affected by 

global climate change. See Letter from Rob Bishop, Chairman, 

House Committee on Natural Resources, to Gina McCarthy, 

Administrator, U.S. Environmental Protection Agency, dated June 

11, 2015; Letter from Rob Bishop, Chairman, House Committee on 

Natural Resources, and James M. Inhofe, Chairman, Senate 

Committee on Environment and Public Works, to Gina McCarthy, 

Administrator, U.S. Environmental Protection Agency, dated June 

15, 2015. EPA’s assessment of ESA requirements in connection 

with the present rule does not address whether global climate 

change may, as a general matter, be a relevant consideration in 

the status of certain listed species. Rather, the requirements 

of ESA section 7(a)(2) must be considered and applied to the 

specific action at issue. As explained above, EPA’s conclusion 

that ESA section 7(a)(2) consultation is not required here is 

premised on the specific facts and circumstances of the present 

rule and is fully consistent with prior relevant analyses 

conducted by DOI, FWS, and EPA.
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of this final action. However, CAA section 111(d)(1) standards 

cannot directly control emissions of criteria pollutants. See 

CAA section 111(d)(1)(i). Consequently, CAA section 111(d) 

provides no discretion to adjust the standard based on potential 

impacts to endangered species of reduced criteria pollutant 

emissions. Section 7(a)(2) consultation thus is not required 

with respect to the projected reductions of criteria pollutant 

emissions. See 50 CFR 402.03; see also, WildEarth Guardians v. 

U.S. Envt’l Protection Agency, 759 F.3d 1196, 1207-10 (10th Cir. 

2014) (EPA has no duty to consult under section 7(a)(2) of the 

ESA regarding hazardous air pollutant controls that it did not 

require – and likely lacked authority to require – in a federal 

implementation plan for regional haze controls under section 

169A of the CAA); National Lime Ass'n v. EPA, 233 F. 3d 625, 

638-39 (D.C. Cir. 2000) (although CAA section 112(b)(2) 

prohibits the EPA from listing criteria pollutants as hazardous 

air pollutants, the EPA may use PM as a surrogate for metal 

hazardous air pollutants and reductions in PM do not constitute 

impermissible regulation of a criteria pollutant). 

Finally, the EPA has also considered other potential 

effects of the rule (beyond reductions in air pollutants) and 

whether any such effects are sufficiently“caused by” the rule 

and “reasonably certain to call foroccur” within the meaning of 
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the ESA consultationregulatory definition of the effects of an 

action. 50 CFR 402.02. As the EPA noted in the proposal, there 

are substantial questions as to whether any potential for 

relevant effects results from any element of the rule or would 

result instead from separate decisions and actions made in 

connection with the development, implementation, and enforcement 

of a plan to implement the standards established in the rule. 

Cf. American Trucking Assn's v. EPA, 175 F. 3d 1027, 1043-45 

(D.C. Cir. 1999), rev'd on different grounds sub nom., Whitman

v. American Trucking Assn's, 531 U.S. 457 (2000) (National 

Ambient Air Quality Standards have no economic impact, for 

purposes of Regulatory Flexibility Act, because impacts result 

from the actions of states through their development, 

implementation and enforcement of state implementation plans).1391

 

1391 One commenter questioned the EPA’s citation to American 

Trucking Assn's. As stated by the commenter, the statute at 

issue in that case – the Regulatory Flexibility Act (RFA) – is 

distinguishable from the ESA in that it addresses only direct 

effects and does not consider indirect effects. The commenter 

misreads the EPA’s citation to this case. The EPA cites this 

case simply to reference a decision considering the impacts of 

an EPA action – the revision of a National Ambient Air Quality 

Standard (NAAQS) under the Clean Air Act – that in certain 

respects provides a useful analogy to the present rule. A NAAQS 

is implemented through a series of subsequent planning decisions 

generally taken by states by means of adoption of State 

Implementation Plans. States can choose to impose or avoid the 

types of impacts at issue in the D.C. Circuit case through their 

planning decisions; thus such impacts were not viewed as having 
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The EPA recognized, for instance, that questions may exist 

whether decisions such as increased utilization of solar or wind 

power could have effects on listed species. The EPA received 

comments on the proposal asserting that because potential 

increased reliance on wind or solar power may be an element of 

Building Blockbuilding block 3, and because wind and solar 

facilities may in some cases have effects on listed species, the 

EPA must consult under the ESA on this aspect of the rule. The 

EPA is also aware of certain questions posed by a Member of the 

U.S. House of Representatives to FWS regarding potential effects 

 

been caused – for purposes of the RFA – by the EPA’s 

promulgation of the revised NAAQS in the first instance. The 

standard setting and implementation mechanisms under section 

111(d) are very similar. Under section 111(d), the EPA is 

required to establish “a procedure similar to that provided by 

section 7410” – the provision establishing the State 

Implementation Plan mechanism for implementing NAAQS. Thus, the 

D.C. Circuit’s discussion provides a useful analogy to the 

present rule and the various types of potential effects that may 

be attributable to future implementation planning decisions by 

states and other entities as they exercise their discretion in 

determining how to implement the federal guidelines, but not to 

promulgation of the rule itself. The EPA’s citation to this case 

was not intended to address any comparison of the scope of 

effects covered by the RFA and the effects cognizable under 

section 7(a)(2) of the ESA. The EPA is aware that the ESA 

addresses both direct and indirect effects as defined by the 

applicable ESA regulations. The discussion supporting the EPA’s 

ESA conclusion expressly acknowledges the relevance of indirect 

effects to the ESA analysis and explains why such effects are 

not present here.
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of the rule on the Big Bend Power Station located in Florida, 

which discharges effluent that provides a warm water refuge for 

manatees.1392 The Big Bend Power Station and another coal-fired 

facility located in Florida – the Crystal River Plant – are, for 

example, referenced in the June 11, 2015, and June 15, 2015, 

congressional letters to EPA cited above. 

The EPA has carefully considered the comments and the 

correspondence from Congress as well as the case law and other 

materials cited in those documents. The EPA does not believe 

that the effects of potential future changes in the energy 

sector – including increased reliance on wind or solar power as 

a result of future potential actions by states or other 

implementing entities – or any potential alterations in the 

operations of any particular facility are caused by the current 

rule or sufficiently certain to occur so as to require ESA 

consultation on the rule. The EPA appreciates that the ESA 

regulations call for consultation where actions authorized, 

funded, or carried out by federal agencies may have indirect 

effects on listed species or designated critical habitat. 

However, as noted above, indirect effects must be caused by the 

 

1392 See Letter from Rob Bishop, Chairman, Committee on Natural 

Resources, to Dan Ashe, Director, U.S. Fish and Wildlife 

Service, dated April 2, 2015. 
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action at issue and must be reasonably certain to occur. At this 

point, there is no reasonable certainty regarding implementation 

of any planning measures in any location, let alone in any 

location occupied by a listed species or its designated critical 

habitat. The EPA cannot predict with reasonable certainty where 

such measures may take effect or which measures may be adopted. 

It is not clear, for instance, whether a particular 

implementation plan will call, if at all, for increased reliance 

on wind power, as opposed to solar power, or on some other form 

of low or zero carbon emitting generation. It is also entirely 

uncertain how a future implementation plan for a particular 

state might affect, if at all, operations at a specific 

facility.1393 The precise steps included in an implementation plan 

cannot be determined or ordered by this federal action, and they 

are not sufficiently certain to be attributable to this final 

 

1393 A congressional letter of June 11, 2015, referenced above 

asserts that EPA’s modeling suggests that the Big Bend Power 

Station and Crystal River Energy Complex in Florida will be 

prematurely retired as a result of the rule. EPA notes that any 

such facility-level projections associated with the rule cannot 

be stated with sufficient certainty to qualify as potential 

indirect effects under the ESA. These projections are based on 

numerous assumptions regarding a variety of planning and 

business decisions yet to be made by the implementing 

governments (usually states) and facility owners. Given the wide 

degrees of discretion and flexibility and the numerous options 

available for such decision making, the potential for such 

outcomes to be realized as currently projected is at this point 

too uncertain to qualify as an effect under the ESA. 
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rule for ESA purposes. These steps will flow from a series of 

later in time decisions madegenerally made by other entities – 

usually states – in thetheir distinct planning process, which 

processes. These later decisions cannot now be predicted with 

reasonable certainty or required by the rule. The EPA notes that 

many of these decisions will be made by other entities, most 

likely states, are not caused by the rule, and are not 

reasonably certain to occur. The EPA also notes that the plans 

adopted for particular states may themselves provide wide 

degrees of implementation flexibility, thus further increasing 

the uncertainty that any species-impacting activity will occur 

in any particular location, if at all. The Services have 

explained that section 7(a)(2) was not intended to preclude 

federal actions based on potential future speculative effects.1394

 

1394 See 51 FR at 19933 (describing effects that are “reasonably 

certain to occur” in the context of consideration of cumulative 

effects and distinguishing broader consideration that may be 

appropriate in applying a procedural statute such as the 

National Environmental Policy Act, as opposed to a substantive 

provision such as ESA section 7(a)(2) that may prohibit certain 

federal actions); Endangered Species Consultation Handbook, U.S. 

Fish & Wildlife Service and National Marine Fisheries Service at 

4-30 (March 1998) (in the same context, describing indicators 

that an activity is reasonably certain to occur as including 

governmental approvals of the action or indications that such 

approval is imminent, project sponsors’ assurance that the 

action will proceed, obligation of venture capital, or 

initiation of contracts; and noting that the more governmental 
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These are precisely the types of speculative future activities 

and effects at issue here.1395 For this additional reason, the EPA 

concludes that the rule does not have effects on listed species 

that trigger the section 7(a)(2) consultation requirement.1396

 

administrative discretion remains to be exercised, the less 

there is reasonable certainty the action will proceed).

1395 EPA also notes that some of the future implementing 

activities themselves may requiremay involve federal actions 

that are subject to ESA consultation, thus providing 

consideration of any impacts on listed species at the 

appropriate point when particular activities have become 

reasonably certain. Several commenters on the proposal 

specifically noted that such future activities – e.g., 

development of additional renewable energy facilities such as 

wind farms – may call for ESA consultation. Further, EPA notes 

that section 9 of the ESA, which prohibits the take of 

individuals of most listed species, provides an additional 

protection for listed species as future implementing activities 

become reasonably certain.

1396 The commenters cite certain cases that they assert support 

consulting under ESA section 7(a)(2). The EPA has considered 

these cases, each of which is distinguishable from the present 

rule. By way of example, a commenter cites two cases involving 

EPA actions: Defenders of Wildlife v. EPA, 420 F.3d 946 (9th Cir. 

2005), rev’d, National Association of Homebuilders v. Defenders 

of Wildlife, 551 U.S. 644 (2007); and Washington Toxics 

Coalition v. EPA, 413 F.3d 1024 (9th Cir. 2005). In Defenders of 

Wildlife (a decision that was reversed by the U.S. Supreme 

Court), a principal relevant impact of the federal action at 

issue – the EPA’s approval of a state’s permitting program under 

the Clean Water Act – was that following the action, the 

relevant permitted activities would no longer be subject to 

consultation under the ESA. By contrast, promulgation of the 

present rule will result in no change to any ESA requirements 

applicable to any future activities directed by plans (either 

state or federal) implementing the rule. The action at issue in 

Washington Toxics Coalition involved the EPA’s registration of 

certain pesticide active ingredients under the Federal 
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C. What are the energy impacts? 

 The final guidelines have important energy market 

implications. Under the final guidelines, average nationwide 

retail electricity prices are projected to increase/decrease 

about [X] percent in Table 17 presents a variety of important 

energy market impacts for 2020, increase/decrease [X] percent in 

2025, and increase/decrease [X] percent in 2030 for the 

contiguous U.S., relative to the base case. Average monthly 

electricity bills are anticipated to increase/decrease about [X] 

percent in 2020, increase/decrease [X] percent in 2025,2030 

under both the rate-based and increase/decrease [X] percent in 

2030, relative to the base case.mass-based illustrative plan 

approaches. 

 

Insecticide, Fungicide, and Rodenticide Act. Such actions 

provide authorization for the sale and distribution of those 

products, consistent with applicable labelling requirements. The 

EPA also notes that under the EPA’s regulations, registered 

pesticide labels must, among other things, specify the product 

ingredients and the methods and sites of product application. 40 

CFR 156.10. By contrast, the present rule only sets goals and 

describes potential pathways to meeting those goals, all of 

which are subject to future considerations and decisions 

involved in the implementation of plans (generally by states). 

The rule neither authorizes, nor directs, any of the future 

measures to meet the rule’s goals. Those activities remain 

subject to the full range of future decision making addressing 

which types of measures to implement, what emitting entities 

will be affected, how much, and when.
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 Under the final guidelines, the average delivered coal 

price to the utility power sector is projected to 

increase/decrease about [X] percent in 2020, increase/decrease 

[X] percent in 2025, and increase/decrease [X] percent in 2030, 

relative to the base case. The EPA projects coal use by the 

utility power sector, a large component of total coal use, will 

increase/decrease approximately [X] percent in 2020, 

increase/decrease[X] percent in 2025, and increase/decrease [X] 

percent in 2030 from base case levels. 

The EPA also projects that utility power sector-delivered 

natural gas prices will increase/decrease about [X] percent in 

2020, increase/decrease [X] percent in 2025, and 

increase/decrease [X] percent in 2030. Natural gas use for 

electricity generation will increase/decrease about [X] trillion 

cubic feet (TCF) in 2020, increase/decrease [X] TCF in 2025, and 

increase/decrease [X] TCF in 2030 relative to the base case. 

Renewable energy capacity is anticipated to increase by 

roughly [X] GW in 2025 and [X] GW in 2030 under the final 

guidelines. 

Table 17. Summary Table of Important Energy Market Impacts for 

Rate-based and Mass-based Illustrative Plan Approaches (Percent 

Change from Base Case) 

 Rate-Based Mass-Based 

 2020 2025 2030 2020 2025 2030 
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Retail electricity 

prices 3% 1% 1% 3% 2% 0% 

Price of coal at 

minemouth -1% -5% -4% -1% -5% -3% 

Coal production for 

power sector use -5% -14% -25% -7% -17% -24% 

Price of natural gas 

delivered to power 

sector 

5% -8% 2% 4% -3% -2% 

Natural gas use for 

electricity generation 3% -1% -1% 5% 0% -4% 

These figures reflect the EPA’s illustrative modeling that 

presumes policies that lead to generation shifts and growing use 

of demand-side energy efficiency and renewable electricity 

generation out to 2029. If states make different policy choices, 

impacts could be different. For instance, if states implement 

renewable and/or demand-side energy efficiency policies on a 

more aggressive time-frame, impacts on natural gas and 

electricity prices would likely be less. Implementation of other 

measures not included in the BSER calculation or compliance 

modeling, such as nuclear uprates, transmission system 

improvements, use of energy storage technologies or retrofit 

CCS, could also mitigate gas price and/or electricity price 

impacts. 
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Page 1914 of 2153

 Energy market impacts from the guidelines are discussed 

more extensively in the RIA found in the docket for this 

rulemaking. 

D. What are the compliance costs?

 The compliance costs of this final action are represented 

in this analysis as the change in electric power generation 

costs between the base case and the final rule in which states 

pursue a distinct set of strategies beyond the strategies taken 

in the base case to meet the terms of the final guidelines. The 

compliance costs estimates include cost estimates for demandside energy efficiency. The compliance assumptions – and, 

therefore, the projected compliance costs - set forth in this 

analysis are illustrative in nature and do not represent the 

full suite of compliance flexibilities states may ultimately 

pursue. The illustrative analysis is designed to reflect, to the 

extent possible, the scope and the nature of the final 

guidelines. However, there is considerable uncertainty with 

regards to the precise measures that states will adopt to meet 

the final requirements, because there are considerable 

flexibilities afforded to the states in developing their state 

plans. 

 The incremental cost is the projected additional cost of 

complying with the guidelines in the year analyzed and includes 
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the amortized cost of capital investment, needed new capacity, 

shifts between or amongst various fuels, deployment of demandside energy efficiency programs, and other actions associated 

with compliance. These important dynamics are discussed in more 

detail in the RIA in the rulemaking docket. 

The EPA projects that estimates the annual incremental 

compliance cost offor the rate-based approach for final emission 

guidelines is estimated to be $[X]$2.5 billion in 2020, about 

$[X]$1.0 billion in 2025, and about $[X]$8.4 billion (2011$) in 

2030. These estimates also include, including the costs 

associated with monitoring, reporting, and recordkeeping (MRR). 

MRR costs are estimatedMR&R).1397 The EPA estimates the annual 

incremental compliance cost for the mass-based approach for 

final emission guidelines to be approximately $[X] million$1.4 

billion in 2020, $[X] million$3.0 billion in 2025, and $[X] 

million (2011$)$5.1 billion in 2030. , including the costs 

associated with MR&R. 

More detailed cost estimates are available in the RIA 

included in the rulemaking docket. 

E. What are the economic and employment impacts? 

 

1397 The MR&R costs estimates are $65 million in 2020, $15 million 

in 2025 and $15 million in 2030 and are assumed to be the same 

for both rate-based and mass-based illustrative plan approaches.
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The final standards are projected to result in certain 

changes to power system operation as a compliance with the 

standards. Overall, we project generation shifts, changes to 

fossil fuel and retail electricity prices, and some additional 

coal-fired EGU retirements. Average utility power sector 

delivered natural gas prices are projected to increase/decrease 

roughly [X] percent in 2020, increase/decrease [X] percent in 

2025, and increase/decrease [X] percent in 2030 under the final 

guidelines, on a nationwide average basis. The average delivered 

coal price to the utility power sector is projected to 

increase/decrease about [X] percent in 2020, increase/decrease 

[X] percent in 2025, and increase/decrease [X] percent in 2030 

under the final guidelines, on a nationwide average basis. 

Retail electricity prices are projected to increase/decrease [X] 

percent in 2020, increase/decrease [X] percent in 2025, and 

increase/decrease [X] in 2030 on an average basis across the 

contiguous U.S. Under the final guidelines, the EPA projects [X] 

GW of additional coal-fired generation may be uneconomic to 

maintain and may be removed from operation by 2030See Table 16 

above for a variety of important energy market impacts for 2020, 

2025, and 2030 under both the rate-based and mass-based 

illustrative plan approaches. 
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 It is important to note that the EPA’s modeling does not 

necessarily account for all of the factors that may influence 

business decisions regarding future coal-fired capacity. By 

2025, the average age of the coal-fired fleet will be 49 years 

old and 20 percent of the fleet will be more than 60 years old 

if they remain in operation at that time. Many power companies 

already factor a potential financial liability associated with 

carbon emissions into their long term capacity planning that 

would further influence business decisions to replace these 

aging assets with modern, and significantly cleaner, generation. 

The compliance modeling done to support the final rule 

assumes that overall electric demand will decrease as states 

ramp up programs that result in lower overall demand. Demandside energy efficiency levels are expected to increase such that 

they achieve about an [X]a 7.8 percent reduction on overall 

electricity demand levels in 2030 under the final guidelines. 

Changes in price or demand for electricity, natural gas, 

and coal can impact markets for goods and services produced by 

sectors that use these energy inputs in the production process 

or supply those sectors. Changes in the cost of production may 

result in changes in prices, quantities produced, and 

profitability of affected firms. The EPA recognizes that these 

guidelines provide significant flexibilities and states 
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Page 1918 of 2153

implementing the guidelines may choose to mitigate impacts to 

some markets outside the utility power sector. Similarly, demand 

for new generation or demand-side energy efficiency as a result 

of states implementing the guidelines can result in shifts in 

production and profitability for firms that supply those goods 

and services. 

Executive Order 13563 directs federal agencies to consider 

the effect of regulations on job creation and employment. 

According to the Executive Order, “our regulatory system must 

protect public health, welfare, safety, and our environment 

while promoting economic growth, innovation, competitiveness, 

and job creation. It must be based on the best available 

science.” (Executive Order 13563, 2011) Although standard 

benefit-cost analyses have not typically included a separate 

analysis of regulation-induced employment impacts, we typically 

conduct employment analyses. During the current economic 

recoveryWhile the economy continues moving toward fullemployment, employment impacts are of particular concern and 

questions may arise about their existence and magnitude. 

 States have the responsibility and flexibility to implement 

policies and practices for compliance with the final guidelines. 

Quantifying the associated employment impacts is complicated 

by the wide range of approaches that states may use. As such, 
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Page 1919 of 2153

the EPA’s employment analysis includes projected employment 

impacts associated with illustrative compliance scenariosplan 

approaches for these guidelines for the electric power industry, 

coal and natural gas production, and demand-side energy 

efficiency activities. These projections are derived, in part, 

from a detailed model of the utility power sector used for this 

regulatory analysis, and U.S government data on employment and 

labor productivity. In the utility powerelectricity, coal, and 

natural gas sectors, the EPA estimates that these guidelines 

could have an employment impactresult in a net decrease of 

roughly [X] job-years in [20XX], [X]approximately 25,000 jobyears in [20XX],2025 for the final guidelines under the ratebased illustrative plan approach and [X]approximately 26,000

job-years in [20XX]. Demand2025 under the mass-based approach. 

For 2030, the estimates of the net decrease in job-years are 

31,000 under the rate-based approach and 34,000 under the massbased approach. The Agency is also offering an illustrative 

calculation of potential employment effects due to demand-side 

energy efficiency employmentprograms. Employment impacts are 

estimated atfrom demand-side energy efficiency programs in 2030 

could range from approximately an increase of [X]52,000 to 

83,000 jobs in 2020, [X] jobs in 2025, and [X] jobs in 2030. 

under the final guidelines. 
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By its nature, demand-side energy efficiency reduces 

overall demand for electric power. The EPA recognizes as more 

efficiency is built into the U.S. power system over time, lower 

fuel requirements may lead to fewer jobs in the coal and natural 

gas extraction sectors, as well as in fossil-fuel fired EGU 

construction and operation than would otherwise have been 

expected. The EPA also recognizes the fact that, in many cases, 

employment gains and losses that might be attributable to this 

rule would be expected to affect different sets of people. 

Moreover, workers who lose jobs in these sectors may find 

employment elsewhere just as workers employed in new jobs in 

these sectors may have been previously employed elsewhere. 

Therefore, the employment estimates reported in these sectors 

may include workers previously employed elsewhere. This analysis 

also does not capture potential economy-wide impacts due to 

changes in prices (of fuel, electricity, labor, for example) or 

other factors such as improved labor productivity and reduced 

health care expenditures resulting from cleaner air. For these 

reasons, the numbers reported here should not be interpreted as 

a net national employment impact. 

F. What are the benefits of the final goals? 

Implementing the final standards will generate benefits by 

reducing emissions of CO2 and criteria pollutant precursors, 
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Page 1921 of 2153

including SO2, NOX, and directly emitted particles. SO2 and NOX

are precursors to PM2.5 (particles smaller than 2.5 microns), and 

NOX is a precursor to ozone. The estimated benefits associated 

with these emission reductions are beyond those achieved by 

previous EPA rulemakings including the Mercury and Air Toxics 

Standards rule. The health and welfare benefits from reducing 

air pollution are considered co-benefits for these standards. 

For this rulemaking, we were only able to quantify the climate 

benefits from reduced emissions of CO2 and the health co-benefits 

associated with reduced exposure to PM2.5 and ozone. There are 

many additional benefits which we are not able to quantify, 

leading to an underestimate of monetized benefits. In summary, 

we estimate the total combined climate benefits and health cobenefits for the rate-based approach to be $[X]$3.5 to $[X]$4.6

billion in 2020, $[X]$18 to $[X]$28 billion in 2025, and $[X]$34

to $[X]$54 billion in 2030 (3 percent discount rate, 2011$). 

Total combined climate benefits and health co-benefits for the 

mass-based approach are estimated to be $5.3 to $8.1 billion in 

2020, $19 to $29 billion in 2025, and $32 to $48 billion in 2030 

(3 percent discount rate, 2011$). A summary of the emission 

reductions and monetized benefits estimated for this rule at all 

discount rates is provided in Tables 1215 through 1422 of this 

preamble. 
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Table 1218. Summary of the Monetized Global Climate Benefits for 

the Final Guidelines (billions of 2011$)a

 Discount Rate 

(Statistic) Monetized Climate Benefits 

YEAR 2020 2025 2030 

Rate-based Approach 

CO2 

Reductions 

(million 

metricshort

tons) 

 [X]69 [X]232 [X]415

 

5 percent (average 

SC-CO2) $[X]$0.80 $[X]$3.1 $[X]$6.4

3 percent (average 

SC-CO2) $2.8 $10 $20 

2.5 percent 

(average SC-CO2) $4.1 $15 $29 

3 percent (95th

percentile SC-CO2) $8.2 $31 $61 

Mass-based Approach 

CO2 

Reductions 

(million 

short tons) 

 81 265 413 

 

5 percent (average 

SC-CO2) $0.94 $3.6 $6.4 

3 percent (average 

SC-CO2) $[X]$3.3 $[X]$12 $[X]$20

2.5 percent 

(average SC-CO2) $[X]$4.9 $[X]$17 $[X]$29

3 percent (95th

percentile SC-CO2) $[X]$9.7 $[X]$35 $[X]$60
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a Climate benefit estimates reflect impacts from CO2 emission 

changes in the analysis years presented in the table and do not 

account for changes in non-CO2 GHG emissions. These estimates are 

based on the global social cost of carbon (SC-CO2) estimates for 

the analysis years and are rounded to two significant figures. 

Table 1319. Summary of the Monetized Health Co-Benefits in the 

U.S. for the Final Guidelines, Rate-based Approach (billions of 

2011$)a 

Pollutant 

National 

Emission 

Reduction

s 

(thousand

s of 

short 

tons) 

Monetize

d Health 

Cobenefits

Monetized Health Cobenefits 

(3 

percent 

discount

) 

(7 percent discount) 

Final Guidelines, Rate-based Approach, 2020 

PM2.5 precursors b 

SO2 [X]14

$[X]$0.4

4 to 

$[X]$0.9

9 $[X]$0.39 to $[X]$0.89

NOX 50 $0.14 to 

$0.33 $0.13 to $0.30 

Ozone precursor c 

NOX (ozone 

season only) 19 $0.12 to 

$0.52 $0.12 to $0.52 

Total Monetized Health Cobenefits 

$0.70 to 

$1.8 $0.64 to $1.7 

Total Monetized Health Cobenefits combined with 

Monetized Climate Benefits d

$3.5 to 

$4.6

Directly 

emitted 

PM2.5 

(Elementa

l Carbon 

and 

Organic 

Carbon)$3

.5 to 

$4.5

[X

]

$[X

]

$[X

]

Final Guidelines, Rate-based Approach, 2025 

Inserted Cells

Inserted Cells

Deleted Cells

Deleted Cells

Deleted Cells
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Directly emitted 

PM2.5 

(crustal)precurso

rs b

[X] $[X] $[X] 

SO2 178 $6.4 to 

$14 $5.7 to $13 

NOX [X]165

$[X]$0.5

6 to 

$[X]$1.3 $[X]$0.50 to $[X]$1.1

Ozone precursor c 

NOX (ozone 

season only) [X]70

$[X]$0.4

9 to 

$[X]$2.1 $[X]$0.49 to $[X]$2.1

Total Monetized Health Cobenefits 

$[X] to 

$[X] $[X] to $[X] 

Total Monetized Health Cobenefits combined with 

Monetized Climate Benefits d

$[X]$7.4

to 

$[X]$18 $[X]$6.7 to $[X]$16

Final Guidelines, 2025 

PM2.5 precursors b 

SO2 [X] $[X] to 

$[X] $[X] to $[X] 

Directly 

emitted PM2.5 

(Elemental Carbon 

and Organic 

Carbon) 

[X] $[X] $[X] 

Directly 

emitted PM2.5 

(crustal) 

[X] $[X] $[X] 

NOX [X] $[X] to 

$[X] $[X] to $[X] 

Ozone precursor c 

NOX (ozone 

season only) [X] $[X] to 

$[X] $[X] to $[X] 

Total Monetized Health Cobenefits 

$[X] to 

$[X] $[X] to $[X] 

Total Monetized Health Cobenefits combined with 

Monetized Climate Benefits d

$[X]$18

to 

$[X]$28

$[X]$17 to $[X]$26

Final Guidelines, Rate-based Approach, 2030 
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PM2.5 precursors b

SO2 [X]318

$[X]$12

to 

$[X]$28 $[X]$11 to $[X]$25

Directly 

emitted PM2.5 

(Elemental Carbon 

and Organic 

Carbon) 

[X] $[X] $[X] 

Directly 

emitted PM2.5 

(crustal) 

[X] $[X] $[X] 

NOX [X]282

$[X]$1.0

to 

$[X]$2.3 $[X]$0.93 to $[X]$2.1

Ozone precursor c

NOX (ozone 

season only) [X]118

$[X]$0.8

6 to 

$[X]$3.7

$[X] To $[X]$0.86 to 

$3.7

Total Monetized Health Cobenefits 

$[X]$14

to 

$[X]$34 $[X]$13 to $[X]$31

Total Monetized Health Cobenefits combined with 

Monetized Climate Benefits d

$[X]$34

to 

$[X]$54

$[X]$33 to $[X]$51

a All estimates are rounded to two significant figures, so 

estimates may not sum. It is important to note that the 

monetized co-benefits do not include reduced health effects from 

direct exposure to SO2, direct exposure to NO2, exposure to 

mercury, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2, NOX and directly 

emitted PM2.5. and NOX. The co-benefits do not include the 

benefits of reductions in directly emitted PM2.5. These 

additional benefits would increase overall benefits by a few 

percent based on the analyses conducted for the proposed rule. 

PM co-benefits are shown as a range reflecting the use of two 

concentration-response functions, with the lower end of the 

range based on a function from Krewski et al. (2009) and the 

upper end based on a function from Lepeule et al. (2012). These 
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models assume that all fine particles, regardless of their 

chemical composition, are equally potent in causing premature 

mortality because the scientific evidence is not yet sufficient 

to allow differentiation of effect estimates by particle type. 

c The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent). Referred to as the social cost of carbon, each value 

increases over time. For the purposes of this table, we show the 

benefits associated with the model average at 3 percent discount 

rate, however we emphasize the importance and value of 

considering the full range of social cost of carbon values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA. 

Table 20. Summary of the Monetized Health Co-Benefits in the 

U.S. for the Final Guidelines, Mass-based Approach (billions of 

2011$)a 

Pollutant 

National 

Emission 

Reductions 

(thousands 

of short 

tons) 

Monetized 

Health Cobenefits 

Monetized 

Health Cobenefits 

(3 percent 

discount) 

(7 percent 

discount) 

Final Guidelines, Mass-based Approach, 2020 

PM2.5 precursors b 

SO2 54 $1.7 to $3.8 $1.5 to $3.4

NOX 60 $0.17 to 

$0.39 

$0.16 to 

$0.36 

Ozone precursor c

NOX (ozone season only) 23 $0.14 to 

$0.61 

$0.14 to 

$0.61 
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Total Monetized Health Co-benefits $2.0 to $4.8 $1.8 to $4.4

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$5.3 to $8.1 $5.1 to $7.7

Final Guidelines, Mass-based Approach, 2025 

PM2.5 precursors b 

SO2 185 $6.0 to $13 $5.4 to $12 

NOX 203 $0.58 to 

$1.3 

$0.52 to 

$1.2 

Ozone precursor c 

NOX (ozone season only) 88 $0.56 to 

$2.4 

$0.56 to 

$2.4 

Total Monetized Health Co-benefits $7.1 to $17 $6.5 to $16 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$19 to $29 $18 to $27 

Final Guidelines, Mass-based Approach, 2030 

PM2.5 precursors b

SO2 280 $10 to $23 $9.0 to $20 

NOX 278 $0.87 to 

$2.0 

$0.79 to 

$1.8 

Ozone precursor c

NOX (ozone season 

only) 121 $0.82 to 

$3.5 

$0.82 to 

$3.5 

Total Monetized Health Co-benefits $12 to $28 $11 to $26 

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$32 to $48 $31 to $46 

a All estimates are rounded to two significant figures, so 

estimates may not sum. It is important to note that the 

monetized co-benefits do not include reduced health effects from 

direct exposure to SO2, direct exposure to NO2, exposure to 

mercury, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2 and NOX. The co-
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benefits do not include the benefits of reductions in directly 

emitted PM2.5. These additional benefits would increase overall 

benefits by a few percent based on the analyses conducted for 

the proposed rule. PM co-benefits are shown as a range 

reflecting the use of two concentration-response functions, with 

the lower end of the range based on a function from Krewski et 

al. (2009) and the upper end based on a function from Lepeule et 

al. (2012). These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type. 

c The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent). Referred to as the social cost of carbon, each value 

increases over time. For the purposes of this table, we show the 

benefits associated with the model average at 3 percent discount 

rate, however we emphasize the importance and value of 

considering the full range of social cost of carbon values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA. 

The EPA has used the social cost of carbon (SC-CO2) 

estimates presented in the Technical Support Document: Technical 

Update of the Social Cost of Carbon for Regulatory Impact 

Analysis Under Executive Order 12866 (May 2013, Revised June 

2015) (“current TSD”) to analyze CO2 climate impacts of this 
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rulemaking.1398 We refer to these estimates, which were developed 

by the U.S. government, as “SC-CO2 estimates.” The SC-CO2 is a 

metric that estimates the monetary value of impacts associated 

with marginal changes in CO2 emissions in a given year. It 

includes a wide range of anticipated climate impacts, such as 

net changes in agricultural productivity and human health, 

property damage from increased flood risk, and changes in energy 

system costs, such as reduced costs for heating and increased 

costs for air conditioning. It is typically used to assess the 

avoided damages as a result of regulatory actions (i.e., 

benefits of rulemakings that lead to an incremental reduction in 

cumulative global CO2 emissions). 

The SC-CO2 estimates used in this analysis were developed 

over many years, using the best science available, and with 

input from the public. Specifically, an interagency working 

 

1398 Docket ID EPA-HQ-OAR-2013-0495, Technical Support Document: 

Technical Update of the Social Cost of Carbon for Regulatory 

Impact Analysis Under Executive Order 12866, Interagency Working 

Group on Social Cost of Carbon, with participation by Council of 

Economic Advisers, Council on Environmental Quality, Department 

of Agriculture, Department of Commerce, Department of Energy, 

Department of Transportation, Domestic Policy Council, 

Environmental Protection Agency, National Economic Council, 

Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (May 2013, Revised 

JuneJuly 2015). Available at: 

http://[X].://www.whitehouse.gov/sites/default/files/omb/inforeg

/scc-tsd-final-july-2015.pdf.
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group (IWG) that included the EPA and other executive branch 

agencies and offices used three integrated assessment models 

(IAMs) to develop the SC-CO2 estimates and recommended four 

global values for use in regulatory analyses. The SC-CO2

estimates were first released in February 2010 and updated in 

2013 using new versions of each IAM. The 2010 SC-CO2 Technical 

Support Document (2010 TSD)1399 provides a complete discussion of 

the methods used to develop these estimates and the current TSD 

presents and discusses the 2013 update (including two recent 

minor corrections to the estimates).1400 

 

1399 Docket ID EPA-HQ-OAR-2009-0472-114577, Technical Support 

Document: Social Cost of Carbon for Regulatory Impact Analysis 

Under Executive Order 12866, Interagency Working Group on Social 

Cost of Carbon, with participation by the Council of Economic 

Advisers, Council on Environmental Quality, Department of 

Agriculture, Department of Commerce, Department of Energy, 

Department of Transportation, Environmental Protection Agency, 

National Economic Council, Office of Energy and Climate Change, 

Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (February 2010). 

Also available at: 

http://www.whitehouse.gov/sites/default/files/omb/inforeg/foragencies/Social-Cost-of-Carbon-for-RIA.pdf.

1400 The current version of the TSD is available at: 

http://[X],https://www.whitehouse.gov/sites/default/files/omb/in

foreg/scc-response-to-comments-final-july-2015.pdf, Docket ID 

EPA-HQ-OAR-2013-0495, Technical Support Document: Technical 

Update of the Social Cost of Carbon for Regulatory Impact 

Analysis Under Executive Order 12866, Interagency Working Group 

on Social Cost of Carbon, with participation by Council of 

Economic Advisers, Council on Environmental Quality, Department 

of Agriculture, Department of Commerce, Department of Energy, 

Department of Transportation, Domestic Policy Council, 
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The EPA received numerous comments on the SC-CO2 estimates 

as part of this rulemaking. The comments covered a wide range of 

topics including the technical details of the modeling conducted 

to develop the SC-CO2 estimates, the aggregation and presentation 

of the SC-CO2 estimates, and the process by which the SC-CO2

estimates were derived. Many but not all commenters were 

supportive of the SC-CO2 and its application to this rulemaking. 

Commenters also provided constructive recommendations for 

potential opportunities to improve the SC-CO2 estimates in future 

updates. Many of these comments were similar to those that OMB’s 

Office of Information and Regulatory Affairs received in 

response to a separate request for public comment on the 

approach used to develop the estimates. After careful evaluation 

of the full range of comments submitted to OMB, the interagency 

working groupIWG continues to recommend the use of the SC-CO2

estimates in regulatory impact analysis.1401 With the release of 

the response to comments, the interagency working groupIWG

announced plans to obtain expert independent advice from the 

 

Environmental Protection Agency, National Economic Council, 

Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (May 2013, Revised 

JuneJuly 2015). 1401 See https://www.whitehouse.gov/omb/oira/social-cost-of-carbon 

for additional details, including the OMB Response to Comments 

and the SC-CO2 TSDs. 
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National AcademyAcademies of Sciences’ National Research Council 

(NRCSciences, Engineering, and Medicine (Academies) to ensure 

that the SC-CO2 estimates continue to reflect the best available 

scientific and economic information on climate change. The 

NRCAcademies review will be informed by the public comments 

received and focus on the technical merits and challenges of 

potential approaches to improving the SC-CO2 estimates in future 

updates. See the EPA Response to Comments document for the 

complete response to comments received on SC-CO2 as part of this 

rulemaking. 

Concurrent with OMB’s publication of the response to 

comments on SC-CO2 and announcement of the NRCAcademies process, 

OMB posted a revised TSD that includes two minor technical 

corrections to the current estimates. One technical correction 

addressed an inadvertent omission of climate change damages in 

the last year of analysis (2300) in one model and the second 

addressed a minor indexing error in another model. On average 

the revised SC-CO2 estimates are one dollar less than the mean 

SC-CO2 estimates reported in the November 2013 revision to the 

May 2013 TSD. The change in the estimates associated with the 

95th percentile estimates when using a 3 percent discount rate 

is slightly larger, as those estimates are heavily influenced by 
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the results from the model that was affected by the indexing 

error.

The EPA, as a member of the IWG on the SC-CO2, has 

carefully examined and evaluated the minor technical corrections 

in the revised TSD and the public comments submitted to OMB’s 

separate SC-CO2 comment process. Additionally, the EPA has 

carefully examined and evaluated all comments received regarding 

the SC-CO2 through this rulemaking process. The EPA concurs with 

the IWG’s conclusion that it is reasonable, and scientifically 

appropriate, to use the current SC-CO2 estimates for purposes of 

regulatory impact analysis, including for this proceeding. 

The four SC-CO2 estimates are as follows: $13, $45, $6612, 

$40, $60, and $130120 per metricshort ton of CO2 emissions in the 

year 2020 (2011$).1402 The first three values are based on the 

average SC-CO2 from the three IAMs, at discount rates of 5, 3, 

and 2.5 percent, respectively. The SC-CO2 value at several 

discount rates are included because the literature shows that 

the SC-CO2 is quite sensitive to assumptions about the discount 

 

1402 The current version of the TSD is available at: 

https://www.whitehouse.gov/sites/default/files/omb/inforeg/scctsd-final-july-2015.pdf. The 2010 and 2013 TSDs present SC-CO2 in 

$2007.$ per metric ton. The estimates were adjusted to (1) short 

tons for using conversion factor 0.90718474 and (2) 2011$ using 

the GDP Implicit Price Deflator. Also available at: , 

http://www.gpo.gov/fdsys/pkg/ECONI-2013-02/pdf/ECONI-2013-02-

Pg3.pdf. 
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rate, and because no consensus exists on the appropriate rate to 

use in an intergenerational context (where costs and benefits 

are incurred by different generations). The fourth value is the 

95th percentile of the SC-CO2 from all three models at a 3 

percent discount rate. It is included to represent higher-thanexpected impacts from temperature change further out in the 

tails of the SC-CO2 distribution (representing less likely, but 

potentially catastrophic, outcomes). 

There are limitations in the estimates of the benefits from 

the final emission guidelines, including the omission of climate 

and other CO2 related benefits that could not be monetized. The 

2010 TSD discusses a number of limitations to the SC-CO2

analysis, including the incomplete way in which the IAMs capture 

catastrophic and non-catastrophic impacts, their incomplete 

treatment of adaptation and technological change, uncertainty in 

the extrapolation of damages to high temperatures, and 

assumptions regarding risk aversion. Currently, IAMs do not 

assign value to all of the important impacts of CO2 recognized in 

the literature, such as ocean acidification or potential tipping 

points, for various reasons, including the inherent difficulties 

in valuing non-market impacts and the fact that the science 

incorporated into these models understandably lags behind the 

most recent research. Nonetheless, these estimates and the 
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Page 1935 of 2153

discussion of their limitations represent the best available 

information about the social benefits of CO2 emission reductions 

to inform the benefit-cost analysis. As previously noted, the 

interagency working groupIWG plans to seek independent expert 

advice on technical opportunities to improve the SC-CO2 estimates 

from the NRCAcademies. The NRCAcademies process will help to 

ensure that the SC-CO2 estimates used by the federal government 

continue to reflect the best available science and 

methodologies. Additional details are provided in the TSDs. 

The health co-benefits estimates represent the total 

monetized human health benefits for populations exposed to 

reduced PM2.5 and ozone resulting from emission reductions from 

the illustrative compliance strategy for the final standards. 

Unlike the global SC-CO2 estimates, the air pollution health cobenefits are estimated for the contiguous U.S. only. We used a 

“benefit-per-ton” approach to estimate the benefits of this 

rulemaking. To create the PM2.5 benefit-per-ton estimates, we 

conducted air quality modeling for an illustrative scenario 

reflecting the proposed standards to convert precursor emissions 

into changes in ambient PM2.5 and ozone concentrations. We then 

used these air quality modeling results in BenMAP1403 to calculate 

 

1403 http://www.epa.gov/airquality/benmap/index.html
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average regional benefit-per-ton estimates using the health 

impact assumptions used in the PM NAAQS RIA1404 and Ozone NAAQS 

RIAs.1405,1406 The three regions were the Eastern U.S., Western 

U.S., and California. To calculate the co-benefits for the final 

standards, we multiplied the regional benefit-per-ton estimates 

generated from modeling of the proposed standards by the 

corresponding regional emission reductions for the final 

standards.1407 All benefit-per-ton estimates reflect the 

 

1404 U.S. Environmental Protection Agency (U.S. EPA). 2012. 

Regulatory Impact Analysis for the Final Revisions to the 

National Ambient Air Quality Standards for Particulate Matter. 

Research Triangle Park, NC: Office of Air Quality Planning and 

Standards, Health and Environmental Impacts Division. (EPA 

document number EPA-452/R-12-003, December). Available at: 

<http://www.epa.gov/pm/2012/finalria.pdf>. 

1405 U.S. Environmental Protection Agency (U.S. EPA). 2008b. Final 

Ozone NAAQS Regulatory Impact Analysis. Research Triangle Park, 

NC: Office of Air Quality Planning and Standards, Health and 

Environmental Impacts Division, Air Benefit and Cost Group 

Research. (EPA document number EPA-452/R-08-003, March). 

Available at: 

<http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=194645>.

1406 U.S. Environmental Protection Agency (U.S. EPA). 2010. 

Section 3: Re-analysis of the Benefits of Attaining Alternative 

Ozone Standards to Incorporate Current Methods. Available at: 

<http://www.epa.gov/ttnecas1/regdata/RIAs/s3-

supplemental_analysis-updated_benefits11-5.09.pdf>. 

1407 U.S. Environmental Protection Agency. 2013. Technical support 

document: Estimating the benefit per ton of reducing PM2.5

precursors from 17 sectors. Research Triangle Park, NC: Office 

of Air and Radiation, Office of Air Quality Planning and 

Standards, January. Available at: 

<http://www.epa.gov/airquality/benmap/models/Source_Apportionmen

t_BPT_TSD_1_31_13.pdf>. 
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geographic distribution of the modeled emissions for the 

proposed standards, which may not exactly match the emission 

reductions in this final rulemaking, and thus they may not 

reflect the local variability in population density, 

meteorology, exposure, baseline health incidence rates, or other 

local factors for any specific location. More information 

regarding the derivation of the benefit-per-ton estimates is 

available in the RIA. 

PM benefit-per-ton values are generated using two 

concentration-response functions, Krewski et al. (2009) 1408 and 

Lepeule et al. (2012).) 1409. These models assume that all fine 

particles, regardless of their chemical composition, are equally 

potent in causing premature mortality because the scientific 

evidence is not yet sufficient to allow differentiation of 

effect estimates by particle type. Even though we assume that 

all fine particles have equivalent health effects, the benefitper-ton estimates vary between PM2.5 precursors depending on the 

 

1408 Krewski D.; M. Jerrett; R. T. Burnett; R. Ma; E. Hughes; Y. 

Shi, et al. 2009. Extended Follow-up and Spatial Analysis of the 

American Cancer Society Study Linking Particulate Air Pollution 

and Mortality. Health Effects Institute. (HEI Research Report 

number 140). Boston, MA: Health Effects Institute. 

1409 Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012. 

“Chronic Exposure to Fine Particles and Mortality: An Extended 

Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environmental Health Perspective, 120(7), July, pp. 965-970. 
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location and magnitude of their impact on PM2.5 concentrations, 

which drive population exposure. 

It is important to note that the magnitude of the PM2.5 and 

ozone co-benefits is largely driven by the concentration 

response functions for premature mortality and the value of a 

statistical life used to value reductions in premature 

mortality. For PM2.5, we use two key empirical studies, one based 

on the American Cancer Society cohort study1410 (Krewski et al, 

2009) and one based on the extended Six Cities cohort study.1411

(Lepuele et al, 2012). We present the PM2.5 co-benefits results as 

a range based on benefit-per-ton estimates calculated using the 

concentration-response functions from these two epidemiology 

studies, but this range does not capture the full range of 

uncertainty inherent in the co-benefits estimates. In the RIA 

for this rule, which is available in the docket, we also include 

PM2.5 co-benefits estimates using benefit-per-ton estimates based 

on expert judgments of the effect of PM2.5 on premature mortality 

 

1410 Krewski D.; M. Jerrett; R. T. Burnett; R. Ma; E. Hughes; Y. 

Shi, et al. 2009. Extended Follow-up and Spatial Analysis of the 

American Cancer Society Study Linking Particulate Air Pollution 

and Mortality. Health Effects Institute. (HEI Research Report 

number 140). Boston, MA: Health Effects Institute. 1411 Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012. 

“Chronic Exposure to Fine Particles and Mortality: An Extended 

Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environmental Health Perspective, 120(7), July, pp. 965-970. 
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(Roman et al., 2008)1412 as a characterization of uncertainty 

regarding the PM2.5-mortality relationship. 

For the ozone co-benefits, we present the results as a range 

reflecting benefit-per-ton estimates which use several different 

concentration-response functions for mortality, with the lower 

end of the range based on a benefit-per-ton estimate using the 

function from Bell et al. (2004)1413 and the upper end based on a 

benefit-per-ton estimate using the function from Levy et al. 

(2005).1414 Similar to PM2.5, the range of ozone co-benefits does 

not capture the full range of inherent uncertainty. 

In this analysis, in estimating the benefits-per-ton for 

PM2.5 precursors, the EPA assumes that the health impact function 

for fine particles is without a threshold. This is based on the 

conclusions of EPA’s Integrated Science Assessment for 

Particulate Matter,1415 which evaluated the substantial body of 

 

1412 Roman, H., et al. 2008. “Expert Judgment Assessment of the 

Mortality Impact of Changes in Ambient Fine Particulate Matter 

in the U.S.” Environmental Science & Technology, Vol. 42, No. 7, 

February, pp. 2268 – 2274. 

1413 Bell, M.L., et al. 2004. “Ozone and Short-Term Mortality in 

95 U.S. Urban Communities, 1987-2000.” Journal of the American 

Medical Association, 292(19), pp. 2372-8. 1414 Levy, J.I., S.M. Chemerynski, and J.A. Sarnat. 2005. “Ozone 

exposure and mortality: an empiric Bayes metaregression 

analysis.” Epidemiology. 16(4): p. 458-68. 1415 U.S. Environmental Protection Agency. 2009. Integrated 

Science Assessment for Particulate Matter (Final Report). 

Research Triangle Park, NC: National Center for Environmental 
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published scientific literature, reflecting thousands of 

epidemiology, toxicology, and clinical studies that documents 

the association between elevated PM2.5 concentrations and adverse 

health effects, including increased premature mortality. This 

assessment, which was twice reviewed by the EPA’s independent 

Science Advisory Board, concluded that the scientific literature 

consistently finds that a no-threshold model most adequately 

portrays the PM-mortality concentration-response relationship. 

In general, we are more confident in the magnitude of the 

risks we estimate from simulated PM2.5 concentrations that 

coincide with the bulk of the observed PM concentrations in the 

epidemiological studies that are used to estimate the benefits. 

Likewise, we are less confident in the risk we estimate from 

simulated PM2.5 concentrations that fall below the bulk of the 

observed data in these studies. 

For this analysis, policy-specific air quality data are not 

available,1416 and thus, we are unable to estimate the percentage 

of premature mortality associated with this specific rule. that 

is above the lowest measured PM2.5 levels (LML) for the two PM2.5

 

Assessment, RTP Division. (EPA document number EPA-600-R-08-

139F, December). Available at: 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546. 

1416 In addition, site-specific emission reductions will depend 

upon how states implement the guidelines. 
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mortality epidemiology studies that form the basis for our 

analysis. As a surrogate measure of mortality impacts above the 

LML, we provide the percentage of the population exposed above 

the lowest measured PM2.5 level (LML) in each of the two studies

from which we obtained concentration-response functions for PM2.5 

mortality, using the estimates of baseline projected PM2.5 from 

the air quality modeling for the proposed guidelines used to 

calculate the benefit-per-ton estimates for the EGU sector. 

Using the Krewski et al. (2009) study, 88 percent of the 

population is exposed to annual mean PM2.5 levels at or above the 

LML of 5.8 micrograms per cubic meter (μg/m3). Using the Lepeule 

et al. (2012) study, 46 percent of the population is exposed 

above the LML of 8 μg/m3. It is important to note that baseline 

exposure is only one parameter in the health impact function, 

along with baseline incidence rates, population, and change in 

air quality. 

Every benefit 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. Despite these uncertainties, we believe the air 

quality co-benefit analysis for this rule provides a reasonable 
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indication of the expected health benefits of the air pollution 

emission reductions for the illustrative analysis of the final 

standards under a set of reasonable assumptions. This analysis 

does not include the type of detailed uncertainty assessment 

found in the 2012 PM2.5 National Ambient Air Quality Standard 

(NAAQS) RIA (U.S. EPA, 2012) because we lack the necessary air 

quality input and monitoring data to conduct a complete benefits 

assessment. In addition, using a benefit-per-ton approach adds 

another important source of uncertainty to the benefits 

estimates. The 2012 PM2.5 NAAQS benefits analysis provides an 

indication of the sensitivity of our results to various 

assumptions. 

We note that the monetized co-benefits estimates shown here 

do not include several important benefit categories, including 

exposure to SO2, NOX, and hazardous air pollutants (e.g., mercury 

and hydrogen chloride), as well as ecosystem effects and 

visibility impairment. Although we do not have sufficient 

information or modeling available to provide monetized estimates 

for this rule, we include a qualitative assessment of these 

unquantified benefits in the RIA for the final 

standardsguidelines. In addition, in the RIA for the final 

standards, we did not estimate changes in emissions of directly 

emitted particles. As a result, quantified PM2.5 related benefits 
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are underestimated by a relatively small amount. In the RIA for 

the proposed guidelines, the benefits from reductions in 

directly emitted PM2.5 were less than 10 percent of total 

monetized health co-benefits across all scenarios and years. 

For more information on the benefits analysis, please refer 

to the RIA for this rule, which is available in the rulemaking 

docket. 

XII. Statutory and Executive Order Reviews 

Additional information about these Statutory and Executive 

Orders can be found at http://www2.epa.gov/lawsregulations/laws-and-executive-orders. 

A. Executive Order 12866: Regulatory Planning and Review, and 

Executive Order 13563: Improving Regulation and Regulatory 

Review 

This final action is an economically significant regulatory 

action that was submitted to the OMB for review. Any changes 

made in response to OMB recommendations have been documented in 

the docket. The EPA prepared an analysis of the potential costs 

and benefits associated with this action. This analysis, which 

is contained in the “Regulatory Impact Analysis for Clean Power 

Plan Final Rule” (EPA-452/R-15-003, July 2015), is available in 

the docket and is briefly summarized in section XI of this 

preamble. 
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 Consistent with Executive Order 12866 and Executive Order 

13563, the EPA estimated the costs and benefits for illustrative 

compliance approaches of implementing the guidelines. The final 

rule establishes: 1) carbon dioxide (CO2) emission performance 

rates for two source categories of existing fossil fuel-fired 

EGUs, fossil fuel-fired electric utility steam generating units 

and stationary combustion turbines, and 2) guidelines for the 

development, submittal and implementation of state plans that 

implement the CO2 emission performance rates. Actions taken to 

comply with the guidelines will also reduce the emissions of 

directly-emitted PM2.5, SO2 and NOX. The benefits associated with 

these PM2.5, SO2 and NOX reductions are referred to as cobenefits, as these reductions are not the primary objective of 

this rule. 

The EPA has used the social cost of carbon estimates 

presented in the Technical Support Document: Technical 

Update of the Social Cost of Carbon for Regulatory Impact 

Analysis Under Executive Order 12866 (May 2013, Revised 

JuneJuly 2015) (“current TSD”) to analyze CO2 climate impacts 

of this rulemaking. We refer to these estimates, which were 

developed by the U.S. government, as “SC-CO2 estimates.” The 

SC-CO2 is an estimate of the monetary value of impacts 

associated with a marginal change in CO2 emissions in a 
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given year. The four SC-CO2 estimates are associated with 

different discount rates (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 

3 percent), and each increases over time. In this summary, 

the EPA provides the estimate of climate benefits 

associated with the SC-CO2 value deemed to be central in the 

current TSD: the model average at 3 percent discount rate. 

In the final emission guidelines, the EPA has translated 

the source category-specific CO2 emission performance rates into 

equivalent state-level rate-based and mass-based CO2 goals in 

order to maximize the range of choices that states will have in 

developing their plans. Because of the range of choices 

available to states and the lack of a priori knowledge about the 

specific choices states will make in response to the final 

goals, the Regulatory Impact Analysis (RIA) for this rule 

analyzed two implementation scenarios designed to achieve these 

goals, which we term the “rate-based” illustrative plan approach 

and the “mass-based” illustrative plan approach. 

It is very important to note that the differences between 

the analytical results for the rate-based and mass-based 

illustrative plan approaches presented in the RIA may not be 

indicative of likely differences between the approaches if 

implemented by states and affected EGUs in response to the final 
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guidelines. Rather, the two sets of analyses are intended to 

illustrate two different approaches to accomplish the emission 

performance rates finalized in the Clean Power Plan Final Rule. 

In other words, if one approach performs differently than the 

other on a given metric during a given time period, this does 

not imply this will apply in all instances in all time periods 

in all places. 

The EPA estimates that, in 2020, the final guidelines 

will yield monetized climate benefits (in 2011$) of 

approximately $[X]$2.8 billion for the rate-based approach 

and $3.3 billion for the mass-based approach (3 percent 

model average). TheFor the rate-based approach, the air 

pollution health co-benefits in 2020 are estimated to be 

$[X]$0.7 billion to $[X]$1.8 billion (2011$) for a 3 percent 

discount rate and $[X] billion to $[X]$0.64 billion (2011$) for a 7 

percent discount rate.to $1.7 billion (2011$) for a 7 percent 

discount rate. For the mass-based approach, the air 

pollution health co-benefits in 2020 are estimated to be 

$2.0 billion to $4.8 billion (2011$) for a 3 percent 

discount rate and $1.8 billion to $4.4 billion (2011$) for 

a 7 percent discount rate. The annual, illustrative 

compliance costs estimated by IPM and inclusive of demandside energy efficiency program and participant costs and 
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MRR costs in 2020, are approximately $[X]$2.5 billion for 

the rate-based approach and $1.4 billion for the mass-based 

approach (2011$) in 2020.$). The quantified net benefits (the 

difference between monetized benefits and compliance costs) 

in 2020 are estimated to range from $[X]$1.0 billion to 

$[X]$2.1 billion (2011$) for the rate-based approach and 

from $3.9 billion to 6.7 billion (2011$) for the mass-based 

approach, using a 3 percent discount rate (model average). 

The EPA estimates that, in 2025, the final guidelines will 

yield monetized climate benefits (in 2011$) of approximately 

$[X] billion $10 billion for the rate-based approach and $12 

billion for the mass-based approach (3 percent model average). 

TheFor the rate-based approach, the air pollution health cobenefits in 2025 are estimated to be $[X]$7.4 billion to $[X]$18

billion (2011$) for a 3 percent discount rate and $[X]$6.7

billion to $[X]$16 billion (2011$) for a 7 percent discount 

rate. For the mass-based approach, the air pollution health cobenefits in 2025 are estimated to be $7.1 billion to $17 billion 

(2011$) for a 3 percent discount rate and $6.5 billion to $16

billion (2011$) for a 7 percent discount rate. The annual, 

illustrative compliance costs estimated by IPM and inclusive of 

demand side energy efficiency program and participant costs and 

MRR costs in 2025, are approximately $[X]$1.0 billion for the 
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rate-based approach and $3.0 billion for the mass-based approach 

(2011$) in 2025.$). The quantified net benefits (the difference 

between monetized benefits and compliance costs) in 2025 are 

estimated to range from $[X]$17 billion to $[X]$27 billion 

(2011$) for the rate-based approach and $16 billion to $26 

billion (2011$) for the mass-based approach, using a 3 percent 

discount rate (model average). 

The EPA estimates that, in 2030, the final guidelines will 

yield monetized climate benefits (in 2011$) of approximately 

$[X] billion $20 billion for the rate-based approach and $20 

billion for the mass-based approach (3 percent model average). 

TheFor the rate-based approach, the air pollution health cobenefits in 2030 are estimated to be $[X]$14 billion to $[X]$34

billion (2011$) for a 3 percent discount rate and $[X]$13

billion to $[X]$31 billion (2011$) for a 7 percent discount 

rate. For the mass-based approach, the air pollution health cobenefits in 2030 are estimated to be $12 billion to $28 billion 

(2011$) for a 3 percent discount rate and $11 billion to $26

billion (2011$) for a 7 percent discount rate. The annual, 

illustrative compliance costs estimated by IPM and inclusive of 

demand side energy efficiency program and participant costs and 

MRR costs in 2030, are approximately $[X]$8.4 billion for the 

rate-based approach and $5.1 billion for the mass-based approach 
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(2011$) in 2030.$). The quantified net benefits (the difference 

between monetized benefits and compliance costs) in 2030 are 

estimated to range from $[X]$26 billion to $[X]$45 billion 

(2011$) for the rate-based approach and from $26 billion to $43 

billion (2011$) for the mass-based approach, using a 3 percent 

discount rate (model average). 

Table 14. Summary of the Monetized Benefits, Compliance Costs, 

and Net Benefits for the Final Guidelines in 2020, 2025 and 2030a

Tables 20 and 21 provide the estimates of the climate 

benefits, health co-benefits, compliance costs and net benefits 

of the final emission guidelines for rate-based and mass-based 

illustrative plan approaches, respectively. 

Table 21. Summary of the Monetized Benefits, Compliance Costs, 

and Net Benefits for the Final Guidelines in 2020, 2025 and 2030 

Under the Rate-Based Illustrative Plan Approach [Billions of 

2011$]a

Final Guidelines, 2020 

 Rate-Based Approach 

2020 2025 2030

Climate 

Benefitsb 

5% discount 

rate $0.80 $3.1 $6.4 

3% discount 

rate $2.8 $10 $20 
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2.5% 

discount 

rate 

$4.1 $15 $29 

95th 

percentile 

at 3% 

discount 

rate 

$8.2 $31 $61 

Air Quality Co-benefits Discount Rate 

3% 7% 3% 7% 3% 7% 

Air Quality 

Health Cobenefitsc

$0.70 to $1.8 

$0.64 

to 

$1.7 

$7.4 

to 

$18 

$6.7 

to 

$16 

$14 

to 

$34

$13 

to 

$31

Compliance 

Costsd $2.5 $1.0 $8.4 

Net 

Benefitse $1.0 to $2.1 

$1.0 

to 

$2.0 

$17 

to 

$27 

$16 

to 

$25 

$26 

to 

$45

$25 

to 

$43

NonMonetized 

Benefits 

Non-monetized climate benefits 

 3% Discount Rate 

7% 

Discount 

rate 

Climate benefits b $[X] 

Air pollution 

health co-benefits 

c

$[X] to $[X] $[X] to 

$[X] 

Total Compliance 

Costs d $[X] $[X] 

Net Monetized 

Benefits e $[X] to $[X] $[X] to 

$[X] 

Non-monetized 

Benefits 

Non-monetized climate 

benefits 

Reductions in exposure to ambient NO2 and SO2
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Reductions in mercury 

deposition 

Reductions in mercury deposition 

Ecosystem benefits associated with reductions in 

emissions of NOX, SO2, PM, and mercury 

Visibility impairment 

Final Guidelines, 2025 

a All are rounded to two significant figures, so figures may not 

sum. 

b The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to SC-CO2 than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SC-CO2 estimated for a 3 percent discount rate. However, 

we emphasize the importance and value of considering the full 

range of SC-CO2 values. As shown in the RIA, climate benefits are 

also estimated using the other three SC-CO2 estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SC-CO2 estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of SO2 and 

NOX. The range reflects the use of concentration-response 

functions from different epidemiology studies. The co-benefits 

do not include the benefits of reductions in directly emitted 

PM2.5. These additional benefits would increase overall benefits 

by a few percent based on the analyses conducted for the 

proposed rule. The reduction in premature fatalities each year 

accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 
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final guidelines and a discount rate of approximately 5 percent. 

This estimate includes monitoring, recordkeeping, and reporting 

costs and demand-side energy efficiency program and participant 

costs. 

e The estimates of net benefits in this summary table are 

calculated using the global SC-CO2 at a 3 percent discount rate 

(model average). The RIA includes combined climate and health 

estimates based on additional discount rates. 

Table 22. Summary of the Monetized Benefits, Compliance Costs, 

and Net Benefits for the Final Guidelines in 2020, 2025 and 2030 

Under the Mass-Based Illustrative Plan Approach [Billions of 

2011$]a

 Mass-Based Approach 

2020 2025 2030

Climate 

Benefitsb 

5% discount 

rate $0.9 $3.6 $6.4 

3% discount 

rate $3.3 $12 $20 

2.5% 

discount 

rate 

$4.9 $17 $29 

95th 

percentile 

at 3% 

discount 

rate 

$9.7 $35 $60 

Air Quality Co-benefits Discount Rate 
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3% 7% 3% 7% 3% 7% 

Air Quality 

Health Cobenefitsc

$2.0 to $4.8 

$1.8 

to 

$4.4 

$7.1 

to 

$17 

$6.5 

to 

$16 

$12 

to 

$28

$11 

to 

$26

Compliance 

Costsd $1.4 $3.0 $5.1 

Net 

Benefitse $3.9 to $6.7 

$3.7 

to 

$6.3 

$16 

to 

$26 

$15 

to 

$24 

$26 

to 

$43

$25 

to 

$40

NonMonetized 

Benefits 

Non-monetized climate benefits 

 3% Discount rate 

7% 

Discount 

rate 

Climate benefits b $[X] 

Air pollution 

health co-benefits 

c

$[X] to $[X] $[X] to 

$[X] 

Total Compliance 

Costs d $[X] $[X] 

Net Monetized 

Benefits e $[X] to $[X] $[X] to 

$[X] 

Non-monetized 

Benefits Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and SO2

Reductions in mercury 

deposition 

Reductions in mercury deposition 

Ecosystem benefits associated with reductions in 

emissions of NOX, SO2, PM, and mercury 

Visibility impairment 

Final Guidelines, 2030 

Climate benefits b $[X] 

Air pollution 

health co-benefits 

c

$[X] to $[X] $[X] to 

$[X] 
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Total Compliance 

Costs d $[X] $[X] 

Net Monetized 

Benefits e $[X] to $[X] $[X] to 

$[X] 

Non-monetized 

Benefits 

Non-monetized climate 

benefits 

Reductions in exposure to 

ambient NO2 and SO2

Reductions in mercury 

deposition 

Ecosystem benefits 

associated with reductions 

in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

a All are rounded to two significant figures, so figures may not 

sum. 

b The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to SC-CO2 than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 

average SC-CO2 estimated for a 3 percent discount rate, however 

we emphasize the importance and value of considering the full 

range of SC-CO2 values. As shown in the RIA, climate benefits are 

also estimated using the other three SC-CO2 estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SC-CO2 estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

final guidelines and a discount rate of approximately 5 percent. 

This estimate includes monitoring, recordkeeping, and reporting 
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costs and demand-side energy efficiency program and participant 

costs. 

e The estimates of net benefits in this summary table are 

calculated using the global SC-CO2 at a 3 percent discount rate 

(model average). The RIA includes combined climate and health 

estimates based on additional discount rates. 

There are 

additional 

important 

benefits that 

the EPA could 

not monetize. 

Due to 

current data 

and modeling 

limitations, 

our estimates 

of the 

benefits from 

reducing CO2

emissions do 

not include 

important 

impacts like 

ocean 

acidification 

or potential 

tipping 

points in 

natural or 

managed 

ecosystems. 

Visibility improvement 

a All are rounded to two significant figures, so figures may not 

sum. 

b The climate benefit estimate in this summary table reflects 

global impacts from CO2 emission changes and does not account for 

changes in non-CO2 GHG emissions. Also, different discount rates 

are applied to SC-CO2 than to the other estimates because CO2

emissions are long-lived and subsequent damages occur over many 

years. The benefit estimates in this table are based on the 
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Page 1956 of 2153

average SC-CO2 estimated for a 3 percent discount rate. However, 

we emphasize the importance and value of considering the full 

range of SC-CO2 values. As shown in the RIA, climate benefits are 

also estimated using the other three SC-CO2 estimates (model 

average at 2.5 percent discount rate, 3 percent, and 5 percent; 

95th percentile at 3 percent). The SC-CO2 estimates are yearspecific and increase over time. 

c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of SO2 and 

NOX. The co-benefits do not include the benefits of reductions in 

directly emitted PM2.5. These additional benefits would increase 

overall benefits by a few percent based on the analyses 

conducted for the proposed rule. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

final guidelines and a discount rate of approximately 5 percent. 

This estimate includes monitoring, recordkeeping, and reporting 

costs and demand-side energy efficiency program and participant 

costs. 

e The estimates of net benefits in this summary table are 

calculated using the global SC-CO2 at a 3 percent discount rate 

(model average). The RIA includes combined climate and health 

estimates based on additional discount rates. 

There are additional important benefits that the EPA could not 

monetize. Due to current data and modeling limitations, our 

estimates of the benefits from reducing CO2 emissions do not 

include important impacts like ocean acidification or potential 

tipping points in natural or managed ecosystems. Unquantified 
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benefits also include climate benefits from reducing emissions 

of non-CO2 greenhouse gases (e.g., nitrous oxide and methane)1417

and co-benefits from reducing direct exposure to SO2, NOxNOX and 

hazardous air pollutants (e.g., mercury and hydrogen chloride), as well 

as from reducing ecosystem effects and visibility impairment. 

Based upon the foregoing discussion, it remains clear that the 

benefits of this final action are substantial, and far exceed 

the costs. Additional details on benefits, costs, and net 

benefits estimates are provided in this RIA.

B. Paperwork Reduction Act (PRA)

 The information collection requirements in this rule have 

been submitted for approval to OMB under the PRA. The 

Information Collection Request (ICR) document prepared by the 

EPA has been assigned the EPA ICR number 2503.02. You can find a 

copy of the ICR in the docket for this rule, and it is briefly 

summarized here. The information collection requirements are not 

enforceable until OMB approves them. 

 

1417 Although CO2 is the predominant greenhouse gas released by 

the power sector, electricity generating units also emit small 

amounts of nitrous oxide and methane. For more detail about 

power sector emissions, see RIA Chapter 2 and the U.S. 

Greenhouse Gas Reporting Program’s power sector summary, 

http://www.epa.gov/ghgreporting/ghgdata/reported/powerplants.htm

l.
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This rule does not directly impose specific requirements on 

EGUs located in states, U.S. territories or areas of Indian 

country. The rule also does not impose specific requirements on 

tribal governments that have affected EGUs located in their area 

of Indian country. For areas of Indian country, the rule 

establishes CO2 emission performance goals that could be 

addressed through either tribal or federal plans. A tribe would 

have the opportunity under the Tribal Authority Rule (TAR,), but 

not the obligation, to apply to the EPA for Treatment as State 

(TAS) for purposes of a CAA section 111(d) plan and, if approved 

by the EPA, to establish a CAA section 111(d) plan for its area 

of Indian country. To date, no tribe has requested or obtained 

TAS eligibility for purposes of a CAA section 111(d) plan. For 

areas of Indian country with affected EGUs where a tribe has not 

applied for TAS and submitted any needed plan, if the EPA 

determines that a CAA section 111(d) plan is necessary or 

appropriate, the EPA would have the responsibility to establish 

the plans. Because tribes are not required to implement section 

111(d) plans and because no tribe has yet sought TAS eligibility 

for this purpose, this action is not anticipated to impose any 

information collection burden on tribal governments over the 3-

year period covered by this ICR. 
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This rule does impose specific requirements on state and 

U.S. territory governments with affected EGUs. The information 

collection requirements are based on the recordkeeping and 

reporting burden associated with developing, implementing, and 

enforcing a plan to limit CO2 emissions from existing sources in 

the utility power sector. These recordkeeping and reporting 

requirements are specifically authorized by CAA section 114 (42 

U.S.C. 7414). All information submitted to the EPA pursuant to 

the recordkeeping and reporting requirements for which a claim 

of confidentiality is made is safeguarded according to agency 

policies set forth in 40 CFR part 2, subpart B. 

The annual burden for this collection of information for 

the states (averaged over the first 3 years following 

promulgation) is estimated to be a range of 529505,000 to 

859821,000 hours at a total annual labor cost of $37.435.8 to 

$60.858.1 million. The lower bound estimate reflects the 

assumption that some states already have energy efficiency and 

renewable energy programs in place. The higher bound estimate 

reflects the overly-conservative assumption that no states have 

energy efficiency and renewable energy programs in place. 

The annual burden for this collection of information for 

the two affected U.S. territories, i.e., Puerto Rico and Guam, 

(averaged over the first 3 years following promulgation of this 
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action) is estimated to be 23,700 to 38,200 hours at a total 

annual labor cost of $1.68 to $2.71 million. 

The total annual burden for the federal government 

associated with the state collection of information (averaged 

over the first 3 years following promulgation) is estimated to 

be 54,901000 hours at a total annual labor cost of $3.0400

million. The total annual burden for the federal government 

associated with the territorial collection of information 

(averaged over the first 3 years following promulgation) is 

estimated to be 2,600 hours at a total annual labor cost of 

$145,000. Burden is defined at 5 CFR 1320.3(b). 

An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR 

part 9. When OMB approves this ICR, the agency will announce 

that approval in the Federal Register and publish a technical 

amendment to 40 CFR part 9 to display the OMB control number for 

the approved information collection activities contained in this 

final rule. 

C. Regulatory Flexibility Act (RFA) 

I certify that this action will not have a significant 

economic impact on a substantial number of small entities under 
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the RFA. This action will not impose any requirements on small 

entities. Specifically, emission guidelines established under 

CAA section 111(d) do not impose any requirements on regulated 

entities and, thus, will not have a significant economic impact 

upon a substantial number of small entities. After emission 

guidelines are promulgated, states and U.S. territories

establish emission standards on existing sources, and it is 

those requirements that could potentially impact small entities. 

Our analysis here is consistent with the analysis of the 

analogous situation arising when the EPA establishes NAAQS, 

which do not impose any requirements on regulated entities. As 

here, any impact of a NAAQS on small entities would only arise 

when states take subsequent action to maintain and/or 

achieve the NAAQS through their state implementation plans. See 

American Trucking Assoc. v. EPA, 175 F.3d 1029, 1043-45 (D.C. 

Cir. 1999) (NAAQS do not have significant impacts upon small 

entities because NAAQS themselves impose no regulations upon 

small entities). 

Nevertheless, the EPA is aware that there is substantial 

interest in the rule among small entities and, as detailed in 

section III.A of the preamble to the proposed carbon pollution 

emission guidelines for existing EGUs (79 FR 34845-34847; June 

18, 2014) and in section II.D of the preamble to the proposed 
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carbon pollution emission guidelines for existing EGUs in Indian 

Country and U.S. Territories (79 FR 65489; November 4, 2014), 

has conducted an unprecedented amount of stakeholder outreach. 

As part of that outreach, agency officials participated in many 

meetings with individual utilities and electric utility 

associations, as well as industry leaders and trade association 

representatives from various industries. While formulating the 

provisions of the rule, the EPA considered the input provided 

over the course of the stakeholder outreach as well as the input 

provided in the many public comments. 

D. Unfunded Mandates Reform Act (UMRA) 

This action does not contain an unfunded mandate of $100 

million or more as described in UMRA, 2 U.S.C. 1531–1538, and does 

not significantly or uniquely affect small governments. The 

emission guidelines do not impose any direct compliance 

requirements on EGUs located in states, U.S. territories or areas 

of Indian country. As explained in section XII.B above, the rule 

also does not impose specific requirements on tribal governments 

that have affected EGUs located in their area of Indian country. 

The rule does impose specific requirements on state and U.S. 

territory governments that have affected EGUs. Specifically, 

states and U.S. territories are required to develop plans to 

implement the guidelines under CAA section 111(d) for affected 
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EGUs. The burden for states and U.S. territories to develop CAA 

section 111(d) plans in the 3-year period following promulgation 

of the rule was estimated and is listed in section XII.B above, 

but this burden is estimated to be below $100 million in any one 

year. Thus, this rule is not subject to the requirements of 

section 202 or section 205 of the UMRA. 

This rule is also not subject to the requirements of 

section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments. Specifically, the state and U.S. territory

governments to which rule requirements apply are not considered 

small governments. 

In light of the interest among governmental entities, the 

EPA conducted outreach with national organizations representing 

state and local elected officials and U.S. territory and tribal 

governmental entities while formulating the provisions of this 

rule. Sections III.A and XI.F of the preamble to the proposed 

carbon pollution emission guidelines for existing EGUs (79 FR 

34845-34847; June 18, 2014) and sections II.D and VI.F of the 

preamble to the proposed carbon pollution emission guidelines 

for existing EGUs in areas of Indian Country and U.S. 

Territories (79 FR 65489; November 4, 2014) describes the 

extensive stakeholder outreach the EPA has conducted on setting 
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emission guidelines for existing EGUs. The EPA considered the 

input provided over the course of the stakeholder outreach as 

well as the input provided in the many public comments when 

developing the provisions of these emission guidelines. 

E. Executive Order 13132: Federalism 

 The EPA has concluded that this action may have 

federalism implications, pursuant to agency policy for 

implementing the Order, because it imposes substantial direct 

compliance costs on state or local governments, and the federal 

government will not provide the funds necessary to pay those 

costs. As discussed in the Supporting Statement found in the 

docket for this rulemaking, the development of state plans will 

entail many hours of staff time to develop and coordinate 

programs for compliance with the rule, as well as time to work 

with state legislatures as appropriate, to develop a plan 

submittal. Consistent with this determination, the EPA provides 

the following federalism summary impact statement.

The EPA consulted with state and local officials early in 

the process of developing the proposed action to permit them to 

have meaningful and timely input into its development. As 

described in the Federalism discussion in the preamble to the 

proposed standards of performance for GHG emissions from new 

EGUs (79 FR 1501; January 8, 2014), the EPA consulted with state 
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and local officials in the process of developing the proposed 

standards for newly constructed EGUs. This outreach addressed 

planned actions for new, reconstructed, modified and existing 

sources. The EPA invited the following 10 national organizations 

representing state and local elected officials to a meeting on 

April 12, 2011, in Washington DC: (1) National Governors 

Association; (2) National Conference of State Legislatures, (3) 

Council of State Governments, (4) National League of Cities, (5) 

U.S. Conference of Mayors, (6) National Association of Counties, 

(7) International City/County Management Association, (8) 

National Association of Towns and Townships, (9) County 

Executives of America, and (10) Environmental Council of States. 

The National Association of Clean Air Agencies also 

participated. On February 26, 2014, the EPA re-engaged with 

those governmental entities to provide a pre-proposal update on 

the emission guidelines for existing EGUs and emission standards 

for modified and reconstructed EGUs. In addition, as described 

in section III.A of the preamble to the proposed carbon 

pollution emission guidelines for existing EGUs (79 FR 34845-

34847; June 18, 2014), extensive stakeholder outreach conducted 

by the EPA allowed state leaders, including governors, state 

attorneys general, environmental commissioners, energy officers, 

public utility commissioners, and air directors, opportunities 
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to engage with EPA officials and provide input regarding 

reducing carbon pollution from power plants. 

In the spirit of Executive Order 13132, and consistent with 

the EPA’s policy to promote communications between the EPA and 

state and local governments, the EPA specifically solicited 

comment on the proposed action from state and local officials. 

The EPA received comments from over 400 entities representing 

state and local governments. 

Several themes emerged from state and local government 

comments. Commenters raised concerns with the building blocks 

that comprise the best system of emission reduction (BSER), 

including the stringency of the building blocks, and the timing 

of achieving interim CO2 levels. They also identified the 

potential for electric system reliability issues and stranded 

assets due to the proposed timeframe for plan submittals and CO2

emission reductions. In addition, states commented on state plan 

development and implementation topics, including state plan 

approaches, early actions, trading programs, interstate 

crediting for RE, and EPA guidance and outreach. 

Commenters identified overarching concerns regarding the 

stringency of the CO2 goals and the timeframe for achieving 

reductions that encompassed the building blocks, the BSER, and 

associated timing for achievement of interim CO2 levels. State 
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commenters, in particular, identified changes to the stringency 

of the building blocks, concerns with the timeframe over which 

reductions must be achieved, and concerns with the approaches 

and measures used for the BSER. For the final rule, in response 

to stakeholder comments, the EPA has made refinements to the 

building blocks, the period of time over which measures are 

deployed, and the stringency of emission limitations that those 

measures can achieve in a practical and reasonable cost way. The 

final BSER reflects those refinements. 

To many commenters, the proposal’s 2020 compliance date, 

together with the stringency of the interim CO2 goal, bore 

significant reliability implications. In this final rule, the 

agency is addressing those concerns via adjustments to the 

compliance timeframe (an 8-year interim period that begins in 

2022) and to the approach for meeting interim CO2 emission 

performance rates (a glide path separated into three steps, 

2022-2024, 2025-2027, and 2028-2029).), as well as a more 

gradual phase in of the emission reduction expectations. These 

adjustments provide more time for planning, consultation and 

decision making in the formulation of state plans and in EGUs’ 

choices of compliance strategies. The final rule also retains 

flexibilities presented in the proposal and offers additional 

opportunities, including opportunities for trading within and 
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between states, and other multi-state compliance approaches that 

will further support electric system reliability. The EPA is 

also requiring stateseach state to consult with relevant 

ISOs/RTOs and/or planning/demonstrate in its final state that it 

has considered electric system reliability authorities 

duringissues in developing its plan development, and to document 

recommendations in their plans –- and is providing the time for 

states to do so. Even with this foundation of flexibility in 

place, these final guidelines further provide states with the 

option of proposing amendments to approved plans in the event 

that unanticipated and significant reliability challenges arise. 

Commenters provided compelling information indicating that 

it will take longer than the agency initially anticipated to 

adjust investmentsfor states to complete the tasks necessary to 

finalize a state plan, including administrative and achieve 

interim CO2 reductions.potential legislative processes.

Recognizing this, as well as the urgent need for actions to 

reduce GHG emissions, the EPA is requiring states to framemake

an initial plansubmittal by August 31September 6, 2016, and is 

allowing states two additional years to submit a final plan, if 

justified (to be submitted by August 31September 6, 2018). 

States commented on state plan development and 

implementation topics that included state plan approaches, early 
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actions being taken into account, trading programs being 

allowed, interstate crediting for RE being allowed, and guidance 

and outreach being provided by the EPA. For the state plan 

approaches, commenters expressed concerns with the proposed 

“portfolio approach” for state plans, including concerns with 

enforceability of requirements, and identified a “state 

commitment approach” with backstop measures as an option for 

state plans. In this final rule, in response to stakeholder 

comments on the portfolio approach and alternative approaches, 

the EPA is finalizing a “state measures” approach that includes 

a requirement for the inclusion of backstop measures. 

State commenters also expressed interest in the EPA 

ensuring that early actions to reduce CO2 are rewarded. In this 

final rule, states with currently existing programs and 

policies, andsupported providing incentives for states that put 

in place new programs and policies early, will be better 

positioned to achieve the CO2 goals. Measures that a state takes 

priorand utilities to 2022, or programs already in place by 

2022, that result in CO2 emission reductions during the 2022-2029 

period will contribute toward meeting both the interim and final 

CO2 emission performance rates. Thus, states with currently 

existing programs and policies, and states that put in place new 

programs and policies early, will be better positioned to 
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achieve the goals.deploy CO2-reducing investments, such as RE 

generating capacity and demand-side EE measures that are 

installed after 2012 will be eligible for use in adjusting a CO2

emission performance rate., as early as possible. The EPA 

recognizes the value of such early actions, and in this final 

rule is establishing the CEIP to provide opportunities for 

investment in RE and demand-side EE projects that deliver 

results in 2020 and/or 2021. 

Many state commenters supported the use of mass-based and 

rate-based emission trading programs in state plans, including 

interstate emission trading programs. The EPA also received a 

number of comments from states and stakeholders about the value 

of EPA support in developing and/or administering tracking 

systems to support state administration of rate-based and massbased emission trading programs. In this final rule, states may 

use trading or averaging approaches and technologies or 

strategies that are not explicitly mentioned in any of the three 

building blocks as part of their overall plans, as long as they 

achieve the required emission reductions from affected fossilfuel-fired EUGsEGUs. In addition, in response to concerns from 

states and power companies that the need for up-front interstate 

cooperation in developing mulitmulti-state plans could inhibit 

the development of interstate programs that could lower cost, 
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the final rule provides additional options to allow individual 

EGUs to use creditable out-of-state reductions to achieve 

required CO2 reductions, without the need for up-front interstate 

agreements. The EPA is committed to working with states to 

provide support for tracking of emissions and allowances or 

credits, to help implement multi-state trading or averaging 

approaches. 

In their comments, many states identified the need for the 

EPA to provide guidance, including guidance on RE and EE 

emission measurement and verification (EM&V), and to maintain 

regular contact/forums with states throughout the implementation 

process. To provide state and local governments and other 

stakeholders with an understanding of the rule requirements, and 

to provide efficiencies where possible and reduce the cost and 

administrative burden, the EPA will continue outreach throughout 

the plan development and submittal process. Outreach will 

include opportunities for states to participate in briefings, 

teleconferences, and meetings about the final rule. The EPA’s 10 

regional offices will continue to be the entry point for states, 

and tribes and territories to ask technical and policy 

questions. The agency will host (or partner with appropriate 

groups to co-host) a number of webinars about various components 

of the final rule during the first two months after the final 
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rule is issued. The EPA will use information from this outreach 

process to inform the training and other tools that will be of 

most use to the states, and tribes, and territories that are 

implementing the final rule. The EPA expects to issue guidance 

on specific topics, including evaluation, measurement and 

verification (EM&V) for RE and demand-side EE, state-community 

engagement, and resources and financial assistance for RE and 

demand-side EE. As guidance documents, tools, templates and 

other resources become available, the EPA, in consultation with 

the U.S. Department of Energy and other federal agencies, will 

continue to make these resources available via a dedicated 

website. 

A list of the state and local government commenters has 

been provided to OMB and has been placed in the docket for this 

rulemaking. In addition, the detailed response to comments from 

these entities is contained in the EPA’s response to comments 

document on this final rulemaking, which has also been placed in 

the docket for this rulemaking. 

 As required by section 8(a) of Executive Order 13132, 

the EPA included a certification from its Federalism Official 

stating that the EPA had met the Executive Order’s requirements 

in a meaningful and timely manner when it sent the draft of this 

final action to OMB for review pursuant to Executive Order 
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12866. A copy of the certification is included in the public 

version of the official record for this final action. 

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments 

This action has tribal implications. However, it will 

neither impose substantial direct compliance costs on federally 

recognized tribal governments, nor preempt tribal law. Tribes 

are not required to develop or adopt CAA programs, but they may 

apply to the EPA for treatment in a manner similar to states 

(TAS) and, if approved, do so. As a result, tribes are not 

required to develop plans to implement the guidelines under CAA 

section 111(d) for affected EGUs in their areas of Indian 

country. To the extent that a tribal government seeks and 

attains TAS status for that purpose, these emission guidelines 

would require that planning requirements be met and emission 

management implementation plans be executed by the tribes. The 

EPA notes that this rule does not directly impose specific 

requirements on affected EGUs, including those located in areas 

of Indian country, but provides guidance to any tribe approved 

by the EPA to address CO2 emissions from EGUs subject to section 

111(d) of the CAA. The EPA also notes that none of the affected 

EGUs are owned or operated by tribal governments. 

 As described in sections III.A and XI.F of the preamble to 
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the proposed carbon pollution emission guidelines for existing 

EGUs (79 FR 34845-34847; June 18, 2014) and sections II.D and 

VI.F of the preamble to the proposed carbon pollution emission 

guidelines for existing EGUs in Indian Country and U.S. 

Territories (79 FR 65489; November 4, 2014), the rule was 

developed after extensive and vigorous outreach to tribal 

governments. These tribes expressed varied points of view. Some 

tribes raised concerns about the impacts of the regulations on 

EGUs located in their areas of Indian country and the subsequent 

impact on jobs and revenue for their tribes. Other tribes 

expressed concern about the impact the regulations would have on 

the cost of water covered under treaty to their communities as a 

result of increased costs to the EGU that provide energy to 

transport the water to the tribes. Other tribes raised concerns 

about the impacts of climate change on their communities, 

resources, ways of life and hunting and treaty rights. The 

tribes were also interested in the scope of the guidelines being 

considered by the agency (e.g., over what time period, 

relationship to state and multi-state plans) and how tribes will 

participate in these planning activities. 

The EPA consulted with tribal officials under the EPA 

Policy on Consultation and Coordination with Indian Tribes early 

in the process of developing this action to permit them to have 
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meaningful and timely input into its development. A summary of 

that consultation follows. 

Prior to issuing the supplemental proposal on November 4, 

2014, the EPA consulted with tribes as follows. The EPA held a 

consultation with the Ute Tribe, the Crow Nation, and the 

Mandan, Hidatsa, Arikara (MHA) Nation on July 18, 2014. On 

August 22, 2014, the EPA held a consultation with the Fort 

Mojave Tribe. On September 15, 2014, the EPA held a consultation 

with the Navajo Nation. The Navajo Nation sent a letter to the 

EPA on September 18, 2014, summarizing the information presented 

at the consultation and the Navajo Nation’s position on the 

supplemental proposal. One issue raised by tribal officials was 

the potential impacts of the June 18, 2014 proposal and the 

supplemental proposal on tribes with budgets that are dependent 

on revenue from coal mines and power plants, as well as 

employment at the mines and power plants. The tribes noted the 

high unemployment rates and lack of access to basic services on 

their lands. Tribal officials also asked whether the rules will 

have any impact on a tribe’s ability to seek TAS. Tribal 

officials also expressed interest in agency actions with regard 

to facilitating power plant compliance with regulatory 

requirements. The Navajo Nation made the following 

recommendations in their letter of September 18, 2014: the 
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Navajo Nation supports a mass-based CO2 emission standard based 

on the highest historical CO2 emissions since 1996; the Navajo 

Nation requests that the EPA grant the Navajo Nation carbon 

credits and that the Navajo Nation retains ownership and control 

of such credits; building block 2 is not appropriate for the 

Navajo Nation because there are no NGCC plants located on the 

Navajo Nation; building block 3 is not appropriate for the 

Navajo Nation because the Navajo people already receive 

virtually all of their electricity from carbon-free sources 

(mostly hydroelectric power) and their use of electricity is 

negligible compared to the generation at the power plants; 

building block 4 is not appropriate for the Navajo Nation 

because of the inadequate access to electricity, and the goal 

should allow for an increase in energy consumption on the Navajo 

Nation; the supplemental proposal should consider the useful 

life of the power plants located on the Navajo Nation; and the 

supplemental proposal should clarify that RE projects located 

within the Navajo Nation that provide electricity outside the 

Navajo Nation should be counted toward meeting the relevant 

state’s RE goals under the Clean Power Plan. 

After issuing the supplemental proposal, the EPA held 

additional consultation with tribes. On November 18, 2014, the 

EPA held consultations with the following tribes: Fort McDowell 
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Yavapai Nation, Fort Mojave Tribe, Hopi Tribe, Navajo Nation, 

and Ak-Chin Indian Community. A consultation with the Ute Indian 

Tribe of the Uintah and Ouray Reservation was held on December 

16, 2014 and with the Gila River Indian Community on January 15, 

2015. The Navajo Nation reiterated the concerns raised during 

the previous consultation. Several tribes also again indicated 

that they wanted to ensure they would be included in the 

development of any tribal or federal plans for areas of Indian 

country. The Fort Mojave Tribe and the Navajo Nation expressed 

concern with using data from 2012 as the basis for the goal for 

their areas of Indian country; in their view, that year was not 

representative for the affected EGU. On April 28, 2015, the EPA 

held an additional consultation with the Navajo Nation. The 

issues raised by the Navajo Nation during the consultation 

included whether the EPA has the authority to set less stringent 

standards on a case-by-case basis, and a suggested “parity glide 

path” that would account and adjust for the very low electricity 

usage by the Navajo Nation and promote Navajo Nation economic 

growth and demand.

 Furthermore, on July 7, 2015 the EPA conducted an 

additional consultation with the Navajo Nation. One of the goals 

of the consultation was for the new government of the Navajo 

Nation to deepen their understanding of the rulemaking. The 
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questions raised by the nation had to do with goal setting and 

carbon credits, the timing of the rulemaking, and the proposed 

federal plan. Additionally, on July 14, 2015 the EPA conducted 

an additional consultation with the Fort Mojave Tribe. The Fort 

Mojave tribes expressed concerns that 2012 is not a 

representative year, that natural gas-fired combined cycle power 

plants should be treated differently from coal-fired power 

plants, and that the proposed goal for Fort Mojave was not 

appropriate. Additionally, they also expressed interest in being 

engaged in the federal plan process. Responses to these comments 

and others received are available in the Response to Comment 

Document that is in the docket for this rulemaking. As required 

by section 7(a), the 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 Risks and Safety Risks 

This action is subject to Executive Order 13045 (62 FR 

19885, April 23, 1997) because it is an economically significant 

regulatory action as defined by Executive Order 12866, and the 

EPA believes that the environmental health or safety risk 

addressed by this action has a disproportionate effect on 
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children. Accordingly, the agency has evaluated the 

environmental health and welfare effects of climate change on 

children. 

CO2 is a potent greenhouse gas that contributes to climate 

change and is emitted in significant quantities by fossil fuelfired power plants. The EPA believes that the CO2 emission 

reductions resulting from implementation of these final 

guidelines, as well as substantial ozone and PM2.5 emission 

reductions as a co-benefit, will further improve children’s 

health. 

The assessment literature cited in the EPA’s 2009 

Endangerment Finding concluded that certain populations and 

lifestages, including children, the elderly, and the poor, are 

most vulnerable to climate-related health effects. The 

assessment literature since 2009 strengthens these conclusions 

by providing more detailed findings regarding these groups’ 

vulnerabilities and the projected impacts they may experience. 

These assessments describe how children’s unique 

physiological and developmental factors contribute to making 

them particularly vulnerable to climate change. Impacts to 

children are expected from heat waves, air pollution, infectious 

and waterborne illnesses, and mental health effects resulting 

from extreme weather events. In addition, children are among 
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those especially susceptible to most allergic diseases, as well 

as health effects associated with heat waves, storms, and 

floods. Additional health concerns may arise in low income 

households, especially those with children, if climate change 

reduces food availability and increases prices, leading to food 

insecurity within households. 

More detailed information on the impacts of climate change 

to human health and welfare is provided in section II.A of this 

preamble. 

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use 

This action, which is a significant regulatory action under 

EO 12866, is likely to have a significant effect on the supply, 

distribution, or use of energy. The EPA has prepared a Statement 

of Energy Effects for this action as follows. We estimate a [X]1

to [X]2 percent change in retail electricity prices on average 

across the contiguous U.S. in [20XX],2025, and a [X]22 to [X]23

percent reduction in coal-fired electricity generation as a 

result of this rule. The EPA projects that utility power sector 

delivered natural gas prices will increase/decrease by about 

[X]up to [X]2.5 percent in [20XX].2030. For more information on 

the estimated energy effects, please refer to the economic 
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impact analysis for this proposal. The analysis is available in 

the RIA, which is in the public docket. 

I. National Technology Transfer and Advancement Act (NTTAA) 

This rulemaking does not involve technical standards. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

Executive Order 12898 (59 FR 7629; February 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 populations and low-income populations in 

the U.S. The EPA defines environmental justice as the fair 

treatment and 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. The EPA has this goal for all 

communities and persons across this Nation. It will be achieved 

when everyone enjoys the same degree of protection from 

environmental and health hazards and equal access to the 
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decision-making process to have a healthy environment in which 

to live, learn, and work. 

Leading up to this rulemaking the EPA summarized the public 

health and welfare effects of GHG emissions in its 2009 

Endangerment Finding. See, section VIII.A of this preamble where 

the EPA summarizes the public health and welfare impacts from 

GHG emissions that were detailed in the 2009 Endangerment 

Finding under CAA section 202(a)(1).1418 As part of the 

Endangerment Finding, the Administrator considered climate 

change risks to minority populations and low-income populations, 

finding that certain parts of the population may be especially 

vulnerable based on their characteristics or circumstances. 

Populations that were found to be particularly vulnerable to 

climate change risks include the poor, the elderly, the very 

young, those already in poor health, the disabled, those living 

alone, and/or indigenous populations dependent on one or a few 

resources. See sections XII.F and XII.G, above, where the EPA 

discusses Consultation and Coordination with Tribal Governments 

and Protection of Children. The Administrator placed weight on 

the fact that certain groups, including children, the elderly, 

 

1418 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases Under Section 202(a) of the Clean Air Act,” 74 Fed. Reg. 

66,496FR 66496 (Dec. 15, 2009) (“Endangerment Finding”). 
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and the poor, are most vulnerable to climate-related health 

effects. 

The record for the 2009 Endangerment Finding summarizes the 

strong scientific evidence in the major assessment reports by 

the U.S. Global Change Research Program (USGCRP), the 

Intergovernmental Panel on Climate Change (IPCC), and the 

National Research Council (NRC) of the National Academies that 

the potential impacts of climate change raise environmental 

justice issues. These reports concluded that poor communities 

can be especially vulnerable to climate change impacts because 

they tend to have more limited adaptive capacities and are more 

dependent on climate-sensitive resources such as local water and 

food supplies. In addition, Native American tribal communities 

possess unique vulnerabilities to climate change, particularly 

those impacted by degradation of natural and cultural resources 

within established reservation boundaries and threats to 

traditional subsistence lifestyles. Tribal communities whose 

health, economic well-being, and cultural traditions that depend 

upon the natural environment will likely be affected by the 

degradation of ecosystem goods and services associated with 

climate change. The 2009 Endangerment Finding record also 

specifically noted that Southwest native cultures are especially 

vulnerable to water quality and availability impacts. Native 
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Alaskan communities are already experiencing disruptive impacts, 

including coastal erosion and shifts in the range or abundance 

of wild species crucial to their livelihoods and well-being. 

The most recent assessments continue to strengthen 

scientific understanding of climate change risks to minority 

populations and low-income populations in the United States.1419

The new assessment literature provides more detailed findings 

regarding these populations’ vulnerabilities and projected 

impacts they may experience. In addition, the most recent 

assessment reports provide new information on how some 

communities of color (more specifically, populations defined 

 

1419 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 

Eds., 2014: Climate Change Impacts in the United States: The 

Third National Climate Assessment. U.S. Global Change Research 

Program, 841 pp. 

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part A: Global and Sectoral Aspects. Contribution 

of Working Group II to the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change [Field, C.B., V.R. 

Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. 

Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. 

Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, 1132 pp. 

IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part B: Regional Aspects. Contribution of Working 

Group II to the Fifth Assessment Report of the Intergovernmental 

Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, 

M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. 

Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 

Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 

Cambridge University Press, 688 pp.
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jointly by ethnic/racial characteristics and geographic 

location) may be uniquely vulnerable to climate change health 

impacts in the United States. These reports find that certain 

climate change related impacts—including heat waves, degraded 

air quality, and extreme weather events—have disproportionate 

effects on low-income populations and some communities of color, 

raising environmental justice concerns. Existing health 

disparities and other inequities in these communities increase 

their vulnerability to the health effects of climate change. In 

addition, assessment reports also find that climate change poses 

particular threats to health, well-being, and ways of life of 

indigenous peoples in the United States. 

As the scientific literature presented above and as the 

2009 Endangerment Finding illustrates, low income populations 

and some communities of color are especially vulnerable to the 

health and other adverse impacts of climate change. The EPA 

believes that communities will benefit from this final 

rulemaking because this action directly addresses the impacts of 

climate change by limiting GHG emissions through the 

establishment of CO2 emission guidelines for existing affected 

fossil fuel-fired EGUs. 

In addition to reducing CO2 emissions, the guidelines 

finalized in this rulemaking would reduce other emissions from 
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affected EGUs that reduce generation due to higher adoption of 

energy efficiency and renewable energy. These emission 

reductions will include SO2 and NOx, which form ambient PM2.5 and 

ozone in the atmosphere, and hazardous air pollutants (HAP), 

such as mercury and hydrochloric acid. In the final rule 

revising the annual PM2.5 NAAQS,1420 the EPA identified low-income 

populations as being a vulnerable population for experiencing 

adverse health effects related to PM exposures. Low-income 

populations have been generally found to have a higher 

prevalence of pre-existing diseases, limited access to medical 

treatment, and increased nutritional deficiencies, which can 

increase this population’s risksusceptibility to PM-related and 

ozone-related effects.1421 Therefore, inIn areas where this 

rulemaking reduces exposure to PM2.5, ozone, and methylmercury, 

low-income populations will also benefit from such emissions 

reductions. The RIA for this rulemaking, included in the docket 

for this rulemaking, provides additional information regarding 

 

1420 “National Ambient Air Quality Standards for Particulate 

Matter, Final Rule,” 78 FR 3086 (Jan. 15, 2013). 

1421 U.S. Environmental Protection Agency (U.S. EPA). 2009. 

Integrated Science Assessment for Particulate Matter (Final 

Report). EPA-600-R-08-139F. National Center for Environmental 

Assessment – RTP Division. December. Available on the Internet 

at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.
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the health and ecosystem effects associated with these emission 

reductions. 

Additionally, as outlined in the community and 

environmental justice considerations section IX of this 

preamble, the EPA has puttaken a number of conditions in 

placeactions to help ensure that this action will not have 

potential disproportionately high and adverse human health or 

environmental effects on alloverburdened communities (low 

income, communities . The EPA consulted its May 2015, Guidance 

on Considering Environmental Justice During the Development of 

color).Regulatory Actions, when determining what actions to 

take.1422 As described in the community and environmental justice 

considerations section of this preamble the EPA also conducted a 

proximity analysis, which is available in the docket of this 

rulemaking and is discussed in section IX. Additionally, as 

outlined in sections I and IX of this preamble, the EPA has 

engaged with communities throughout this rulemaking and has 

devised a robust outreach strategy for continual engagement 

throughout the implementation phase of this rulemaking.

K. Congressional Review Act (CRA) 

 

1422 Guidance on Considering Environmental Justice During the 

Development of Regulatory Actions. 

http://epa.gov/environmentaljustice/resources/policy/considering

-ej-in-rulemaking-guide-final.pdf. May 2015. 
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 This final action is subject to the CRA, and the EPA will 

submit a rule report to each House of the Congress and to the 

Comptroller General of the United States. This action is a 

“major rule” as defined by 5 U.S.C. 804(2). 

XIII. Statutory Authority 

The statutory authority for this action is provided by 

sections 111, 301, 302, and 307(d)(1)(C) of the CAA as amended 

(42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This action is also 

subject to section 307(d) of the CAA (42 U.S.C. 7607(d)).
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Carbon Pollution 

Emission Guidelines for Existing Stationary Sources: Electric 

Utility Generating Units 

Page 1989 of 2153

List of Subjects in 40 CFR Part 60 

Environmental protection, Administrative practice and 

procedure, Air pollution control, Intergovernmental relations, 

Reporting and recordkeeping requirements. 

___________________ 

Dated: ___________________.

____________________ 

Gina McCarthy, 

Administrator.

 
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Carbon Pollution 

Emission Guidelines for Existing Stationary Sources: Electric 

Utility Generating Units 

Page 1990 of 2153
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Page 1991 of 2153

For the reasons stated in the preamble, title 40, chapter I, 

part 60 of the Code of the Federal Regulations is amended as 

follows: 

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES 

1. The authority citation for Part 60 continues to read as 

follows: 

Authority: 42 U.S.C. 7401 et seq.

2. Add subpart UUUU to read as follows:

Subpart --UUUU: Emission Guidelines for Greenhouse Gas Emissions 

and Compliance Times for Electric Utility Generating Units 

Sec. 

Introduction 

60.5700 What is the purpose of this subpart? 

60.5705 WhatWhich pollutants are regulated by this subpart? 

60.5710 Am I affected by this subpart? 

60.5715 What is the review and approval process for my 

stateState plan? 

60.5720 What if I do not submit a plan or my plan is not 

approvable? 

60.5725 In lieu of a stateState plan submittal, are there 

other acceptable option(s) for a stateState to meet 

its section 111(d) obligations? 

60.5730 Is there an approval process for a negative 

declaration letter? 

60.5735 What authorities will not be delegated to stateState, 

local, or tribal agencies? 

60.5736 Will the EPA impose any sanctions? 

60.5737 What is the Clean Energy Incentive Program and how do 

I participate? 

State and Multi-stateState Plan Requirements 

60.5740 What must I include in my federally enforceable State 

or multi-State plan? 

60.5745 What must I include in my final plan submittal? 

60.5750 Can I work with other statesStates to develop a multistateState plan? 

60.5755 Can I include existing requirements, programs, and 
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Page 1992 of 2153

measures in my plan? 

60.5760 What are the timing requirements for submitting my 

plan? 

60.5765 What must I include in an initial plan submittal in 

lieu ofif requesting an extension for a final plan 

submittal? 

60.5770 What schedules, performance periods, and compliance 

periods must I include in my plan? 

60.5775 What emission standards must I include in my plan? 

60.5780 What stateState measures may I includerely upon in 

support of my plan? 

60.5785 What is the procedure for revising my plan? 

60.5790 What must I do to meet my plan obligations? 

Emission Rate Credit Requirements

60.57915795 What Emission Rate Creditsaffected EGUs qualify 

for use in my state plan?generation of ERCs? 

60.5792 How can an affected EGU use an ERC for demonstrating 

compliance5800 What other resources qualify for 

issuance of ERCs? 

60.57935805 What is a qualified state ERC the process for the 

issuance of ERCs? 

60.5810 What applicable requirements are there for an ERC 

tracking system?

60.5795 

Mass Allocations Requirements 

60.5815 What are the requirements for State allocation of 

allowances in a mass-based program? 

60.5820 What are my allowance tracking requirements? 

60.5825 What is the process for affected EGUs to demonstrate 

compliance in a mass-based program? 

Evaluation Measurement and Verification Plans and Monitoring and 

Verification Reports 

60.5830 What are the requirements for EM&V plans for eligible 

resources? 

60.57965835 What are the requirements for a post-project ERC 

verification assurance plan? 

60.5797 What standards must the independent third party 

verifier meetM&V reports for eligible resources? 

Applicability of Plans to Affected EGUs

60.58005840 Does this subpart directly affect EGU owners and 

operators in my stateState? 

60.58055845 What affected EGUs must I address in my 

stateState plan? 
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60.58105850 What affected EGUs are exemptexcluded from my 

state plan?being affected EGUs? 

60.58155855 What are the CO2 emission performance rates for 

affected EGUs? 

60.58205860 What applicable monitoring, recordkeeping, and 

reporting requirements do I need to include in my 

state plan for affected EGUs? 

Recordkeeping and Reporting Requirements 

60.58255865 What are my state recordkeeping requirements? 

60.58305870 What are my state reporting and notification 

requirements? 

60.58355875 How do I submit information required by these 

Emission Guidelinesemission guidelines to the EPA? 

Definitions 

60.58405880 What definitions apply to this subpart? 

Table 1 to Subpart UUUU of Part 60—CO2 Emission Performance Rates 

(Pounds of CO2 Perper Net MWh) 

Table 2 to Subpart UUUU of Part 60—Statewide Rate-based CO2

Emission Goals (Pounds of CO2 Perper Net MWh) 

Table 3 to Subpart UUUU of Part 60—Statewide Mass-based CO2

Emission Goals (Tons of CO2) 

Table 3 to Subpart UUUU of Part 60—Statewide Mass-based CO2

Emission Goals (Short Tons of CO2) 

Table 4 to Subpart UUUU of Part 60—Statewide Mass-based CO2

Emission Goals plus New Source CO2 Emission Complement 

(Short Tons of CO2) 

Introduction 

§ 60.5700 What is the purpose of this subpart?

 This subpart establishes emission guidelines and approval 

criteria for stateState or multi-stateState plans that establish 

emission standards limiting greenhouse gas (GHG) emissions from 

an affected steam generating unit, integrated gasification 
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combined cycle (IGCC), or stationary combustion turbine. An 

affected steam generating unit, IGCC, or stationary combustion 

turbine shall, for the purposes of this subpart, be referred to 

as an affected EGU. These emission guidelines are developed in 

accordance with sections 111(d) of the Clean Air Act and subpart 

B of this part. To the extent any requirement of this subpart is 

inconsistent with the requirements of subparts A or B of this 

part, the requirements of this subpart will apply. 

§ 60.5705 WhatWhich pollutants are regulated by this subpart? 

 (a) The pollutants regulated by this subpart are greenhouse 

gases. The emission guidelines for greenhouse gases established 

in this subpart are expressed as carbon dioxide (CO2) emission 

performance rates and equivalent statewide CO2 emission goals.

(b) ThePSD and Title V Thresholds for Greenhouse 

Gases. 

(1) For the purposes of §51.166(b)(49)(ii), with 

respect to GHG emissions from facilities, the “pollutant 

that is subject to the standard promulgated under section 

111 of the Act” shall be considered to be the pollutant 

that otherwise is subject to regulation under the Act as 

defined in §51.166(b)(48) and in any State Implementation 

Plan (SIP) approved by the EPA that is interpreted to 

incorporate, or specifically incorporates, §51.166(b)(48) 

of this chapter. 
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(2) For the purposes of §52.21(b)(50)(ii), with 

respect to GHG emissions from facilities regulated in the 

plan, the “pollutant that is subject to the standard 

promulgated under section 111 of the Act” shall be 

considered to be the pollutant that otherwise is subject to 

regulation under the Act as defined in §52.21(b)(49) of 

this chapter. 

(3) For the purposes of §70.2 of this chapter, with respect 

to greenhouse gas regulated by this subpart is carbon dioxide 

(CO2).emissions from facilities regulated in the plan, the 

“pollutant that is subject to any standard promulgated under 

section 111 of the Act” shall be considered to be the pollutant 

that otherwise is "subject to regulation" as defined in §70.2 of 

this chapter.

§ (4) For the purposes of §71.2, with respect to greenhouse 

gas emissions from facilities regulated in the plan, the 

“pollutant that is subject to any standard promulgated under 

section 111 of the Act” shall be considered to be the pollutant 

that otherwise is "subject to regulation" as defined in §71.2 of 

this chapter. 

§60.5710 Am I affected by this subpart? 

 If you are the Governor of a stateState in the contiguous 

United States with one or more affected EGUs that commenced 

construction on or before January 8, 2014, you must submit a 
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Page 1996 of 2153

stateState or multi-stateState plan to the U.S. Environmental 

Protection Agency (EPA) that implements the emission guidelines 

contained in this subpart. You must submit a negative 

declaration letter in place of the state plan if there areIf you 

are the Governor of a State in the contiguous United States with

no affected EGUs for which construction commenced on or before 

January 8, 2014, in your stateState, you must submit a negative 

declaration letter in place of the State plan. 

§ 60.5715 What is the review and approval process for my plan? 

The EPA will review your plan according to § 60.27 except 

that under § 60.27(b) the Administrator will have twelve12

months after the date the final plan or plan revision (as 

allowed under § 60.5795) is submitted, to approve or disapprove 

such plan or revision or each portion thereof. If you submit an 

initial plan submittal under § 60.5765(a) in lieu of a final 

plan submittal the EPA will follow the procedure in §

60.5765(b). 

§ 60.5720 What if I do not submit a plan or my plan is not 

approvable? 

(a) If you do not submit an approvable plan the EPA will 

develop a Federal plan for your stateState according to § 60.27 

except that under § 60.27(d) the EPA will have one year to 

promulgate a Federal plan for your stateState from the date EPA 

finds you failed to submit a plan or EPA disapproves your plan. 
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The Federal plan will implement the emission guidelines 

contained in this subpart. Owners and operators of affected EGUs 

not covered by an approved plan must comply with a Federal plan 

implemented by the EPA for the stateState. 

(b) After a Federal plan has been implemented in your 

stateState, it will be withdrawn when your stateState submits, 

and the EPA approves, a final plan prior to the beginning of the 

interim period on January 1, 2022. If a federal plan is in place 

during the interim period or final period and a state submits 

and EPA approves a plan, the federal plan will not be withdrawn 

until the end of the performance period that is at that time in 

place (e.g., at the end of an interim step so that the state 

plan goes into effect at the beginning of a new interim step).. 

§ 60.5725 In lieu of a stateState plan submittal, are there 

other acceptable option(s) for a stateState to meet its CAA 

section 111(d) obligations? 

 A stateState may meet its CAA section 111(d) obligations 

only by submitting a final stateState or multi-stateState plan 

submittal or a negative declaration letter (if applicable). 

§ 60.5730 Is there an approval process for a negative 

declaration letter? 

No. The EPA has no formal review process for negative 

declaration letters. Once your negative declaration letter has 

been received, the EPA will place a copy in the public docket 
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and publish a notice in the FEDERAL REGISTER. If, at a later date, 

an affected EGU for which construction commenced on or before 

January 8, 2014 is found in your stateState, you will have been 

found to have failed to submit a final plan as required, and a 

Federal plan implementing the emission guidelines contained in 

this subpart will apply to that affected EGU until you submit, 

and the EPA approves, a final stateState plan. 

§ 60.5735 What authorities will not be delegated to stateState, 

local, or tribal agencies?

The authorities that will not be delegated to State, local, 

or tribal agencies are specified in paragraphparagraphs (a) and 

(b) of this section. 

(a) Approval of alternatives, not already approved by this 

subpart, to the CO2 emissionsemission performance rates in Table 

1 to this subpart established under § 60.58155855. 

(b) Approval of alternatives, not already approved by this 

subpart, to the CO2 emissions goals in Tables 2, 3 and 34 to this 

subpart established under § 60.58155855. 

§ 60.5736 Will the EPA impose any sanctions? 

The EPA will not exercisewithhold any authority it may have 

to impose sanctions under the Clean Air Act, 42 U.S.C. §§ 

7410(m), 7509, existing federal funds from a State on states for 

failingaccount of a State’s failure to submit, implement, or 
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Page 1999 of 2153

enforce an approvable plan or plan revision, or to meet any 

other requirements under this subpart or subpart B of this part. 

§60.5737 What is the Clean Energy Incentive Program and how do 

I participate? 

(a) This subpart establishes the Clean Energy Incentive 

Program (CEIP). Participation in this program is optional. The 

program enables States to award early action emission rate 

credits (ERCs) and allowances to eligible renewable energy (RE) 

or demand-side energy efficiency (EE) projects that generate 

megawatt hours (MWh) or reduce end-use energy demand during 2020 

and 2021. Eligible projects are those that: 

(1) Are located in or benefit a state that has submitted a 

final state plan that includes requirements establishing its 

participation in the CEIP; and 

(2) Commence construction in the case of RE, or commence 

operation in the case of demand-side EE, following the 

submission of a final state plan to the EPA, or after September 

6, 2018 for a state that chooses not to submit a final state 

plan by that date; and 

(3) Generate metered MWh from any type of wind or solar 

resources; or 

(4) Result in quantified and verified electricity savings 

(MWh) through demand-side EE implemented in low-income 

communities. 
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(b) The EPA will award matching ERCs or allowances to 

States that award early action ERCs or allowances, up to a limit 

equivalent to 300 million tons of CO2 emissions. The awards will 

be executed as follows: 

(1) For RE projects that generate metered MWh from wind or 

solar resources: for every two MWh generated, the project will 

receive one early action ERC (or the equivalent number of 

allowances) from the state, and the EPA will provide one 

matching ERC (or the equivalent number of allowances) to the 

state to award to the project. 

(2) For EE projects implemented in low-income communities: 

for every two MWh in end-use demand savings achieved, the 

project will receive two early action ERCs (or the equivalent 

number of allowances), and the EPA will provide two matching 

ERCs (or the equivalent number of allowances) to the state to 

award to the project. 

(c) You may participate in this program by including in 

your State plan a mechanism that enables issuance of early 

action ERCs or allowances by the State to parties effectuating 

reductions in the calendar years 2020 and 2021 in a manner that 

would have no impact on the emission performance of affected 

EGUs required to meet rate-based or mass-based emission 

standards during the performance periods. This mechanism is not 
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required to account for matching ERCs or allowances that may be 

issued to the State by the EPA. 

(d) If you are submitting an initial submittal by September 

6, 2016, you must include a non-binding statement of intent to 

participate in the program. If you are submitting a final plan 

by September 6, 2016, your State plan must either include 

requirements establishing the necessary infrastructure to 

implement such a program and authorizing its affected EGUs to 

use early action allowances or ERCs as appropriate, or you must 

include a non-binding statement of intent as part of its 

supporting documentation and revise your plan to include the 

appropriate requirements at a later date. 

(e) Your final State plan, or plan revision if applicable, 

must require that projects eligible to be awarded under this 

program be evaluated, monitored, verified, and issued per 

applicable requirements of the State plan approved by the EPA as 

meeting §60.5805 through §60.5835. 

State and Multi-stateState Plan Requirements 

§ 60.5740 What must I include in my state federally enforceable 

State or multi stateState plan include? 

(a) You must include the components described in paragraphs 

(a)(1) through (105) of this section in your plan submittal. 

These components of your plan submittal will be codified as part 

of the federally enforceable plan upon approval by EPA. The 
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final plan submittalThe final plan must meet the requirements 

and include the information required under § 60.5745. 

(1) (1) Identification of affected EGUs. Consistent with §

60.25(a), you must identify the affected EGUs covered by your 

plan and all affected EGUs in your stateState that meet the 

applicability criteria in § 60.58055845. In addition, you must 

include an inventory of CO2 emissions from the affected EGUs 

during the most recent calendar year for which data is available 

prior to the submission of the plan. 

(2) Emission standards. You must include an identification 

of all emission standards for each affected EGU according to 

§60.5775, compliance periods for each emission standard 

according to § 60.5770, and a demonstration that the emission 

standards are, when taken together, sufficiently protective to 

meetachieve the applicable CO2 emission performance rates or CO2

emission goals described in § 60.5815.60.5855. Allowance systems 

are an acceptable form of emission standards under this subpart. 

(i) IfYour plan does not need to include corrective 

measures specified in paragraph (a)(2)(ii) of this section if

your plan includes only requirements of : 

(A) Imposes emission standards on yourall affected EGUs to 

meet eitherthat, assuming full compliance by all affected EGUs, 

mathematically assure achievement of the CO2 emission performance 

rates orin the plan for each plan period; 
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(B) Imposes emission standards on all affected EGUS that, 

assuming full compliance by all affected EGUs, mathematically 

assure achievement of the CO2 emission goals, you; or 

(C) Imposes emission standards on all affected EGUs that, 

assuming full compliance by all affected EGUs, in conjunction 

with applicable requirements under state law for EGUs subject to 

subpart TTTT of this subpart, assuming the applicable 

requirements under state law are met by all EGUs subject to 

subpart TTTT of this subpart, achieve the applicable mass-based 

CO2 emission goals plus new source CO2 emission complement 

allowed for in §60.5790(b)(5). 

(ii) If your plan does not meet the requirements of 

(a)(2)(i) of this section, your plan must include in your plan 

the requirement for corrective measures to be put in place if 

there is an exceedance of an interim step or final period CO2

emission performance rate or CO2 emission goal by 10 percent or 

greater, either on average or cumulatively as 

applicable.implemented if triggered. Upon triggering corrective 

measures, if you do not already have them included in your 

approved State plan, you must submit corrective measures to EPA 

for approval as a plan revision per the requirements of 

§60.5785(c). These corrective measures must ensure that the 

interim period and final period CO2 emission performance rates or 

CO2 emission goals are achieved by your affected EGUs, as 
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applicable, and must achieve additional emission reductions to 

offset any emission performance shortfall. Your plan must 

include the requirement that corrective measures be triggered 

and implemented according to paragraphs (a)(2)(ii)(A) through 

(H) of this section. 

(ii) If your plan includes state (A) Your plan must include 

a trigger for an exceedance of an interim step 1 or interim step 

2 CO2 emission performance rate or CO2 emission goal by 10 

percent or greater, either on average or cumulatively (if 

applicable). 

(B) Your plan must include a trigger for an exceedance of 

an interim step 1 goal or interim step 2 goal of 10 percent or 

greater based on either reported CO2 emissions with applied plus 

or minus adjustments for net CO2 allowances “imports” or 

“exports” (if applicable), or based on the adjusted CO2 emission 

rate (if applicable). 

(C) Your plan must include a trigger for a failure to meet 

an interim period goal based on reported CO2 emissions with 

applied plus or minus adjustments for net CO2 allowances 

“imports” or “exports” (if applicable), or based on the adjusted 

CO2 emission rate (if applicable). 

(D) Your plan must include a trigger for a failure to meet 

the interim period or any final reporting period CO2 emission 
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Page 2005 of 2153

performance rate or CO2 emission goal, either on average or 

cumulatively (if applicable). 

(E) Your plan must include a trigger for a failure to meet 

any final reporting period goal based on reported CO2 emissions 

with applied plus or minus adjustments for net CO2 allowances 

“imports” or “exports” (if applicable). 

(F) Your plan must include a trigger for a failure to meet 

the interim period CO2 emission performance rate or CO2 emission 

goal based on the adjusted CO2 emission rate (if applicable). 

(G) Your plan must include a trigger for a failure to meet 

any final reporting period CO2 emission performance rate or CO2

emission goal based on the adjusted CO2 emission rate (if 

applicable). 

(H) A net import adjustment represents the CO2 emissions 

(in tons) equal to the number of net imported CO2 allowances. 

This adjustment is added to reported CO2 emissions. Under this 

adjustment, such allowances must be issued by a state with an 

emission budget trading program that only applies to affected 

EGUs (or affected EGUs plus EGUs covered by subpart TTTT of this 

part as applicable). A net export adjustment represents the CO2

emissions (in tons) equal to the number of net exported CO2

allowances. This adjustment is subtracted from reported CO2

emissions. 
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(iii) If your plan relies upon State measures, in addition 

to or in lieu of emission standards on your affected EGUs, then 

the final stateState plan must include the information in 

paragraph (a)(3) of this section and the submittal must include 

the information listed in § 60.5745(a)(6). 

(3iv) If your plan includes staterequires emission 

standards in addition to relying upon State measures, then you 

must demonstrate that the emission standards and State measures 

are, when taken together, results in the achievement of to meet 

the applicable mass-based CO2 emission goal described in §60.5855 

by your State’s affected EGUs. 

(3) State measures backstop. If your plan relies upon State

measures, you must submit, as part of the plan, a federally 

enforceable backstop that identifiesincludes emission standards 

for affected EGUs that will be put into place, if there is an 

exceedance of 10 percent or greater of any interim step goal or 

final goal period.a triggering event listed in paragraph 

(a)(3)(i) of this section, within 18 months of the due date of 

the report required in paragraph (b) of §60.5870(c). The 

emission standards inon the affected EGUs as part of the 

backstop must be able to meet either the CO2 emission performance 

rates or mass-based or rate-based CO2 emission goal required by 

your plan for bothyour State during the interim period and final 

periods, as well as any. You must either submit, along with the 
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backstop emission standards, provisions to adjust the emission 

standards to make up for the prior emission performance

shortfall identified from the prior compliance period., such 

that no modification of the emission standards is necessary in 

order to address the emission performance shortfall, or you must 

submit, as part of the final plan, backstop emission standards 

that assure affected EGUs would achieve your State’s CO2 emission 

performance rates or emission goals during the interim and final 

periods, and then later submit appropriate revisions to the 

backstop emission standards adjusting for the shortfall through 

the State plan revision process described in §60.5785. The 

backstop must also address the following:include the 

requirements in paragraphs (a)(3)(i) through (iii).

(i) You must include aA trigger for the backstop to go into 

effect upon either a: 

(A) A failure to meet a programmatic milestone or an; 

(B) An exceedance of 10 percent or greater of anyan interim 

step 1 goal or final interim step 2 goal based on reported CO2

emissions, with applied plus or minus adjustments for net CO2

allowances “imports” or “exports” (if applicable); 

(C) A failure to meet the interim period. goal based on 

reported CO2 emissions, with applied plus or minus adjustments 

for net CO2 allowances “imports” or “exports” (if applicable); or 
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(D) A failure to meet any final reporting period goal based 

on reported CO2 emissions, with applied plus or minus adjustments 

for net CO2 allowances “imports” or “exports” (if applicable). 

(ii) You may include in your plan any additional triggers 

so long as they do not affectreduce the stringency of the two 

triggers required under this paragraph (a)(3)(i) of this 

section. 

(ii) You must include a(iii) A schedule for implementation 

of the backstop once triggered, and you must identify all 

necessary stateState administrative and technical procedures for 

implementing the backstop. 

(4) Identification of applicable monitoring, reporting, 

and recordkeeping requirements for each affected EGU. TheseYou 

must include in your plan all applicable monitoring, reporting 

and recordkeeping requirements for each affected EGU and the 

requirements must be consistent with or no less stringent than 

the requirements specified in § 60.58205860.

(5) Description of State reporting. You must include in 

your plan a description of the process, contents, and schedule 

for stateState reporting to the EPA about plan implementation 

and progress including information required under § 60.58305870. 

(6) A(i) You must include in your plan a requirement for a 

report to be submitted by July 1, 2021, that demonstrates that 

the stateState has met, or is on track to meet, the programmatic 
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Page 2009 of 2153

milestone steps that the state indicated it would take from the 

submittal of the final plan through the end of 2020, and that 

the state is on track to implement the plan as of January 1, 

2022in the timeline required in §60.5770. 

(b) You must follow the requirements of subpart B of this 

part (Adoption and Submittal of state plans for Designated 

Facilities) and demonstrate that they were met in your 

stateState plan. However, the provisions of § 60.24(f) shall not 

apply. 

§ 60.5745 What must I include in my final plan submittal?

(a) In addition to the components of the plan listed in §

60.5740, a final plan submittal to the EPA must include the 

information in paragraphs (a)(1) through (1013) of this section. 

This information must be submitted to the EPA as part of your 

final plan submittal but will not be codified as part of the 

federally enforceable plan upon approval by EPA. 

(1) You must include a description of your plan approach 

and the geographic scope of the plan (i.e., stateState or multistateState, geographic boundaries related to the plan elements), 

including, if applicable, identification of multi-stateState

plan participants. 

(2) You must identify CO2 emission performance rates or 

equivalent statewide CO2 emission goals that your affected EGUs 

will achieve through the implementation of your plan.. If the 
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geographygeographic scope of your plan is a single-state State,

then you must includeidentify CO2 emission performance rates or 

emission goals according to § 60.58155855. If your plan includes 

multiple statesStates and you elect to set CO2 emission 

performance goals, you must includeidentify CO2 emission goals 

calculated according to § 60.5750. 

(i) You must specify in the plan submittal the CO2 emission 

performance rates or emission goals that affected EGUs will meet 

for the interim period, each interim steps 1, 2step, and 3 

andthe final period described in § 60.5770.(including each final 

reporting period) pursuant to §60.5770.

(3) You must include a demonstration that the affected EGUs 

covered by the plan are projected to achieve the CO2 emission 

performance rates or CO2 emission goals described in §

60.58155855. 

(4) You must include a demonstration that each affected 

EGU’s emission standard is quantifiable, non-duplicative, 

permanent, verifiable, and enforceable according to section 

§60.5775. 

(5) If your plan includes only emission standards on your 

affected EGUs sufficient to meet either the CO2 emission 

performance rates or CO2 emision goals, you must include in your 

plan submittal the information in paragraphs (a)(5)(i) through 

(iii) v) of this section as applicable. 
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(i) If the emission standards in your plan applies separate 

rate-based CO2 emission standards for affected EGUs (in lbs 

CO2/MWh) that are equal to or lower than the CO2 emission 

performance rates listed in table 1Table 1 of this subpart, then 

no additional demonstration is required beyond inclusion of the 

emission standards in the plan. Under this approach, compliance 

by affected EGUs with the emission standards will ensure that 

the CO2 emission performance rates or the state rate-based CO2

emission goal is achieved. 

(ii) If a plan applies rate-based emission standards to 

individual affected EGUs at a lblbs CO2/MWh rate that differs 

from the CO2 emission performance rates in tableTable 1 of this 

subpart or the state’sState’s rate-based CO2 emission goal in 

tableTable 2 of this subpart, then a further demonstration is 

required that the application of the CO2 emission standards will 

achieve the CO2 emission performance rates or stateState ratebased CO2 goal. You must demonstrate through a projection that 

the adjusted weighted average CO2 emission rate of affected EGUs, 

when weighted by generation (in MWh), will be equal to or less 

than the CO2 emission performance rates or the rate-based CO2

emission goal. This projection must address both the interim 

period (including interim step periods 1-3, for 2022-2024, 2025-

2027, and 2028-2029), and and the final period (2030-2031, and 

subsequent two-year periods).. The projection in the plan 
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submittal must include the information listed in (a)(5)(v) and 

in addition the following: 

(A) A summaryAn analysis of each affected EGU’s anticipated 

future operation characteristics, including annualthe change in

generation, CO2 emissions, capacity of affected EGUs given the 

compliance costs and capacity factors; 

(B) Plannedincentives under the application of different 

emission rate standards across affected EGU retirementsEGUs in a 

State; 

(C) Anticipated (B) A projection showing how generation is 

expected to shift between affected EGUs and across affected EGUs 

and non-affected EGUs over time; 

(C) Assumptions regarding the availability and anticipated 

use of the MWh of electricity generation or electricity savings 

from eligible resources that can be issued ERCs to adjust the ; 

(D) The specific calculation (or assumption) of how 

eligible resource MWh of electricity generation or savings are 

being used in the projection to adjust the reported CO2 emission 

rate of affected EGUs, including but not limited to, anticipated 

use (in MWh) by technology-type (e.g., wind, solar, demand-side 

EE), the physical location of the resources providing; 

(E) If a state plan provides for the ability of renewable 

energy resources located in states with mass-based plans to be 

issued ERCs, and any other relevant information 
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(e.g.,consideration in the projection that such resources must 

meet geographic eligibility requirements, based on power 

purchase agreements (PPAs) and other long-term power contracts); 

and an explanation, with calculation, of how these measures are 

being used in the projection to adjust the CO2 emission rate of 

affected EGUs;or related documentation; and 

(D) Expected electricity demand growth at the state or 

regional level, including the source and basis for these 

estimates; 

(E) Expected fuel switching at affected EGUs; 

(F) Heat rate improvements at affected EGUs; and 

(G(F) Any other applicable assumptions used in the 

projection. 

(iii) If a plan establishes mass-based emission standards 

for affected EGUs that cumulatively do not exceed the State’s 

EPA-specified mass CO2 emission goal then no additional 

demonstration is required beyond inclusion of the emission 

standards in the plan. 

(iv) If a plan applies mass-based emission standards to 

individual affected EGUs that do not meet the requirements of 

paragraph (a)(5)(iii) you must include a demonstration that your 

mass-based emission program will be designed such that 

compliance by affected EGUs would achieve the stateState massbased CO2 emission goals. This demonstration includes the 
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information listed in paragraph (a)(5)(v) and emission budgets 

for affected EGUs during the interim period and final plan 

performance periods that are equal to or lower than the 

applicable stateState mass-based CO2 goals specified in 

tableTable 3 of this subpart. Compliance periods for affected 

EGUs must aligned with each of the interim steps and final plan 

periods.

(v) Your plan demonstration to be included in your plan 

submittal, if applicable, must include the information listed in 

(a)(5)(v)(A) through (M) of this section. 

(A) A summary of each affected EGU’s anticipated future 

operation characteristics, including: 

(1) Annual generation; 

(2) CO2 emissions; 

(3) Fuel use, fuel prices (when applicable), fuel carbon 

content; 

(4) Fixed and variable operations and maintenance costs 

(when applicable); 

(5) Heat rates; and 

(6) Electric generation capacity and capacity factors. 

(B) An identification of any planned new electric 

generating capacity. 

(C) Analytic treatment of the potential for building 

unplanned new electric generating capacity. 
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(D) A timeline for implementation of EGU-specific actions 

(if applicable). 

(E) All wholesale electricity prices. 

(F) A geographic representation appropriate for capturing 

impacts and/or changes in electric system. 

(G) A time period of analysis, which must extend through at 

least 2031. 

(H) An anticipated electricity demand forecast (MWh load 

and MW peak demand) at the State or regional level, including 

the source and basis for these estimates, and, if appropriate, 

justification and documentation of underlying assumptions that 

inform the development of the demand forecast (e.g., annual 

economic and demand growth rate or population growth rate). 

(I) A demonstration that each emission standard included in 

your plan meets the requirements of §60.5775. 

(J) Any ERC or emission allowance prices, when applicable. 

(K) An identification of State-enforceable measures with 

electricity savings and RE generation, in MWh, expected for 

individual and collective measures and any assumptions related 

to the quantification of the MWh, as applicable. 

(L) An identification of planning reserve margins. 

(M) Any other applicable assumptions used in the 

projection. 
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(6) If your plan includes staterelies upon State measures, 

in addition to or in lieu of the emission standards required by 

paragraph (a)(2) of § §60.5740,(a)(2), the final stateState plan 

submittal must include the information under paragraphs 

(a)(5)(iv) and (a)(6)(i) through (vi):v) of this section. 

(i) You must include a description of all the stateState

measures the stateState will rely upon to achieve the applicable 

CO2 emission performance rates or CO2 emission goalgoals required 

under §60.5855(e), the projected impacts of the State measures 

over time, the applicable stateState laws or regulations related 

to such measures, and identification of parties or entities 

implementing such stateState measures. 

(ii) You must include the schedule and milestones for the 

implementation of the stateState measures. If the stateState

measures in your plan submittal rely upon renewable energy (RE) 

or demand-side energy efficiency (EE) programs and 

projectsmeasures that do not have a direct effect on the 

emissions measured at an affected EGU’s stack, you must also 

demonstrate how the minimum emission, monitoring and 

verification (EM&V) requirements listed under § 60.5795 that 

apply to those programs and projects will be met. 

(iii) You must demonstrate that the federally enforceable 

emission standards for affected EGUs, if included, and state in 

conjunction with any State measures relied upon for your plan, 
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are sufficient to attain the CO2 emission performance rates 

orachieve the mass-based CO2 emission goal for the interim period

of 2022-2029 and the final period of 2030 and beyond. This 

includes the interim period of 2022-2029, including interim step 

1 2022-2024 period, interim step 2 2025-2027 , each interim step 

in that interim period, the final period, and interim step 3 

2028-2029each final reporting period (or alternative CO2 emission 

performance step levels adopted by the state, provided they 

result in achievement of the CO2 emission performance rates or 

state CO2 emission goal during the 2022-2029 interim period), as 

well as the final period of 2030 and beyond. Your demonstration 

must use technically sound quantification methods that are 

reliable and replicable. The demonstration must be supported by 

the methods and measurement procedures by which the federally 

enforceable CO2. In addition, you must demonstrate that each

emission standards for affected EGUs are reliably measured, if 

these standards are incorporated into the state measures state 

plan. standard included in your plan meets the requirements of 

§60.5775 and each State measure included in your plan submittal 

meets the requirements of §60.5780.

(iv) You must include a CO2 performance projection of your 

state measure State measures that shows how the measures will 

achieve the future CO2 performance at affected EGUs. Elements of 

this projection must include the following for the interim 
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period and the final periods: period: 

(A) A baseline demand and supply forecast as well as the 

underlying assumptions and data sources of each forecast; 

(B) The magnitude of energy and emission impacts from all 

measures included in the plan and applicable assumptions; 

(C) An explanation of the tools and emission quantification 

approaches used in the projection; and 

(D) Underlying emission quantification assumptions. 

(v) If the state measures in your plan submittal are 

designed to meet either a CO2 emission performance rate or ratebased CO2 emission goal, MWh from state measures may be used to 

adjust the denominator of the CO2 emission rate of affected EGUs 

when demonstrating achievement of the CO2 emission performance 

rates or the rate-based CO2 emission goal. In this case your plan 

submittal must include the following information, at a minimum, 

to demonstrate state measures will require affected EGUs to meet 

the CO2 emission performance rates or the rate-based CO2 emission 

goal: 

(A) A summary of each affected EGU’s anticipated future 

operation characteristics, including annual generation, CO2

emissions, capacity and capacity factors; 

(B) Planned retirements; 

(C) A detailed description of the zero CO2 emitting demandside energy efficiency (EE) savings and renewable energy (RE) 
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generation (and any other qualifying MWh) from state measures 

that will be available for use in adjusting the reported CO2

emission rates of affected EGUs, including, but not limited to, 

the amount of generation or savings by technology-type (e.g., 

wind, solar, EE), the physical location of the measures or 

generation, and any other relevant information (e.g., power 

purchase agreements (PPAs) and other long-term power contracts); 

and an explanation, with calculation, of how these measures are 

being used in the projection to adjust the CO2 emission rate of 

affected EGUs; 

(D) Expected electricity demand growth at the state or 

regional level, including the source and basis for these 

estimates; 

(E) Expected fuel switching at affected EGUs; 

(F) Heat rate improvements at affected EGUs; and 

• (G) StateAny other applicable assumptions used in the 

projection. 

(vi) If the state measures in your plan submittal are 

designed to meet mass-based CO2 emission goals, a state must 

demonstrate that the combined stateState-enforceable measures, 

alongin conjunction with any federally enforceable CO2 emission 

standards for affected EGUs, if included, will achieve the state 

mass-based CO2 emission goal. You must demonstrate and document 

how the combined state measures are impacting CO2 emissions at 
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affected EGUs so that the sum of emissions at all affected EGUs 

will be lower than or achieve the state’s CO2 emission goal for 

each of result in the achievement by the affected EGUs of the 

State’s mass-based CO2 emission goals for the interim steps 

period, interim step, and final periodreporting periods. In 

addition, you must demonstrate that each State measure included 

in your plan submittal meets the requirements of §60.5780. 

(7) Your plan must demonstrate any regional information 

considered in developing the assumptions. Multi-state plans or 

plans sharing common elements should use regional assumptions or 

demonstrate reconciliation of any inconsistencies between statelevel assumptions. 

(8) Your plan submittal must include a demonstration that 

the reliability of the electrical grid has been thoroughly 

considered. 

(8) Your plan submittal must include a timeline with all 

the programmatic milestone steps the State intends to take 

between the time of the State plan submittal and January 1, 2022 

to ensure the plan is effective as of January 1, 2022. 

(9) CertificationYour plan submittal must adequately 

demonstrate that your State has the legal authority (e.g., 

through regulations or legislation) and funding to implement and 

enforce each component of the State plan submittal, including 
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federally enforceable emission standards for affected EGUs or 

State measures as applicable. 

(10) Your State plan submittal must demonstrate that each 

interim step goal required under §60.5855(c), will be met and 

include in its supporting documentation a description of the 

analytic process, tools, methods, and assumptions used to make 

this demonstration. 

(11) Your plan submittal must include certification that a 

hearing required under § 60.23 (c)(1) on the stateState plan was 

held, a list of witnesses and their organizational affiliations, 

if any, appearing at the hearing, and a brief written summary of 

each presentation or written submission. pursuant to the 

requirements of §60.23(f).

(10) Supporting12) Your plan submittal must include 

documentation of any conducted community outreach and community 

involvement, including engagement with vulnerable communities. 

(13) Your plan submittal must include supporting material 

for your plan including: 

(i) Materials demonstrating the state'sState's legal 

authority to carry out each component of its plan, including 

emissions standards or stateState measures; 

(ii) Materials supporting that the CO2 emission performance 

rates or CO2 emission goals will be achieved by affected EGUs 
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identified under the plan, according to paragraph (a)(3) of this 

section; 

(iii) Materials supporting any calculations for CO2 emission 

goals calculated according to § 60.58155855, if applicable; and 

(iv) MaterialsAny other materials necessary to support 

evaluation of the plan by the EPA. 

(v) Materials supporting each hearing held including the 

list of witnesses and their organizational affiliations, if any, 

appearing at the hearing, and a brief written summary of each 

presentation or written submission pursuant to the requirements 

of 40 CFR 60.23(f) 

(b) You must submit your final plan to the EPA 

electronically according to § 60.58355875. 

§ 60.5750 Can I work with other statesStates to develop a multistateState plan?

 A multi-state plan may be submitted on behalf of multiple 

states, provided it is formally signed by the Governor or the 

Governor’s designee for each of the states participating in the 

multi-state plan. In this instance, the joint submittal will 

have the same legal effect as an individual submittal for each 

participating state. A multi-stateState plan must include all 

the required elements for a plan specified in § 60.5740(a). A 

multi-stateState plan must meet the requirements of paragraphs 

(a) and (b) of this section. 
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(a) The multi-stateState plan must demonstrate that all 

affected EGUs in all states participating in the multi-state 

planStates will meet the CO2 emission performance rates listed in 

table 1Table 1 of this subpart or an equivalent CO2 emission goal 

according to paragraphs (a)(1) or (2) of this section. States 

may only follow the procedures in (a)(1) or (2) if they have 

functionally equivalent requirements meeting §60.5775 and 

§60.5790 included in their plans.

(1) For statesStates electing to demonstrate performance 

with a CO2 emission rate-based goal, the CO2 emission goals 

identified in the plan according to § 60.58155855 will be aan 

adjusted weighted (by net energy output) average lblbs CO2/MWh 

emission rate to be achieved by all affected EGUs in the multistateState area during the plan periods; or 

(2) For statesStates electing to demonstrate performance 

with a CO2 emission mass-based goal, the CO2 emission goals 

identified in the multi-stateState plan according to §

60.58155855 will be total CO2 emissions by all affected EGUs in 

the multi-stateState area during the plan periods. 

(b) Options for submitting a multi-stateState plan include 

the following: 

(1) States participating in a multi-stateState plan may 

submit one multi-stateState plan submittal on behalf of all 

participating statesStates. The joint submittal must be signed 
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electronically, according to §60.5875, by authorized officials 

for each of the statesStates participating in the multistateState plan. In this instance, the joint submittal will have 

the same legal effect as an individual submittal for each 

participating State. The joint submittal must adequately address 

plan components that apply jointly for all participating 

statesStates and components that apply for each individual 

stateState in the multi-stateState plan, including necessary 

stateState legal authority to implement the plan, such as 

stateState regulations and statutes. 

(2) States participating in a multi-stateState plan may 

submit a single plan submittal, signed by authorized officials 

from each participating state, thatState, which addresses common 

plan elements and each individual. Each participating 

statesStates must, in addition, provide individual plan 

submittals that provide stateaddress State-specific elements of 

the multi-stateState plan.

(3) States participating in a multi-stateState plan may 

separately make individual submittals that address all elements 

of the multi-stateState plan. The plan submittals must be 

materially consistent for all common plan elements that apply to 

all participating statesStates, and also must address individual 

stateState-specific aspects of the multi-stateState plan. Each 

individual stateState plan submittal must address all required 
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plan components in § 60.5740. 

§ 60.5755 Can I include existing requirements, programs, and 

measures in my plan? 

 (a) Yes, existing state programs, requirements, and 

measures, meeting the requirements in paragraph (b) of this 

section may qualify for use in projecting and demonstrating that 

a plan achieves the CO2 emission performance rates or emission 

goals specified in a plan, according to § 60.5815. 

 (b) Emission impacts of existing programs, requirements, 

and measures that occur during a plan performance period must 

meet the following requirements to qualify for use in projecting 

and demonstrating that a plan achieves the CO2 emission 

performance rates or emission goals specified in a plan, 

according to § 60.5815: 

 (1) Actions taken pursuant to an existing state program, 

requirement, or measure, such as compliance with a regulatory 

obligation or initiation of an action related to a program or 

measure, must occur after December 31, 2012; and 

(2) The existing state program, requirement, or measure, 

and any related actions taken pursuant to such program, 

requirement, or measure, meet the applicable requirements 

pursuant to § 60.5740(a), § 60.5780 and § 60.5785. 

§ (c) A State may elect to participate in more than one 

multi-State plan. If a State elects to participate in more than 
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one multi-State plan then you must identify in the State plan 

submittal required under §60.5745, the subset of affected EGUs 

that are subject to the specific multi-State plan or your 

State’s individual plan. An affected EGU can only be subject to 

one plan. 

(d) A State may elect to allow its affected EGUs to 

interact with affected EGUs in other States through mass-based 

trading programs or a rate-based trading program without 

entering into a formal multi-State plan allowed for under this 

section, so long as such programs are part of an EPA-approved 

state plan. 

(1) For States that elect to do mass-based trading under 

this option the State must indicate in its plan that its 

emission budget trading program will be administered using an 

EPA-approved (or EPA-administered) emission and allowance 

tracking system. 

(2) For States that elect to use a rate-based trading 

program which allows the affected EGUs to use ERCs from other 

State rate-based trading programs, the plan must require 

affected EGUs within their State to comply with emission 

standards equal to the sub-category CO2 emission performance 

rates in Table 1 of this subpart. 

§60.5760 What are the timing requirements for submitting my 

plan? 
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(a) You must submit a final plan with the information 

required under § 60.5745 by August 31September 6, 2016, unless 

you are submitting an initial plan submittal, allowed under §

60.5765, in lieu of a final stateState plan submittal, according 

to paragraphs (b) of this section. 

(b) For statesStates seeking a two year extension for a 

final plan submittal, you must include the information in §

60.5765(a) in an initial plan submittal by August 31September 6, 

2016, to receive an extension to submit your final stateState

plan submittal by August 31September 6, 2018. 

(c) You must submit all information required under 

paragraphs (a) and (b) of this section according to the 

electronic reporting requirements in § 60.58355875. 

§ 60.5765 What must I include in an initial plan submittal if 

requesting an extension for a final state plan submittal? 

(a) You must includesufficiently demonstrate that your 

State is able to undertake steps and processes necessary to 

timely submit a final plan by the extended date of September 6, 

2018, by addressing the following required elementscomponents in 

an initial plan submittal by September 6, 2016, if requesting an 

extension for a final plan submittal: 

(1) A An identification of final plan approach or 

approaches under consideration and description of the plan 
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approach and progress made to date in developing each of on the 

final plan elements in § 60.5740components; 

 

(2) An initial projection of the level of emission 

performance that will be achieved under the final plan; 

(3) A commitment by the state or states to maintain 

existing state measures that limit or avoid CO2 emissions from 

affected EGUs (e.g., renewable energy standards, unit-specific 

limits on operation or fuel utilization); 

(4) Justificationappropriate explanation of why the State 

requires additional time is needed to submit a final plan (e.g., 

a state’s required schedule for legislative approval and 

administrative rulemaking, the need for multi-state coordination 

in the development of an individual state plan, or the process 

and coordination necessary to develop a multi-state plan);to 

submit a final plan by September 6, 2018; and

(5) A comprehensive roadmap describing in detail the action 

you intend to take to submit all required elements of a final 

plan submittal as specified in § 60.5740 by no later than August 

31, 2017, including process, analytical methods and schedule 

(including milestones) specifying when all necessary plan 

components will be complete (e.g., projection of emission 

performance; implementing legislation, regulations and 

agreements; necessary approvals); 
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(6) Identification of existing and future programs, 

requirements, and measures the state or states intend to include 

in the plan and supporting materials as appropriate; 

(7) If a multi-state plan is being developed, an executed 

agreement(s) with other states (e.g., memorandum of 

understanding) participating in the development of the multistate plan; 

(8) A description of all steps the state or states have 

already taken in furtherance of actions needed to finalize a 

final plan submittal; and 

(10) Evidence of an opportunity for public comment and a 

response to any significant comments received on issues relating 

to the approvability of the initial plan. 

(3) Demonstration or description of opportunity for public 

comment on the initial submittal and meaningful engagement with 

stakeholders, including vulnerable communities, during the time 

in preparation of the initial submittal and the plans for 

engagement during development of the final plan. 

(b) You must submit an initial plan submittal allowed in 

paragraph (a) of this section, information required under 

paragraph (c) of this section (only if a stateState elects to 

submit an initial submittal to request an extension for a final 

plan submittal), and a final stateState plan submittal according 

to § 60.58305870. If a stateState submits an initial plan 
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submittal, an extension for a final stateState plan submittal is 

considered granted and a final stateState plan submittal is due 

according to § 60.5760(b) unless a stateState is notified within 

90 days of the EPA receiving the initial plan submittal that the 

EPA finds the initial plan submittal does not meet the 

requirements listed in paragraph (a) of this section and the 

State has failed to submit the final plan required by September 

6, 2016. 

(c) If an extension for submission of a final plan has been 

granted, you must submit a progress report by August 31September 

6, 2017. The 2017 report must include the following: 

(1) A summary of the status of each component of the final 

plan, including an update from the 2016 initial plan submittal 

and a list of which final plan components are not complete. 

(2) A commitment to a plan approach (e.g., single or multistateState, rate-based or mass-based emission performance level, 

rate-based or mass-based emission standards), including draft or 

proposed legislation and/or regulations. 

(3) An updated comprehensive roadmap with a schedule and 

milestones for completing the final plan, including progressany 

updates to date in developing a final plancommunity engagement 

undertaken and steps taken in furtherance of actions needed to 

finalize a final planplanned. 
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(d) If you do not submit an acceptable update by August 31, 

2017, you will have failed to meet the conditions for the 2-year 

extension and EPA will develop a federal plan unless you submit 

a final plan during this time. 

§ §60.5770 What schedules, performance periods, and 

compliance periods must I include in my state plan? 

(a) You (a) The affected EGUs covered by your plan must 

meet the CO2 emission reduction requirements for the affected 

EGUs required under §60.5855 for the interim period, interim 

steps 1, 2, and 3 andthe final periodreporting periods according 

to paragraph (b) of this section. You must also include in your 

plan schedules of compliance periods for each affected EGU 

regulated under the plan according to paragraphs (c) and (d) of 

this section. 

(b) Your plan must require your affected EGUs to achieve 

each stateCO2 emission performance rate or CO2 emission goal, as 

applicable, required under § 60.58155855 over its applicable 

timethe periods according to paragraphs (b)(1) through (3) of 

this section:.

(1) The interim period must cover the eight calendar years 

2022-2029 starting January 1, 2022 and ending December 31, 2029. 

(2) The interim steps are increments of plan performance 

within the interim period. Interim step 1 must cover the three 

calendar years 2022-2024, interim step 2 must cover the three 
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calendar years 2025-2027 and interim step 3 must cover the two 

calendar years 2028-2029. 

(3) The final period must cover the years 2030 and 

thereafter and with increments of plan performance for every two 

calendar years (i.e., 2030-2031, 2032-2033, 2034-2035, etc.). 

(2) Each interim step. 

(3) Each final reporting period. 

(c) If your state adoptsThe emission standards for affected 

EGUs regulated under the plan, the emission standards for 

affected EGUs must include the following compliance periods for 

the emission standards:: 

(1) For the interim period, affected EGUs must have 

emission standards that have schedules of compliance forperiods 

that are no longer than each interim step 1, 2 and 3are imposed

for the calendar years January 1, 2022 to December 31, 2024, 

January 1, 2025 to December 31, 2027, and January 1, 2028 to 

December 31, 2029, respectivelyentirety of the interim step 

either alone or in combination. 

(2) For the final period, EGUs must have emission standards 

that have schedules of compliance forperiods that are no longer 

than each two calendar years starting in 2030 (i.e., January 1, 

2030 to December 31, 2031, January 1, 2032 to December 31, 2033, 

January 1, 2034 to December 31, 2035, etc.). 
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(3) Schedules of compliance for interim step 1, 2, 3 and 

final reporting period and are imposed for the entirety of the 

final reporting period either alone or in combination. 

(3) Compliance periods for each interim step and each final 

reporting period may take forms shorter than the applicable 3 or 

2 calendar years specified in paragraphs (1) or (2) as long as 

thosethis regulation, provided the schedules of compliance 

collectively end on the same schedule as theeach interim 

stepsstep and final periodsreporting period. 

(d) If your plan includes staterelies upon State measures 

in lieu of or in addition to emission standards for affected 

EGUs regulated under the plan, then the state measures must 

includeperiod for achievement of each State measure must be 

identical to the compliance periods for affected EGUs listed in 

paragraphs (c)(1) through (3).) of this section.

§ 60.5775 What emission standards must I include in my plan? 

(a) Emission standard(s) for affected EGUs under your state 

plan must be quantifiable, verifiable, non-duplicative, 

permanent, and enforceable with respect to each affected EGU. 

The plan shallmust include the methods by which each emission 

standard meets each of the following requirements in paragraphs 

(b) through (f) of this section. 

(b) An affected EGU’s emission standard is quantifiable if 

it can be reliably measured, in a manner that can be replicated. 
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(c) An affected EGU’s emission standard is verifiable if 

adequate monitoring, recordkeeping and reporting requirements 

are in place to enable the stateState and the Administrator to 

independently evaluate, measure, and verify compliance with the 

emission standard. 

(d) An affected EGU’s emission standard is non-duplicative 

with respect to a stateState plan if it is not already 

incorporated as an emission standard in another stateState plan 

unless incorporated in multi-stateState plan.

(e) An affected EGU’s emission standard is permanent if the 

emission standard must be met for each compliance period, or 

unless it is replaced by another emission standard in an 

approved plan revision, or the stateState demonstrates in an 

approvable plan revision that the emission reductions from the 

emission standard are no longer necessary for the stateState to 

meet its stateState level of performance. 

(f) An affected EGU’s emission standard is enforceable if: 

(1) A technically accurate limitation or requirement and 

the time period for the limitation or requirement isare

specified; 

(2) Compliance requirements are clearly defined; 

(3) The affected EGUs responsible for compliance and liable 

for violations can be identified; 

(4) Each compliance activity or measure is enforceable as a 
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practical matter; and 

(5) The Administrator and, the state maintain the ability 

to enforce violations and secure appropriate corrective actions 

pursuant to sections 113(a) through (h) of the Act, 42 U.S.C. §§ 

7413(a)-(h), and states and otherState, and third parties 

maintain the ability to enforce against violations and secure 

appropriate corrective actions pursuant to section 304 of the 

Act, 42 U.S.C. § 7604. 

(g) Your plan must ensure that (including if an affected 

EGU does not meet its emission standard because it did not meet 

the emissions standard based on its stack emissions and 

generation alone and it did not obtain sufficient qualifying 

ERCs to meet its emission standard by July 1 following the 

relevant compliance period, it may be emissions, its allowances 

if it is subject to federal enforcement pursuant to Sections 

113(a) – (h), 42 U.S.C. §§ 7413(a)-(h), and Section 304 of the 

Clean Air Act, 42 U.S.C. § 7604, and the United States, states, 

and other persons have the ability to enforce violations and 

secure corrective actions. 

(i) In addition to any other recourse provided in Sections 

113 (a) – (h)a mass-based emission standard, or Section 304 of 

the Clean Air Act, 42 U.S.C. §§ 7413(a)-(h), 7604, for each 

compliance period in which an affected EGU does not meet its CO2 

emission standard, it will be required to retire 2 times the 
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number of ERCs that would have brought it into compliance with 

its CO2 emission standard, and it must retire them by the end of 

the compliance period immediately following the compliance 

period in which it did not meet its CO2 emission standard. 

(ii) Failure to retire these replacement ERCs is an 

additional violation that may be ERCs if it is subject to 

federal enforcementa rate-based emission standard) and secure 

appropriate corrective actions, in the case of the Administrator 

pursuant to CAA sections 113(a)–(h), in the case of a State, 

pursuant to its plan, State law or CAA section 304, as 

applicable, and in the case of third parties, pursuant to CAA 

section 304. 

(h) If an affected EGU obtained sufficient facially valid 

ERCs to meet its emission standard as specified in (a), but 

those ERCs were found to be invalid, it may be subject to 

federal enforcement as specified in (g). 

(i) For purposes of determining the number of days of 

violation for calculation of civil penalties and other relief, 

if an affected EGU does not meet its emission standard for a 

compliance period, each day in the compliance period constitutes 

a day in violation. For a two calendar year compliance period, 

the number of days in violation is 730 or 731 days. For a three 

calendar year compliance period, the number of days in violation 

is §1,095 or 1,096 days 
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§ 60.5780 What stateState measures may I includerely upon in 

support of my plan? 

(a) You may include staterely upon State measures in 

support of your plan that are not emission standard(s) on 

affected EGU’sEGUs, provided those stateState measures meet the 

following requirements: in paragraph (a) of this section.

(1a) Each stateState measure is quantifiable, verifiable, 

non-duplicative, permanent, and enforceable with respect to each 

affected entity (which may be, but is not limited to, an 

affected EGUentities other than affected EGUs with no federally 

enforceable obligations under a State plan), and your plan 

supporting materials includesinclude the methods by which each 

stateState measure meets each of the following requirements in 

paragraphs (i1) through (v5) of this subpart. 

(i1) A stateState measure is quantifiable with respect to 

an affected entity if it can be reliably measured, in a manner 

that can be replicated. 

(ii2) A stateState measure is verifiable with respect to an 

affected entity if adequate monitoring, recordkeeping and 

reporting requirements are in place to enable the stateState to 

independently evaluate, measure, and verify compliance with the 

stateState measure. 

(iii3) A stateState measure is non-duplicative with respect 

to an affected entity if it is not already incorporated as a 
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stateState measure or an emission standard in another stateState

plan or stateState plan supporting material unless incorporated 

in multi-stateState plan. 

(iv4) A stateState measure is permanent with respect to an 

affected entity if the stateState measure must be met for at 

least each compliance period, or unless it is replaced by 

another stateState measure in an approved plan revision, or the 

stateState demonstrates in an approved plan revision that the 

emission reductions from the stateState measure are no longer 

necessary for the state’sState’s affected EGUs to meet theirits

CO2 emission performance rates. 

(v5) A stateState measure is enforceable against an 

affected entity if: 

(Ai) A technically accurate limitation or requirement and 

the time period for the limitation or requirement isare

specified; 

(Bii) Compliance requirements are clearly defined; 

(Ciii) The affected entities responsible for compliance and 

liable for violations can be identified; 

(Div) Each compliance activity or measure is enforceable as 

a practical matter; and 

(Ev) The stateState maintains the ability to enforce 

violations and secure appropriate corrective actions. 
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(b) If you include a rate-based ERC trading program as part 

of your state measures, the documentation supporting your 

submittal must show that your state regulations include all of 

the same requirements as those specified in § 60.5791 through § 

60.5797 and any other applicable requirements that a state would 

need to include in a rate-based ERC trading program approvable 

as part of a plan. 

§ §60.5785 What is the procedure for revising my plan? 

(a) Plans can only be revised only with approval by the 

Administrator. The Administrator will approve a plan revision if 

it is satisfactory with respect to the applicable requirements 

of this subpart and any applicable requirements of subpart B of 

this part, including the requirement in § 60.5745(a)(3) to 

demonstrate achievement of the CO2 emission performance rates in 

§ 60.58155855. If one (or more) of the elements of the plan set 

in § 60.5740 require revision with respect to achieving the CO2

emission performance rates in § 60.58155855, a request must be 

submitted to the Administrator indicating the proposed revisions 

to the plan to ensure the CO2 emission performance rates are met. 

In addition, the following provisions in (b) through (d) may 

apply. 

(b) You may submit revisions to a plan to adjust CO2

emission goals under the following instances: 
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(1) Addressing data correctionsthe addition of an affected 

EGU required to state goal, which resultbe included in no more 

than a 2 percent change in the state goal; andplan under 

§60.5740(a)(1).

(2) Addressing EGUs that become subject to subpart TTTT of 

this Partpart and are no longer considered affected EGUs for 

incorporation in a plan. 

(c) If your state submits State is required to submit a 

notification according to section § 60.58305870(d) indicating an 

exceedance of 10 percent or greater of a CO2 emission performance 

rate or CO2 emission goala triggering of corrective measures as 

described in §60.5740(a)(2)(i) and your plan does not already 

include corrective measures to be implemented if triggered, you 

must revise your stateState plan to include corrective measures 

to be implemented. The corrective measures must ensure future 

achievement of the CO2 emission performance rates or stateState

CO2 emission goal and. Additionally, the corrective measures must

achieve additional emission reductions to offset any emission 

performance deficiency that occurred during an exceededshortfall 

relative to the overall interim step(s)period or final 

period(s). CO2 emission performance rate or State CO2 emission 

goal. The stateState plan revision submission must explain how 

the corrective measures both make up for the shortfall and 

address the State plan deficiency that caused the shortfall. The 
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State must submit the revised plan and explanation to the EPA 

within 24 months after submitting the stateState report required 

in section § 60.58305870(a) indicating the exceedance in lieu of 

the requirements of § 60.28 (a). (a). The State must implement 

corrective measures within 6 months of the EPA’s approval of a 

plan revision adding them. The shortfall must be made up as 

expeditiously as practicable.

(d) You may applyIf your plan relies upon State measures, 

your State triggers the backstop under §60.5740(a)(3)(i), and 

your State measures plan backstop does not include a mechanism

to havemake up the shortfall, you must revise your backstop 

emission standards to make up the shortfall. The shortfall must 

be made up as expeditiously as practicable. 

(e) Reliability Safety Valve 

(1) In order to trigger a reliability safety valve, you 

must notify the EPA within 48 hours of an unforeseen, emergency 

situation that threatens reliability, such that your State will 

need a short–term modification to a plan to respondof emission 

standards under a State plan for a specified affected EGU or 

EGUs. The EPA will consider the notification in §60.5870(g)(1)

to any instances that can be characterized as a reliability 

safety valve issuebe an approved short-term modification to the 

State plan without needing to go through the full stateState

plan revision process if the stateState provides propera second
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notification to the EPA. within seven days of the first 

notification. The short -term modification, if approved under a 

reliability safety valve allows modification to emission 

standards for an affected EGU or EGUs so that under the State 

plan for a maximum of 90 days, thean affected EGU or EGUs may 

operate at an emission standardfor an initial period of up to 90 

days. During that is aboveperiod of time, the EGU or EGUs will 

need to comply with the modified emission standard specified in 

the relevant plan. However, you must ensurestandards identified

in your submittalthe initial notification required under 

§60.5870(g)(1) or amended in the second notification required 

under §60.5870(g)(2). For the duration of the up to 90 day 

short-term modification, the emissions of the affected EGU or 

EGUs that theexceed their obligations under the approved State 

plan will not be counted against the State’s CO2 emission 

performance rates or the state CO2 emission goal will still be 

achieved. rate or goal. The EPA reserves the right to review any 

such notification required under §60.5870(g), and, in the event 

that the EPA finds such notification is improper, the EPA may 

disallow the short-term modification and affected EGUs must 

continue to operate under the approved State plan emission 

standards. As described more fully below in §60.5870(g)(3), at 

least seven days before the end of the initial 90 day 

reliability safety valve period, the State must notify the 
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appropriate EPA regional office whether the reliability concern 

has been addressed and the EGU or EGUs can resume meeting the 

original emission standards established in the State plan prior 

to the short-term modification or whether a serious, ongoing 

reliability issue necessitates the EGU or EGUs emitting beyond 

the amount allowed under the State plan.

(1) To request this short-term modification you (2) Plan 

revisions submitted pursuant to §60.5870(g)(3) must submit a 

notification to the EPA including: 

(i) A full description of the reliability concern and why 

the affected EGU (or EGUs) needs to operate under modified 

emission standards from those originally required in the plan; 

(ii) A description of how it is coordinating or will 

coordinate, with relevant planning authorities to alleviate the 

problem in an expedited manner; 

(iii) A written concurrence from the relevant planning 

authority supporting the temporary modification request or an 

explanation of why this kind of concurrence cannot be provided; 

and 

(iv) Additional information with respect to whether or not 

the relevant planning authority has conducted a system-wide or 

other analysis of the reliability safety valve concern. 

(2) If the short term modification is approved then at the 

end of modification period, of 90 days or less, you must submit 
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a notification to the EPA including: 

(i) Whether the reliability concern has been addressed; 

(ii) Whether you are requiring the affected EGU, or EGUs, 

to meet the original emissions standards in the state plan 

approved prior to the short-term modification going forward; 

(iii) How the CO2 emission performance rates or state CO2 

emission goals will be met going forward and enumerate how it 

will make uprequirements for any emission reductions that were 

lost during the safety valve period; andState plan revisions 

under §60.5785(a).

(iv) If there still is a serious, ongoing reliability 

issue, then you must provide to the EPA a notice that you will 

be submitting a state plan revision according to paragraph (a) 

of this section. 

§ §60.5790 What must I do to meet my plan obligations? 

(a) To meet your plan obligations by requiring either 

emission standards or state specific measures on your affected 

EGUs as specified in § 60.5740, you must demonstrate that your 

affected EGUs are complying with their emission standards as 

specified in §60.5740, and you must demonstrate that the 

emission standards on affected EGUs in conjunction with any 

State measures are resulting in achievement of the CO2 emission 

performance rates or state specificstatewide CO2 emission goals 

using the procedures in paragraphs (b), (c) and) through (d) of 
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this section. If your plan requires the use of Emission Rate 

Credits (ERCs)allowances for your affected EGUs to comply with 

their emission standards, you must follow the requirements under 

paragraph (e).b) of this section and §60.5830. If your plan 

requires the use of ERCs for your affected EGUs to comply with 

their emission standards, you must follow the requirements under 

paragraphs (c) and (d) of this section and §§60.5795 through 

60.5805.

(b) If you submit a plan that sets a mass-based emission 

trading program for your affected EGUs, the stateState plan must 

include emission standards and requirements that specify the 

emission budget andallowance system, related compliance 

requirements and mechanisms., and the emission budget as 

appropriate. These requirements must include: those listed in 

paragraphs (b)(1) through (5). 

(1) CO2 emission monitoring, reporting, and recordkeeping 

requirements for affected EGUs;.

(2) ProvisionsRequirements for stateState allocation of 

allowances; consistent with §60.5815.

(3) ProvisionsRequirements for tracking of allowances, from 

issuance through submission for compliance; and, consistent with 

§60.5820. 

(4) The process for affected EGUs to demonstrate compliance 

(allowance “true-up” with reported CO2 emissions).) consistent 
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with §60.5825. 

(5) Requirements that address increased emissions from new 

sources, beyond the emissions expected from new sources if 

existing EGUs were given standards of performance in the form of 

the subcategory-specific emission performance rates. You may 

meet this requirement by requiring one of the options under 

paragraphs (b)(5)(i) through (iii). 

(i) You may include, as part of your plan’s supporting 

documentation, requirements enforceable as a matter of State law 

regulating emissions from existing affected EGUs and emissions 

from EGUs covered by subpart TTTT of this part under the massbased CO2 goal plus new source CO2 emission complement applicable 

to your State in Table 4 of this subpart. If you choose this 

option, the term “mass-based CO2 goal plus new source CO2

emission complement” shall apply rather than “CO2 mass based 

goal” and the term “CO2 emission goal” shall include “mass-based 

CO2 goal plus new source CO2 emission complement” in these 

emission guidelines. 

(ii) You may include requirements in your State plan for 

emission budget allowance allocation methods that align 

incentives to generate to existing or new sources; 

(iii) You may submit an approvable equivalent method which 

requires affected EGUs to meet the mass-based CO2 emission goal. 

The EPA will evaluate the approvability of such an alternative 
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method on a case by case basis. 

(c) If you submit a plan that sets rate-based emission 

standards on your affected EGUs, to meet the requirements of §

60.5775, you shallmust follow the requirements in paragraphs 

(c)(1) through (4). 

(1) You must require the owner or operator of each affected 

EGUsEGU covered by your plan to calculate an adjusted CO2

emission rate to demonstrate compliance with its emission 

standard by factoring stack emissions and any qualifying ERCs 

into the following equationsequation: 

ைଶ஼ܯ ∑ 	 ൌ ݁ݐܽݎ	݊݋݅ݏݏ݁݉݅	݈݅ܽ݊ܿ݁݌݉݋ܿଶܱܥ	

஼ாோ	ܹ݄ܯ	 ∑ ൅	 ௣௢ܹ݄ܯ ∑

Where: 

CO2 emission rate = An affected EGU’s calculated CO2

emission rate that will be used to determine 

compliance with the applicable CO2 emission 

standard. 

MCO2 = Measured CO2 mass in units orof pounds (lbs) 

summed over the compliance period for an affected 

EGU. 

MWhop = Total source operationnet energy output over the 

compliance period for an affected EGU in units of 

MWh. 

MWhERC = ERC replacement generation for an affected EGU in 
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units of MWh. (ERCs are denominated in whole 

integers as specified in paragraph (d) of this 

section).

(d) If you submit a plan that sets rate-based emission 

standards and/or state specific measures on affected EGUs, to 

meet the requirements of § 60.5780, you shall require the 

affected EGUs covered by your plan to demonstrate compliance 

with its emission standard by factoring stack emissions and any 

qualifying Emission Reduction Credits (ERCs) into the equation 

listed in paragraph (c) of this section.

(e) If you (2) Your plan must specify that an ERC qualifies 

for the compliance demonstration specified in paragraph (c)(1) 

of this section if the ERC meets the requirements of paragraphs 

(c)(2)(i) through (iv). 

(i) An ERC must have a unique serial number. 

(ii) An ERC must represent one MWh of actual energy 

generated or saved with zero associated CO2 emissions. 

(iii) An ERC must only be issued to an eligible resource 

that meets the requirements of §60.5795 or to an affected EGU 

that meets the requirements of §60.5800 and must only be issued 

by a State or its State agent through an EPA-approved ERC 

tracking system that meets the requirements of §60.5810, or by 

the EPA through an EPA-administered tracking system; and 
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(iv) An ERC must be surrendered and retired only once for 

purpose of compliance with this regulation through an EPAapproved ERC tracking system that meets the requirements of 

§60.5810, or by the EPA through an EPA-administered tracking 

system. 

(3) Your plan must specify that an ERC does not qualify for 

the compliance demonstration specified in paragraph (c)(1) of 

this section if it does not meet the requirements of paragraph 

(c)(2) of this section or if any State has used that same ERC 

for purposes of demonstrating achievement of its State measures. 

The plan must additionally include provisions that address 

requirements for revocation or adjustment that apply if an ERC 

issued by the State is subsequently found to have been 

improperly issued. 

(4) Your plan must include provisions either allowing for 

or restricting banking of ERCs between compliance periods for 

affected EGUs, and provisions not allowing any borrowing of any 

ERCs from future compliance periods by affected EGUs or eligible 

resources. 

(d) If you want an affected EGU subject to a rate-based 

emission standard (whether under an emission standardstandards

plan or as a part of the federally enforceable backstop in a 

stateState measures plan) to be able to use ERCs issued pursuant 

to your stateState measures to demonstrate compliance with its 
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emission standard, to meet the requirements of § 60.5775, such 

ERCs must meet the requirements of § 60.5791 and § 

60.5792paragraphs (c) of this section. 

(f) States may submit aEmission Rate Credit Requirements

rate-based emission trading program with alternative components 

other than those described in § 60.5791 through § 60.5797 so 

long as the submittal satisfactorily demonstrates that the 

trading system and its alternative components are at least as 

stringent in all respects as those in § 60.5791 through § 

60.5797.

 

§60.5795 What affected EGUs qualify for generation of ERCs? 

(a) For issuance of ERCs to affected EGUs, the plan must 

specify the accounting method and process for ERC issuance. For 

plans that require that affected EGUs meet a rate-based CO2

emission goal, where all affected EGUs have identical emission 

standards, you must specify the accounting method listed in 

paragraph (a)(1) of this section for generating ERCs. For plans 

that require affected EGUs to meet the CO2 emission performance 

rates or CO2 emission goals where affected EGUs have emission 

standards that are not equal for all affected EGUs, you must 

specify the accounting methods listed in paragraphs (a)(1) and 

(2) of this section for generating ERCs. 

(1) You must include the calculation method for determining 
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the number of ERCs, denominated in MWh, that may be issued to an 

affected EGU that is in compliance with its emission standard, 

based on the difference between its emission standard and its CO2

emission rate for the compliance period; and 

(2) You must include the calculation method for determining 

the number of ERCs, denominated in MWh, that may be issued to 

affected EGUs that meet the definition of a stationary 

combustion turbine based on the displaced emissions from 

affected EGUs not meeting the definition of a stationary 

combustion turbine, resulting from the difference between its 

annualized net energy output in MWh for the calendar year(s) in 

the compliance period and its net energy output in MWh for the 

2012 calendar year (January 1, 2012, through December 31, 2012). 

(b) Any ERCs generated through the method described as 

required by paragraph (a)(2) must not be used by any affected 

EGUs other than steam generating units or IGCCs to demonstrate 

compliance as prescribed under §60.5790(c)(1). 

(c) Any states in a multi-State plan that requires the Emission 

Rate Credit Requirements

use of ERCs for affected EGUs to comply with their emission 

standards must have functionally equivalent requirements 

pursuant to paragraphs (a)(1) and (2) of this section for 

generating ERCs. 

§60.57915800 What Emission Rate Creditsother resources qualify 
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for use in my state plan? issuance of ERCs?

 (a) An ERC qualifies for the compliance demonstration 

specified in §60.5785, and will be considered a valid qualifying 

ERC for the purpose of inclusion in a plan if it meets each of 

the following requirements: 

 (1) It was issued based on energy generated or saved (a) 

ERCs may only be issued for generation or savings produced on or 

after January 1, 2022, from a qualifying ERC generating to an 

eligible resource, by a state (or it’s state agent) with a 

qualified state ERC tracking system that meets each of the 

requirements of section 60.5792 and was approved by EPA in its 

plan; 

 (2) It represents one MWh of energy generated or saved 

(each one MWh can only generate one ERC) from a qualifying ERC 

generating resource with zero associated CO2 emissions (in the 

case of a qualifying ERC generating resource that emits a 

fractional MWh, aggregation to one MWh is required); 

 (3) It has a unique serial number, where the serial number 

must begin with the two digit postal abbreviation of the state 

in which it was issued and be followed by an identification 

number issued by the state that identifies the location where 

the ERC was generated; 

 in paragraphs (a)(1) through (4) Its CO2 emissions have 

not been transferred outside the ERC;of this section.
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 (5) It is and has been owned by only one person at one 

time; 

 (6) It exists in only one account on a qualified state or 

EPA ERC tracking system; and 

 (7) It was issued to a qualifying ERC generating resource 

that is (1) Resources qualifying for eligibility only include 

resources that increased new installed electrical generation 

nameplate capacity, or new electrical savings measures installed 

or implemented on or after January 1, 2013. If a resource had a 

nameplate capacity uprate, ERCs may be issued only for the 

difference in generation between the uprated nameplate capacity 

and its nameplate capacity prior to the uprate. ERCs must not be 

issued for generation for an uprate that followed a derate that 

occurred on or after January 1, 2013. A resource that is 

relicensed or receives a license extension is considered 

existing capacity and is not an eligible resource, unless it 

receives a capacity uprate as a result of the relicensing 

process that is reflected in its relicensed permit. In such a 

case, only the difference in nameplate capacity between its 

relicensed permit and its prior permit is eligible to be issued 

ERCs. 

(2) The resource must be connected to, and deliver energy 

to or save electricity on, the electric grid in the contiguous 

United States. 
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 (3) The resource is located in a stateeither: 

(i) A State whose affected EGUs are subject to rate-based 

emission standards or state measures pursuant to this 

regulation, unless the qualifying ERC generating resource is 

located in a state; or 

(ii) A State with mass-based emission standards, and the 

qualifying ERC generating resource hascan demonstrate (e.g., 

through a power purchase agreement or contract for delivery of 

its generation into a state) that the electricity generated is 

delivered with the intention to meet load in a State with 

affected EGUs which are subject to rate-based emission standards 

pursuant to this regulation, and was treated as a generation 

resource used to serve regional load that included the State

whose affected EGUs are subject to rate-based emission standards

or state measures pursuant to this regulation.. In this 

situation the only type of eligible resource in the State with 

mass-based emission standards is renewable generating 

technologies listed in (a)(4)(i) of this section. 

 (b) Nothing in paragraph (a) of this section precludes an 

ERC from representing other environmental attributes, in 

addition to its CO2 emission. 

 (c) An ERC may be transferred bundled together with an 

underlying MWh of energy generated that it was based on or 

unbundled from it; however, only the ERC and not the underlying 
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MWh of energy (whether bundled or unbundled) may be used for 

purpose of compliance with this regulation. 

 (d) (4) The resource falls into one of the following 

categories of resources: 

(i) Renewable electric generating technologies using one of 

the following renewable energy resources: wind, solar, 

geothermal, hydro, wave, tidal; 

(ii) Qualified biomass; 

 (iii) Waste-to-energy (biogenic portion only); 

(iv) Nuclear power; 

(v) A non-affected combined heat and power unit, including 

waste heat power; 

(vi) A demand-side EE or demand-side management measure 

that saves electricity and is calculated on the basis of 

quantified ex post savings, not “projected” or “claimed” 

savings; or 

 (vii) A category identified in a State plan and approved 

by the EPA to generate ERCs. 

(b) Any ERCresource that does not meet the requirements of 

this subpart or an approved State plan cannot be used in the 

issued ERCs for use by an affected EGU with its compliance 

demonstration required under section §60.5785 and is 

consequently an invalid ERC.5790(c).

§ 60.5792 How can an affected EGU use an ERC for demonstrating 
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compliance? 

 (a) An ERC may be used in the compliance demonstration 

specified in § 60.5785 if: 

 (1) It meets the requirements of § 60.5791 and this 

subpart; 

 (2) It is surrendered only once by one affected EGU for 

purpose of compliance with this regulation in accordance with § 

60.5793 (e); and 

 (3) It is retired through a qualified state ERC tracking 

system that meets the requirements of § 60.5793, or through an 

EPA ERC tracking system. 

 (b) An ERC may not be used in the compliance demonstration 

specified in § 60.5785 if any state has used that same ERC for 

purposes of demonstrating achievement of its state measures. 

 (c) An affected EGU subject to an emission standard is 

prohibited from including ERCs that were generated from an 

activity, project or program in a state with affected EGUs 

subject to mass-based emission standards in its compliance 

demonstration required under § 60.5785, unless the requirements 

of § 60.5791(a)(7) are met. 

 (d) Provided it only surrenders an ERC for retirement once, 

an affected EGU can retire the same ERC for compliance with this 

regulation and for compliance with other state and local 

requirements. An affected EGU cannot retire an ERC for its 
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compliance with this regulation and transfer the ERC to another 

entity for compliance with a state or local requirement. 

§ 60.5793 What is a qualified state ERC tracking system? 

 (a) A qualified state ERC tracking system must meet 

each of the requirements of (c) ERCs may not be issued to any of 

the following: 

(1) New, modified, or reconstructed EGUs that are subject 

to subpart TTTT of this part, except combined heat and power 

(CHP) units that meet the requirements of a CHP unit under 

paragraph (a); 

(2) EGUs that do not meet the applicability requirements of 

§§60.5845 and 60.5850, except CHP units that meet the 

requirements of a CHP unit under paragraph (a); 

(3) Measures that reduce CO2 emissions outside the electric 

power sector, including GHG offset projects representing 

emission reductions that occur in the forestry and agriculture 

sectors, direct air capture, and crediting of CO2 emission 

reductions that occur in the transportation sector as a result 

of vehicle electrification; and 

(4) Any measure not approved by the EPA for issuance of 

ERCs in connection with a specific State plan. 

(d) You must include the appropriate requirements in paragraphs 

(b) through (n). 

 (b) Basic Functions. A qualified state ERC tracking system 
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is a system that electronically issues and/or accepts, tracks, 

transfers, and retires ERCs that meet the requirements of § 

60.5791 and the remainder of this subpart. 

 (c) Account structure. A qualified state ERC tracking 

system must include accounts for the types of uses listed in 

paragraphs (cd)(1) through (3) of this sectionfor an applicable 

eligible resource in your plan. 

 (1) A general use account, which affected EGUs, 

qualifying ERC (1) If qualified biomass is an eligible resource, 

the plan must include a description of why the proposed 

feedstocks or feedstock categories should qualify as an approach 

for controlling increases of CO2 levels in the atmosphere as well 

as the proposed valuation of biogenic CO2 emissions. In addition, 

for sustainably-derived agricultural and forest biomass 

feedstocks, the state plan must adequately demonstrate that such 

feedstocks appropriately control increases of CO2 levels in the 

atmosphere and methods for adequately monitoring and verifying 

these feedstock sources and related sustainability practices. 

For all qualified biomass feedstocks, plans must specify how 

biogenic CO2 emissions will be monitored and reported, and 

identify specific EM&V, tracking and auditing approaches. 

(2) If waste-to-energy is an eligible resource, the plan 

must assess both their capacity to strengthen existing or 

implement new waste reduction, reuse, recycling and composting 
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programs, and measures to minimize any potential negative 

impacts of waste-to-energy operations on such programs. 

Additionally the plan must include a method for determining the 

proportion of total MWh generation from a waste-to-energy 

facility that is eligible for use in adjusting a CO2 emission 

rate (i.e., that which is generated from biogenic materials). 

(3) If carbon capture and utilization (CCU) is an eligible 

resource in a plan, the plan must include analysis supporting 

how the proposed qualifying CCU technology results in CO2

emission mitigation from affected EGUs and provide monitoring, 

reporting, and verification requirements to demonstrate the 

reductions. 

(e) States and areas of Indian country that do not have any 

affected EGUs, and other countries, may provide ERCs to adjust 

CO2 emissions provided they are connected to the contiguous U.S. 

grid and meet the other requirements for eligibility and 

eligible resources included in this section. 

§60.5805 What is the process for the issuance of ERCs? 

 If your plan uses ERCs your plan must include the process 

and requirements for issuance of ERCs to affected EGUs and 

eligible resources set forth in paragraphs (a) through (f) of 

this section. 

 (a) Eligibility application. Your plan must require that, 

to receive ERCs, the owner or operator must submit an 
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eligibility application to you that demonstrates that the 

requirements of your State plan as approved by the EPA as 

meeting §60.5792 (for an affected EGU) or §60.5800 (for an 

eligible resource) are met, and, in the case of an eligible 

resource, includes at a minimum: 

 (1) Documentation that the eligibility application has only 

been submitted to you, or pursuant to an EPA-approved multiState collaborative approach; 

 (2) An EM&V plan that meets the requirements of the State 

plan as approved by the EPA as meeting §60.5795; and 

(3) A verification report from an independent verifier that 

verifies the eligibility of the eligible resource to be issued 

an ERC and that the EM&V plan meets the requirements of the 

State plan as approved by the EPA of meeting §60.5795. 

 (b) Registration of eligible resources. Your plan must 

require that any affected EGU or eligible resource register with 

an ERC tracking system that meets the requirements of §60.5810 

prior to the issuance, and your plan must specify that you will 

only register an affected EGU or eligible resource after you 

approve its eligibility application and determine that the 

requirements of paragraph (a) of this section are met. 

(c) M&V reports. For an eligible resource registered 

pursuant to paragraph (b) above, your plan must require that, 

prior to issuance of ERCs by you, the owner or operator must 
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submit the following: 

(1) An M&V report that meets the requirements of your State 

plan as approved by the EPA as meeting §60.5835; and 

 (2) A verification report from an independent verifier that 

verifies that the requirements of the M&V report are met. 

 (e) Issuance of ERCs. Your plan must specify your procedure 

for issuance of ERCs based on your review of an M&V report and 

verification report, and must require that ERCs be issued only 

on the basis of energy actually generated or saved, and that 

only one ERC is issued for each verified MWh. 

 (f) Tracking system. Your plan must require that ERCs may 

only be issued through an ERC tracking system approved as part 

of the State plan. 

(g) Error Adjustment. Your plan must include a mechanism to 

adjust the number of ERCs issued if any are issued based on 

error (clerical, formula input error, etc.). 

(h) Qualification status of an eligible resource. Your plan 

must include a mechanism to temporarily or permanently revoke 

the qualification status of an eligible resource, such that it 

can no longer be issued ERCs for at least the duration that it 

does not meet the requirements for being issued ERCs in your 

State plan. 

(i) Qualification status of an independent verifier. 

(1) Eligibility. To be an independent verifier, a person 
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must be approved by the State as: 

(A) An independent verifier, as defined by this regulation; 

and 

(B) Eligible to verify EM&V plans and/or M&V reports per 

the requirements of the approved State plan as meeting §§60.5830 

and 60.5835 respectively. 

(2) Revocation of qualification. Your plan must include a 

mechanism to temporarily or permanently revoke the qualification 

status of an independent verifier, such that it can no longer 

verify EM&V plans or M&V reports for at least the duration of 

the period it does not meet the requirements of your State plan. 

§60.5810 What applicable requirements are there for an ERC 

tracking system? 

(a) Your plan must include provisions for an ERC tracking 

system, if applicable, that meets the following requirements: 

(1) It electronically records the issuance of ERCs, 

transfers of ERCs among accounts, surrender of ERCs by affected 

EGUs as part of a compliance demonstration, and retirement or 

cancellation of ERCs; and 

(2) It documents and provides electronic, internet-based 

public access to all information that supports the eligibility 

of eligible resources and issuance of ERCs and functionality to 

generate reports based on such information, which must include, 

for each ERC, an eligibility application, EM&V plan, M&V 
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reports, and independent verifier verification reports. 

(b) If approved in a State plan, an ERC tracking system may 

provide for transfers of ERCs to/from another ERC tracking 

system approved in a State plan, or provide for transfers of 

ERCs to/from an EPA-administered ERC tracking system used to 

administer a federal plan. 

Mass Allocation Requirements 

§60.5815 What are the requirements for State allocation of 

allowances in a mass-based program? 

(a) For a mass-based trading program, a State plan must 

include requirements for CO2 allowance allocations according to 

paragraphs (b) through (f) of this section. 

(b) Provisions for allocation of allowances for each 

compliance period for each affected EGU prior to the beginning 

of the compliance period. 

(c) Provisions for allocation of set-aside allowance, if 

applicable, must be established to ensure that the eligible 

resources must meet the same requirements for the ERC eligible 

resource requirements of §60.5800, and the State must include 

eligibility application and verification provisions equivalent 

to those for ERCs in §60.5805 and EM&V plan and M&V report 

provisions that meet the requirements of §60.5830 and §60.5835. 
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(d) Provisions for adjusting allocations if the affected 

EGUs or eligible resources are incorrectly allocated CO2

allowances. 

(e) Provisions allowing for or restricting banking of 

allowances between compliance periods for affected EGUs. 

(f) Provisions not allowing any borrowing of emissions from 

future compliance periods by affected EGUs. 

§60.5820 What are my allowance tracking requirements? 

(a) Your plan must include provisions for an allowance 

tracking system, if applicable, that meets the following 

requirements: 

(1) It electronically records the issuance of allowances, 

transfers of allowances among accounts, surrender of allowances 

by affected EGUs as part of a compliance demonstration, and 

retirement of allowances; and 

(2) It documents and provides electronic, internet-based 

public access to all information that supports the eligibility 

of eligible resources and issuance of set aside allowances and 

functionality to generate reports based on such information, 

which must include, for each set aside allowance, an eligibility 

application, EM&V plan, M&V reports, and independent verifier 

verification reports. 

(b) If approved in a State plan, an allowance tracking 

system may provide for transfers of allowances to/from another 
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ERC tracking system approved in a State plan, or provide for 

transfers of allowances to/from an EPA-administered allowance 

tracking system used to administer a federal plan. 

§60.5825 What is the process for affected EGUs to demonstrate 

compliance in a mass-based program? 

 (a) A plan must require affected EGUs owners and operators 

to demonstrate compliance with emission standards in a mass 

based program by holding an amount not less than the tons of 

total CO2 emissions for such compliance period from all affected 

EGUs at the facility in the account for the affected EGU’s 

emissions in the allowance tracking system required under 

60.5820 during the applicable compliance period.

 (b) In a mass-based trading program a plan may allow 

multiple affected EGUs co-located at the same facility to 

demonstrate that they are meeting the applicable emission 

standards on a facility-wide basis by the owner or operator 

holding enough allowances to cover all the affected EGUs at the 

facility. 

 (1) If there are not enough allowances to cover the 

facility’s affected EGUs’ emissions then there must be 

provisions for determining the compliance status of each 

affected EGU located at that facility. 

Evaluation Measurement and Verification Plans and Monitoring and 

Verification Reports 
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§60.5830 What are the requirements for EM&V plans for eligible 

resources? 

(a) If your plan requires your affected EGUs to meet their 

emission standards in accordance with §60.5790, your plan must 

include requirements that any EM&V plan that is submitted in 

accordance with the requirements of §60.5805, in support of the 

issuance of an ERC or set-aside allowance that can be used in 

accordance with §60.5790, must meet the EM&V criteria approved 

as part of your State plan. 

(b) Your plan must require each EM&V plan to include 

identification of the eligible resource and its applicable 

approved eligibility application. 

(c) Your plan must require that an EM&V plan must contain 

specific criteria, as applicable to the specific eligible 

resource. For example, for RE resources, requirements discussing 

how the generation data will be physically measured on a 

continuous basis using a revenue-quality meter. 

(1) For demand-side EE, your State plan must require that 

each EM&V plan quantify and verify electricity savings on a 

retrospective (ex-post) basis using industry best-practice EM&V 

protocols and methods that yield accurate and reliable 

measurements of electricity savings. Your plan must also require 

each EM&V plan to include an assessment of the independent 

factors that influence the electricity savings, the expected 
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life of the savings (in years), and a baseline that represents 

what would have happened in the absence of the demand-side EE 

activity. Additionally, your plan must require that each EM&V 

plan include a demonstration of how the industry best-practices 

protocol and methods were applied to the specific activity, 

project, measure, or program covered in the EM&V plan, and 

include an explanation of why these protocols or methods were 

selected. 

(d) For EM&V plans to be acceptable, eligible resources 

must clearly demonstrate how all such best-practice approaches 

will be applied for the purposes of quantifying and verifying 

MWh results. Subsequent reporting of demand-side EE savings 

values must demonstrate and explain how the EM&V plan was 

followed. 

§60.5835 What are the requirements for M&V reports for eligible 

resources?

(a) If your plan requires your affected EGUs to meet their 

emission standards in accordance with §60.5790, your plan must 

include requirements that any M&V report that is submitted in 

accordance with the requirements of §60.5805, in support of the 

issuance of an ERC or set-aside allocation that can be used in 

accordance with §60.5790, must meet the requirements of this 

section. 

(b) Your plan must require that each M&V report include the 
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following: 

(1) For the first M&V report submitted, documentation that the 

energy-generating resources, and any other person may establish 

an account for holding and trading ERCs. 

 (2) A surrender account, into which affected EGUs will 

place ERCs intended for use in compliance with an emission 

standard or state measure, and from which the ERCs will be 

retired for purpose of compliance with a plan. 

 (3) A retirement account, into which the qualified state 

ERC tracking system will place all ERCs retired for purpose of 

compliance with this regulation. 

 (d) ERC eligibility, generation and issuance. A qualified 

state ERC tracking system must meet the requirements in 

paragraphs (d)(1) through (6) for ERC issuance. 

 (1) Registration. A qualifying ERC generating resource 

registers with the qualified state ERC tracking system pursuant 

to the requirements of paragraph (l) of this section, and an 

independent third party verifier registers with the qualified 

ERC tracking system pursuant to the requirements of paragraph 

(m) of this section. 

 (2) Eligibility approval. A qualifying ERC generating 

resource submits to the qualified ERC tracking system an EM&V 

eligibility application that is energy-saving measures, or 

practices were installed or implemented consistent with EPA’s 
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minimum criteria set forth in § 60.5795. An independent third 

party verifier that meets the requirements of § 60.5797 reviews 

the EM&V eligibility application and certifies, in a 

verification assurance plan that meets the requirements of 

§60.5796 that the particular activity, project, or program 

covered by the EM&V eligibility application that is consistent 

with EPA’s minimum criteria set forth in § 60.5795. The state or 

its state agent approves the eligibility of the particular 

activity, project, or program covered by the EM&V eligibility 

application to generate ERCs for use in compliance with this 

regulation. the description in the approved eligibility 

application required in §60.5805(a).

 (3) Registration and eligibility approval may occur at the 

same time as submission of the first post-project EM(2) Each M&V 

report or in advance of it. 

 (4) ERC issuance. 

 (i) Following implementation of the particular activity, 

project or program specified in paragraph (d)(1) of this 

section, an affected EGU or qualifying ERC generating resource 

submits to the qualified state ERC tracking system a postproject EM&V report that is consistent with EPA’s minimum 

criteria set forth in § 60.5795 and reports the MWh of energy 

generation or energy savings attributable to the activity, 

project or program over the specific period and as covered by 
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the EM&V plan. Such EM&V plans must be submitted no less 

frequently than annually for a particular activity, project or 

program. 

 (ii) An independent third party verifier that meets the 

requirements of § 60.5797 reviews the post-project EM&V report 

and provides a verification assurance plan that meets the 

requirements of § 60.5796. Such verification assurance plans 

shall be submitted on the same periods as the EM&V reports that 

they verify, which according to paragraph (d)(4)(i) must be no 

less frequently than annually for a particular activity, project 

or program. 

 (iii) The state or its state agent reviews the post-project 

EM&V report and verification assurance plan and any other 

credible evidence, ensures that the EM&V report and verification 

assurance plan meet the requirements of § 60.5795 and § 60.5796, 

determines the number of ERCs that were generated (if any) 

during the specific period covered by the EM&V plan, and issues 

a corresponding amount of ERCs into the generation account of 

the affected EGU or qualifying ERC generating resource. 

 (5) Frequency of ERC issuance. A qualified state ERC 

tracking system shall issue ERCs no less frequently than on an 

annual basis (i.e., issuance on a shorter basis, such as 

quarterly or biannual issuance is permissible). 

 (6) Each EM&V report and verification assurance plan shall 
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be submitted on forms and using procedures specified by the 

plan. 

 (e) Surrender of ERCs. A qualified ERC tracking system must 

ensure that an affected EGU will place ERCs intended for use in 

compliance with a plan and sufficient for its compliance 

demonstration in § 60.5785 in its surrender account prior to the 

applicable compliance date, and once an ERC is placed in a 

surrender account, the affected EGU will not be able to remove 

the ERC from the account. 

 (f) Retirement of ERCs. A qualified ERC tracking system 

must retire any ERCs placed in surrender accounts by the 

compliance date for the affected EGUs pursuant to its plan and 

ensure that, once an ERC is retired, the ERC shall no longer be 

transferable to another account on that tracking system or any 

other tracking system. 

 (g) ERC Transfers. 

 (1) Transfers to/from other qualified ERC tracking systems. 

A qualified ERC tracking system may accept into its tracking 

system ERCs from another qualified ERC tracking system and may 

preclude such transfers. 

 (2) Transfers to/from an EPA ERC tracking system. To 

transfer ERCs to/from an EPA CPP ERC tracking system, the 

qualified state ERC tracking system must be registered for such 

use by the EPA. 
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 (h) ERC Adjustment. A qualified ERC tracking system 

has at leastmust include the following mechanisms in place to 

make adjustments to the number of qualifying ERCs issued, after 

generation or savings data is reported to it, and after the ERCs 

were issued, as data from the prior period are finalized: :

 (1) Any prior period adjustments must be reported to the 

qualified ERC tracking system by the appropriate reporting 

entity as soon as possible, with the reason for the adjustment 

specified and data in support of the adjustment provided. 

 (2) If qualifying ERCs have not yet been created for the 

original generation amount to which the adjustment applies, the 

credit or debit adjustment will be reflected in the number of 

qualifying ERCs issued in the current period. 

 (3) If qualifying ERCs have been created, the credit or 

debit adjustment will be treated as an adjustment to the number 

of qualifying ERCs issued to the qualifying affected EGU or ERC 

generating resource in the prior period. 

 (i) Mechanism to halt issuance. A qualified ERC tracking 

system has mechanisms in place to temporarily or permanently 

halt issuance of specific ERCs, to remove specific ERC 

generating resources from its tracking system, and/or to reject 

the transfer of ERCs that do not meet the requirements of § 

60.5791. 

 (j) ERC Information. A qualified ERC tracking system must 
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track, at a minimum, the information in paragraphs (j)(1) 

through (14) of this section. 

 (1) The ERC tracking system from which the ERC is issued. 

 (2) Account holder name and identification number of ERCs. 

 (3) Qualifying ERC generating resource facility 

identification number, name, state, and contact information 

including street address, mailing address, phone number, and 

email. 

 (4) Type of qualifying ERC generating resource according to 

the definition in section § 60.5840. 

 (5) Date the affected EGU or qualifying ERC generating 

resource commenced generation or saving of energy. 

 (6) Eligibility of ERCs from qualifying ERC generating 

resource for compliance with this regulation 

 (7) Quantity of ERCs and fractional roll over ERCs for use 

in subsequent compliance periods. 

 (8) Unique ERC serial numbers. 

 (9) Vintage of ERCs, with last quarter and year of 

generation contributing to an accumulated MWh recorded. 

 (10) Parties to each ERC trade, and dates of each ERC 

trade. 

 (11) Date an ERC was surrendered. 

 (12) Date an ERC was retired. 

 (13) In the case of a qualifying ERC generator that is 
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producing electrical output for use on a utility grid, the 

following must be included: 

 (i) The qualifying ERC generating resource generation 

classification according to the following (if applicable): 

 (A) Generation reported by a control area operator on a 

unit-specific basis; 

 (B) Small wholesale generation; 

 (C) Wholesale generation also serving on-site loads; or 

 (D) Customer-sited distributed generation. 

 (ii) The data reporting entity type and identity of 

specific entity (e.g., control area operator, self-reporting). 

 (iii) The maximum electrical generator nameplate capacity 

in MW; 

 (iv) Information on whether multiple qualifying ERC 

generating resource generating units are aggregated under one 

meter 

 (14) In the case of a qualifying energy saving activity, 

you must have sufficient tracking requirements for 

quantification of the MWh of energy saved. 

 (k) Reports. A qualified ERC tracking system provides at 

least the following reports: 

 (1) EGU Reports. A qualified ERC tracking system commits to 

provide the ability for each ERC holder to obtain reports of 

their account activity that includes the information specified 
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in paragraph (e) of this section on at least an annual basis, 

and provides the ability for each ERC holder to obtain such 

reports for a period of at least 5 years from the date of ERC 

retirement. 

 (2) Public Reports. A qualified ERC tracking system shall 

provide electronic, internet-based access to the following 

reports to the public: all registered account holders on the 

qualified state ERC tracking system, all registered generators 

on the qualified state ERC tracking system, all qualifying ERC 

generating resource EM&V plans, all independent third party 

verifiers, all verification assurance plans, all ERC issuances, 

all annual aggregate ERC activity statistics on at least an 

annual basis (issuance of ERCs, trades within the qualified 

state ERC tracking system, transfers in or out of the qualified 

state ERC tracking system, and retirements for purpose of this 

regulation on the qualified state ERC tracking system). The 

qualified state ERC tracking system shall provide this 

functionality for as long as this regulation is effective. 

 (3) EPA and state regulator reports. A qualified state ERC 

tracking system shall provide the ability for the EPA and state 

regulators to obtain electronically a report that contains 

comprehensive information regarding all ERCs issued, traded or 

retired by the qualified state ERC tracking system for purpose 

of compliance with this regulation, sortable by each of the 
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fields listed paragraph (j) of this section. The qualified state 

ERC tracking system shall provide this functionality for as long 

as this regulation is effective. 

 (l) Qualifying ERC generating resource registration 

requirements. Prior to issuing ERCs from an affected EGU or 

qualifying ERC generating resource for purpose of compliance 

with this regulation, a qualified state ERC tracking system 

shall enter an agreement with the owner or operator of that 

qualifying ERC generating resource that provides for each of the 

following: 

 (1) Reporting of 100 percent of the qualifying ERC 

generating resource’s electrical generation or energy savings to 

that qualified state ERC tracking system; 

 (2) Annual certification by the owner or operator of the 

qualifying ERC generating resource that it is registered with 

only one tracking system for issuance of ERCs, and is eligible 

to generate ERCs in compliance with § 60.5791; 

 (3) In the case of a qualifying energy ERC generator annual 

submission of a copy of the qualifying ERC generating resource’s 

U.S. Energy Information Agency’s Annual Electric Generator 

Report Form EIA-860 to the qualified state ERC tracking system, 

or, if the qualifying ERC generating resource generates less 

than 1 MW/year, annual submission of registration data that 

would be included on a Form EIA-860 if that entity was required 
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to submit Form EIA-860, 

 (4) Collection of data in accordance with any approved EM&V 

plan. 

 (5) In the case of a qualifying energy ERC generator, 

regular inspection of any meters according to appropriate 

industry protocols to ensure proper operation of the meter, 

 (6) Random inspections and audits of the qualifying ERC 

generating resource by an independent third party verifier that 

meets the requirements of § 60.5797, 

 (7) Notification of the qualified state ERC tracking 

system by the owner or operator of the qualifying ERC generating 

resource (i) Identification of the time period covered by the 

M&V report; 

(ii) A description of how relevant quantification methods, 

protocols, guidelines, and guidance specified in the EM&V plan 

were applied during the reporting period to generate the 

quantified MWh of generation or MWh of energy savings; 

(iii) Documentation (including data) of the energy 

generation and/or energy savings from any activity, project, 

measure, resource, or program addressed in the EM&V report, 

quantified and verified in MWh for the period covered by the M&V 

report, in accordance with its EM&V plan, and based on ex-post 

energy generation or savings; and 

(iv) Documentation of any change in qualifying ERC generating 
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resource ownership, the energy generation or savings capability 

of the eligible resource from the description of the resource in 

the approved eligibility application during the period covered 

by the M&V report and the date on which the change occurred, no 

later than 30 days after the sale closes. 

 (m) Independent third party verifier registration 

requirements. Prior to issuing ERCs based on a verification 

assurance plan by an independent third party verifier for 

purpose of compliance with this regulation, a qualified state 

ERC tracking system shall enter an agreement with the 

independent third party verifier that requires the verifier to 

register with the qualified state ERC tracking system, and meet 

the requirements of § 60.5797 and § 60.5796 of this subpart. 

 (n) Periodic audits of independent third party verification 

assurance plans. You must audit the qualified ERC tracking 

system no less frequently than annually of the content of a 50 % 

of the verification assurance plans and of at least 50 % of its 

independent third party verifiers]. Each independent third party 

verifier registered with its qualified state ERC tracking system 

shall be audited at least once every 3 years. 

 (1) You, the state must maintain the power to disaccredit 

or prohibit the use of any specific independent third party 

verifier in verification work pursuant to this regulation. 

§ 60.5795 What are the requirements for EM&V plans?
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 (a) General EM&V plan and report criteria. A qualifying ERC 

must be quantified based on energy generation or energy savings 

from a specific activity, project or program by a qualifying ERC 

generating resource that is quantified and verified as described 

in an EM&V plan or report that meets the requirements for that 

activity, project or program category set forth in § 60.5791, 

meets credible and appropriate industry-standard practices and 

guidance documents, and that meets the requirements of this 

section. 

 (b) Each EM&V plan or report must describe the specific 

activity, project or program and identify its location(s) and 

year(s) of installation and subsequently provide notice of any 

of the following: 

(1) A change in energy generation or savings capability of 

the qualifying ERC generating resource, and the date on which 

the change occurred, no later than 30 days from when the change 

is implemented, 

(2) A change to any of the essential generating or savings 

characteristics of the qualifying ERC generating resource, where 

essential generating characteristics shall mean any 

characteristics that affect the eligibility of the qualifying 

ERC generating resource for purpose of compliance with this 

regulation, including the type of qualifying ERC 

generatingand/or demonstration that the eligible resource, and 
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the date of the change. 

(c) Each EM&V plan or report must describe how the MWh 

associated with each ERC addressed in that plan or report will 

be quantified and verified, and each ERC must be quantified and 

verified based on ex-post energy generation or energy savings. 

(d) Criteria for a qualifying energy generating resource 

with a nameplate capacity of 10 kW or more and for a qualifying 

energy generating resource with a nameplate capacity of less 

than 10 kW for which metered data are available. For a 

qualifying energy generating resource with a nameplate capacity 

of 10 kW or more, or for a qualifying energy generating resource 

with a nameplate capacity of less than 10 kW for which metered 

data are available, to generate ERCs, its EM&V plan and EM&V 

reports must demonstrate that the requirements in paragraphs 

(d)(1) through (6) are met. 

(1) The generation data was physically measured using a 

revenue-quality meter, which shall mean a meter used by a 

control area operator for financial settlements, or a meter that 

meets the American National Standards Institute No. C12.20., 

Code for Electricity Metering, metering accuracy standards, or a 

meter that meets an alternative equivalent standard that has 

been approved in advance of its use to measure generation for 

purpose of compliance with this regulation by EPA. 

(2) The generating data was measured at the generator’s 
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bus bar. 

(3) Data from only one qualifying energy generating 

resource generating unit may be associated with each meter, and 

generation data may not be aggregated, unless the following 

provisions are met: 

(i) All of the generating units have the same essential 

generation characteristics 

(ii) The nameplate capacity of the individual units being 

aggregated is each less than 150 kW, and units collectively do 

not exceed a total nameplate capacity of 1 MW when aggregated, 

and 

(iii) The generation data are measured by the same type of 

meter. 

(4) The generation data was collected electronically by 

either a MV-90 meter data acquisition system or by pulse 

accumulator readings collected by the control area’s Energy 

Management System and telemetered from the generator to the 

control area operator, and the data was verified through a 

control area energy accounting or settlements process which 

occurs at least monthly. 

(5) The generation data was transmitted by a control area 

operator, and if the control area operator is affiliated with 

the owner or operator of the qualifying energy generating 

resource, a person at the control area operator who is precluded 
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from the ability to transfer or retire ERCs issued to that 

generator. 

(6) The generation data serves a load that otherwise would 

have been served by the grid if not for the generator. 

(i) ERCs shall not be issued for energy generation used to 

supply the ancillary equipment used to operate a generating 

station or substation (“station service”) or parasitic load on 

the generator’s side of the point of interconnection. 

(ii) For generators interconnected to transmission systems 

and with on-site loads other than station service drawing 

generation before the metering point, ERCs may be issued for onsite load, if the owner or operator of the qualifying energy 

generating resource can demonstrate that the metering used is 

capable of distinguishing between on-site load and station 

service. 

(e) Criteria for a qualifying energy generating resource 

with a nameplate capacity of less than 10 kW. For a qualifying 

energy generating resource with a nameplate capacity of less 

than 10 kW to generate ERCs, its EM&V plan and EM&V reports must 

demonstrate that the following requirements in paragraphs (e)(1) 

though (6) are met. 

(1) Metered data are unavailable. 

(2) At least 1 MW direct current is generated to the 

distribution or transmission system over a continuous 365 day 
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period. 

(3) Generation data may not be aggregated, unless the 

following provisions are met: 

(i) The nameplate capacity of the individual units being 

aggregated is each less than 150 kW, 

(ii) The units collectively do not exceed a total nameplate 

capacity of 1 MW when aggregated, 

(iii) All of the generating units have the same essential 

generation characteristics, and 

(iv) The generation data are measured by the same 

generation estimating software or algorithms. 

(4) Generation data is measured on at least a monthly basis 

using generation estimating software or algorithms that are 

based on an on-site inspection prior to interconnection and a 

resource study (wind, shading, solar irradiance, depending on 

the resource), or engineering information that takes into 

account the size, age, and type of qualifying energy generating 

resource. 

(5) The generation data was self-reported by the qualifying 

energy resource to its distribution utility and to its 

distribution utility through an electronic internet-based portal 

with software that reports total and hourly generation. 

(6) The generation data serves a load that otherwise would 

have been served by the grid if not for the generator. The ERC 
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is only based on generation transferred from the qualifying 

energy generating resource to the transmission or distribution 

grid, and is not based on the generation used on-site by the 

customer. 

(f) Criteria for a qualifying demand-side EE. In the case 

of qualifying demand-side EE, the following minimum components 

must be addressed in the EM&V plan or report for the specific 

activity, project or program (depending on the scope covered by 

the EM&V plan or report): 

(1) All demand-side EE savings used to adjust a CO2 

emissions rate must be quantified and verified using applicable, 

credible, and rigorous industry-standard practices and guidance 

documents. 

(2) All savings values must be which determined and 

reported in units of gross MWh relative to a specified baseline; 

in cases where gross savings values are not available (e.g., 

randomized control trials), net savings can be reported. 

(3) All savings values determined must be determined on a 

regular basis – at intervals sufficient to credibly document 

annual savings – by application of one or more non-control group 

approaches and/or control group approaches. 

 (4) All savings values assessed using deemed savings must 

be documented in a publicly available database and be reviewed 

and updated at least every 3 years. The database must indicate, 
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for each value, the conditions for which the value can be 

applied (i.e., climate, building type, and implementation 

mechanism). 

(5) For EE program categories that involve the installation 

of identifiable measures, verification using industry-standard 

techniques is required within the first year of program 

implementation. 

(6) If transmission and distribution losses are quantified, 

the adjustment must be based on the lesser of 6 percent of the 

site-level savings or the calculated statewide annual average 

transmission and distribution loss rate expressed as a 

percentage and based on values in the most recent year that is 

published in the US EIA State Electricity Profile. For 

transmission and distribution efficiency measures, MWh savings 

from voltage optimization must be calculated on the basis of 

industry-standard protocols and procedures identified in an EM&V 

plan. 

(7) The duration of EE program or project electricity 

savings must be determined using periodic verification 

assessments, industry-standard persistence studies, deemed 

estimates of effective useful life (EUL), or a combination of 

all three. 

(8) If deemed EUL estimates are used for determining the 

duration of savings, then zero savings must be assumed at the 
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end of a program, project, or measure life; if project or 

program persistence studies are conducted at least every 5 years 

to determine the duration of savings, then savings can be 

counted as long as the verification activities indicate

continued measure operation and performance.to meet the 

requirements of §60.5800. 

(9) All types of double counting must be considered and 

avoided; documentation of steps taken to avoid double counting 

must be provided in EM&V plans and EM&V reports. 

(g) EM&V plans for demand-side EE must describe and 

document the following: 

(1) The baseline energy usage conditions, with clear 

documentation and discussion of the rationale, applicability, 

and relevant data sources, protocols, and guidance documents 

used for defining the common practice baseline (CPB). 

(2) The selected EM&V method, associated assumptions, and 

data sources used to quantify savings from demand-side EE. 

(3) How major changes in independent variable conditions 

that affect energy consumption and savings estimates will be 

analyzed. 

(4) How the initial installation of EE will be verified 

within the first year of implementation for EE program 

categories that involve the installation of identifiable 

measures. 
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(5) How avoided transmission and distribution system losses 

will be included in EE savings values. 

(6) How the duration of EE program or project electricity 

savings will be determined. 

(7) How the rigor of quantifying MWh savings values will be 

assessed, and the methods used to control the types of bias or 

error relevant inherent to the applied EM&V techniques. 

(8) How double counting will be avoided through the use of 

tracking and accounting procedures to ensure that two or more 

programs do not separately claim savings from the same EE 

project or measure. 

(9) How the relevant protocols, guidelines, and guidance 

documents will be applied. 

(10) Any additional EM&V information needed to ensure that 

savings from EE programs and projects are credibly quantifiable 

and verifiable 

 (h) EM&V reports for demand-side EE must describe and 

document the following: 

(1) All demand-side EE savings used to adjust a CO2 

emissions rate must be quantified and verified using credible 

and appropriate industry-standard practices and guidance 

documents. 

(2) EM&V reports must document how applicable EM&V criteria 

were applied to quantify results. 
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(3) EM&V reports must include after-the-fact documentation 

of how relevant protocols, guidelines, and guidance documents 

were actually applied. 

(4) EM&V report submittals must include any additional EM&V 

information needed to ensure that savings from EE programs and 

projects were quantified and verified. 

(5) At applicable state plan check-in intervals with the 

EPA (in 2025, 2028, and 2030), states applying conventional EM&V 

must provide the EPA with access to applicable program- and 

project-level EM&V reports used to compile total MWh savings and 

generation. 

 (b) In each EM&V plan, the owner or operator of the 

affected EGU or qualifying ERC generating resource shall certify 

the following: 

 (1) I certify under penalty of law that I have personally 

examined, and am familiar with, the statements and information 

submitted in this document and all its attachments. Based on my 

inquiry of those individuals with primary responsibility for 

obtaining the information, I certify that the statements and 

information are to the best of my knowledge and belief true, 

accurate, and complete. I am aware that there are significant 

penalties for submitting false statements and information or 

omitting required statements and information, including the 

possibility of fine or imprisonment. 
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§ 60.5796 What are the requirements for a post-project ERC 

verification assurance plan? 

 (a) Your plan must ensure that all verification assurance 

plans that verify ERCs shall meet each of the requirements of 

paragraphs (a)(1) through (8) 

 (1) Verify the eligibility of the specific activity, 

project or program described in the particular EM&V plan or 

report for generating ERCs pursuant to this regulation. 

 (2) Verify that the EM&V plan or report meets the 

requirements of § 60.5795. 

 (3) Verify that the activity, project, or program is in 

place and has been implemented in accordance with each specific 

element in the EM&V plan or report (e.g., that the installation 

rate is met, that the installation meets quality standards, that 

the measures are operating correctly and have the potential to 

generate anticipated savings) 

 (4) Review any documents required in the EM&V plan or 

report and any documents necessary to verify the MWh generated 

by the qualifying ERC generating resource. 

 (5) Verify any calculations, and the appropriateness of the 

calculation methodology, used to generate credits. 

 (6) For a qualifying ERC energy resource, verify the 

metered data specified in of § 60.5795. 

 (7) For a qualifying ERC energy saving activity, verify 
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electricity savings metrics (incremental and cumulative 

savings). 

 (8) Employ an automatic data validity check to ensure that 

all generation or savings data from a qualified ERC generating 

resource is within an acceptable range for that specific 

generator and that erroneous and technically infeasible data is 

not entered. 

 (i) For metered generation, the data validity check shall 

compare reported electricity generation to an engineering 

estimate of the maximum generation potential of the qualified 

renewable energy resource, based on, at a minimum, its maximum 

nameplate capacity in MW and the number of days since the prior 

cumulative meter reading was entered in the qualified state ERC 

tracking system. If the data entered exceeds the estimated 

technically feasible generation, the generation will be 

designated “pending” until the reported data and the estimate 

are reconciled. 

 (b) Your plan must ensure that the subject of any 

verification assurance plans, shall not have the opportunity to 

review or influence any draft or final verification assurance 

plans before its submittal to the relevant oversight entity, and 

the independent third party verifier must share any drafts of 

its reports with the relevant oversight entity at the same time 

as it shares them with the subject of the report. 
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 (c) Your plan must ensure that in each verification 

assurance plan drafted by an independent third party verifier, 

the verifier shall certify the following: 

 (1) 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. 

§ 60.5797 What standards must the independent third party 

verifier meet? 

 (a) Your plan must ensure that any verification assurance 

plan must be drafted by a person (including any corporate parent 

or subsidiary, any contractors or subcontractors, and the actual 

person) who meets the following: 

 (1) Is a professional engineer or has other appropriate 

technical qualification; 

 (2) Is not an, and is not employed by or receiving payment 

(directly or indirectly) from any, owner or operator of an 

qualifying ERC generating resource (e.g., a renewable energy 
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resource, an energy efficiency project, etc.) or an affected 

EGU; 

 (3) Is free from any interest or the appearance of any 

interest in any qualifying ERC generating resource (including 

any role in implementation) or any affected EGU; 

 (4) Has not worked on the development or operation of the 

subject of the verification; 

 (5) Shall not own, buy, sell, or otherwise trade ERCs used 

for compliance with a plan or any other credit reflecting any 

environmental attribute related to the use, generation or saving 

of electricity; 

 (6) Attests, in its verification report, to compliance with 

the American Evaluation Association requirements for 

verification; and 

 (7) Has not been debarred, suspended, or proposed for 

debarment pursuant to the Government-wide Debarment and 

Suspension regulations, 40 CFR part 32, or the Debarment, 

Suspension and Ineligibility provisions of the Federal 

Acquisition Regulations, 48 CFR part 9, subpart 9.4. 

 (b) Your plan must ensure that any qualified state ERC 

tracking system and any independent third party verifier must 

maintain, for its employees, and must ensure the maintenance of, 

for any parties that it employs, professional liability 

insurance, as defined in 31 C.F.R. 50.5(q), through an insurance 
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provider that possess a financial strength rating in the top 

four categories from either Standard & Poor’s or Moody’s, 

specifically, AAA, AA, A or BBB for Standard & Poor’s, and Aaa, 

Aa, A, or Baa for Moody’s. Any entity covered by this paragraph 

shall disclose the level of professional liability insurance 

they possess when entering into contracts to provide 

verification services pursuant to this regulation. 

Applicability of Plans to Affected EGUs

§ 60.58005840 Does this subpart directly affect EGU owners or 

operators in my stateState? 

(a) This subpart does not directly affect EGU owners or 

operators in your stateState. However, affected EGU owners or 

operators must comply with the plan that a stateState or 

statesStates develop to implement the emission guidelines 

contained in this subpart. 

(b) If a stateState does not submit, or EPA disapproves, a 

final plan or initial plan submittal to implement and enforce 

the emission guidelines contained in this subpart by August 

31September 6, 2016, the EPA will implement and enforce a 

Federal plan, as provided in § 60.5720, to ensure that each 

affected EGU within the stateState that commenced construction 

on or before January 8, 2014 complies with all the provisions of 

this subpart. 
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§ 60.58055845 What affected EGUs must I address in my 

stateState plan?

 (a) The EGUs that must be addressed by your plan are 

any affected steam generating unit, IGCC, or stationary 

combustion turbine that commencescommenced construction on or 

before January 8, 2014. 

(b) An affected EGU is a steam generating unit, integrated 

gasification combined cycle (IGCC),, or stationary combustion 

turbine that meets the relevant applicability conditions 

specified in paragraph (b)(1) through (3) of this section. 

except as provided in §60.5850. 

(1) Serves a generator connected to a utility power 

distribution system with a nameplate capacity of 25 MW-net or 

greater (i.e., capable of selling greater than 2025 MW of 

electricity); 

(2) Has a base load rating (i.e., design heat input 

capacity) greater than 260 GJ/hr (250 MMBtu/hr) heat input of 

fossil fuel (either alone or in combination with any other 

fuel); and 

(3) Stationary combustion turbines that meet the definition 

of either a combined cycle or combined heat and power combustion 

turbine. 

§ 60.5810 5850 What EGUs are excluded from being affected EGUs

are exempt from my state plan? 
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 (a) Affected EGUs that are exemptexcluded from your 

plan includebeing affected EGUs are: 

(1) EGUs that are subject to subpart TTTT of this part as a 

result of commencing construction after the subpart TTTT 

applicability date; and those subject to subpart TTTT of this 

part as a result of commencing modification or reconstruction; 

 (2) Steam generating units and IGCC units that are 

currently and always have been subject to a federally 

enforceable permit limiting annual net-electric sales to onethird or less of its potential electric output, or 219,000 MWh 

or less; 

 (3(3) Non-fossil units (i.e., units that are capable 

of combusting 50 percent or more non-fossil fuel) that have 

always historically limited the use of fossil fuels to 10 

percent or less of the annual capacity factor or are subject to 

a federally enforceable permit limiting fossil fuel use to 10 

percent or less of the annual capacity factor. 

(4) Stationary combustion turbines not capable of 

combusting natural gas (e.g., not connected to a natural gas 

pipeline) 

(4) Your EGU is capable of combusting 50 percent (5) EGUs 

that are combined heat and power units that have always 

historically limited, or more non-fossil fuel andare subject to 

a federally enforceable permit currently limiting, or has 
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historically limited, fossil fuel use to 10% or less of the 

annual capacity factor; 

(5) EGUs that are a combined heat and power unit that is 

subject to a federally enforceable permit limiting, or has and 

always historically limitedlimiting, annual net-electric sales 

to a utility distribution system to the design efficiency times 

the potential electric output or 219,000 MWh (whichever is 

greater)), or less; 

(6) EGUs that serve a generator along with other steam 

generating unit(s), IGCC(s), or stationary combustion turbine(s) 

where the effective generation capacity (determined based on a 

prorated output of the base load rating of each steam generating 

unit, IGCC, or stationary combustion turbine) is 25 MW or less; 

(7) EGUs that are a municipal waste combustor unit that is 

subject to subpart Eb of this part; and 

(8) EGUs that are a commercial or industrial solid waste 

incineration unit that is subject to subpart CCCC of this part. 

§ 60.58155855 What are the CO2 emissionsemission performance 

rates for affected EGUs? 

(a) You must require, in your plan, emission standards on 

affected EGUs to meet the CO2 emission performance rates listed 

in tableTable 1 of this subpart except as provided in paragraph 

(b) of this section. In addition, you must set CO2 emission 
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performance rates for the interim steps, according to paragraph 

(a)(1) of this section. 

(1) You must set CO2 emission performance rates for your 

affected EGUs to meet during the interim step periods on average 

and as applicable for the two subcategories of affected EGUs. 

(b) You may elect to require your affected EGUs to meet 

emission standards that differ from the CO2 emission performance 

rates listed in Table 1 of this subpart, provided that you 

demonstrate that the affected EGUs are meetingin your State will 

collectively meet their CO2 emission performance rate by 

achieving statewide emission goals whichthat are equivalent and 

no less stringent than the CO2 emission performance rates listed 

in table 1. Your Table 1, and provided that your equivalent 

statewide CO2 emission goals may take one of the following forms: 

(1) Average statewide rate-based CO2 emission goals listed 

in tableTable 2 of this subpart, except as provided in 

paragraphparagraphs (c) and (d); or 

(2) Cumulative statewide mass-based CO2 emission goals 

listed in tableTable 3 of this subpart, except as provided in 

paragraphparagraphs (c) and (d). 

(c) If your plan incorporates CO2 emission goals listed in 

paragraphs (b)(1) or (2) of this section you may elect tomust

develop your own interim step goals if you do not wish to adopt 

the interim step goals provided in paragraph (b)(1) or 
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(b)(2).and final reporting period goal for your affected EGUs to 

meet either on average or cumulatively. Additionally the 

following applies if you elect to develop your own goals: 

(1) The interim period and interim steps CO2 emission goals 

must be in the same form, either both rate (in units of pounds 

per net MWh) or both mass (in tons); and 

(2) You must set interim step goals that will either on 

average or cumulatively meet the state’sState’s interim period 

goal, as applicable to a rate-based or mass-based goal. 

 (3) The initial and final CO2 emission goals that you elect 

to achieve in your plan may take different forms between the 

interim period and final period (e.g., a rate-based goal for the 

interim period and a mass-based goal for the final period), 

however, the form of a state CO2 emission goal in your plan may 

not be changed once a relevant period has begun. 

(d) Your plansplan’s interim period and final period CO2

emission goals included in a plan that your state or states 

elects to achieveincorporated pursuant to paragraph (b)(1) or 

(2) of this section, may be changed in the plan only according 

to situations listed in paragraphs (d)(1) and (2through (3) of 

this section. If a situation requires a plan revision, you must 

follow the procedures in § 60.5785 to submit a plan revision. 

(1) If your plan implements CO2 emission goals for your 

affected EGUs to meet, you may submit statea plan revisionsor 
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plan revision, allowed in §60.5785, to make corrections to your 

state goal, which them, as a result in no more than a 2 percent 

changeof changes in the state goalinventory of affected EGUs; 

and 

(2) You may address EGUs that become subject to subpart 

TTTT of this Partpart and are no longer considered affected EGUs 

for incorporation in a plan. 

§ (3) If you elect to require your affected EGUs to meet 

emission standards or State measures, in addition to or in lieu 

of emission standards, to meet mass-based CO2 emission goals in 

your plan, you may elect to incorporate the mass emissions from 

EGUs that are subject to subpart TTTT of this part that are 

considered new affected EGUs under subpart TTTT of this part. 

(e) If your plan submittal requires your affected EGUs to 

meet State measures in addition to or in lieu of emission 

standards, you must only use the mass-based goals allowed for in 

paragraph (b)(2) of this section to demonstrate that your 

affected EGUs are meeting the required emissions performance. 

(f) Nothing in this subpart precludes an affected EGU from 

complying with its emission standard or you from meeting your 

State measures. 

§60.58205860 What applicable monitoring, recordkeeping, and 

reporting requirements do I need to include in my plan for 

affected EGUs? 
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(a) Your plan must include monitoring for affected EGUs 

that is no less stringent thatthan what is described in (a)(1) 

through (68) of this section. 

(1) The owner ofor operator of an affected EGU (or group of 

affected EGUs that share a monitored common stack) that is 

required to meet a rate -based or mass-based emission standard 

theystandards must prepare a monitoring plan in accordance with 

the applicable provisions in § 75.53(g) and (h) of this chapter. 

, unless such a plan is already in place under another program 

that requires CO2 mass emissions to be monitored and reported 

according to part 75 of this chapter. 

(2) The(2) For rate-based emission standards, each 

compliance period shall include only “valid operating hours” in 

the compliance period, i.e., full or partial unit (or stack) 

operating hours for which: 

(i) “Valid data” (as defined in §60.5880) are obtained for 

all of the parameters used to determine the hourly CO2 mass 

emissions (lbs). For the purposes of this subpart, substitute 

data recorded under part 75 of this chapter are not considered 

to be valid data; and 

(ii) The corresponding hourly net energy output value is 

also valid data (Note: for operating hours with no useful 

output, zero is considered to be a valid value). 
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(3) For rate-based emission standards, the owner or 

operator of an affected EGU must measure and report the hourly 

CO2 mass emissions (lbs) from each affected unit using the 

procedures in paragraphs (a)(23)(i) through (vvi) of this 

section, except as otherwise provided in paragraph (a)(34) of 

this section. 

(i) The owner or operator of an affected EGU must install, 

certify, operate, maintain, and calibrate a CO2 continuous 

emissions monitoring system (CEMS) to directly measure and 

record CO2 concentrations in the affected EGU exhaust gases 

emitted to the atmosphere and an exhaust gas flow rate 

monitoring system according to § 75.10(a)(3)(i) of this chapter. 

If the owner or operator of an affected EGU measures CO2

concentration on a dry basis, they75.10(a)(3)(i) of this 

chapter. However, when an O2 monitor is used this way, it only 

quantifies the combustion CO2; therefore, if the EGU is equipped 

with emission controls that produce non-combustion CO2 (e.g., 

from sorbent injection), this additional CO2 must be accounted 

for, in accordance with section 3 of appendix G to part 75 of 

this chapter. As an alternative to direct measurement of CO2

concentration, provided that the affected EGU does not use 

carbon separation (e.g., carbon capture and storage), the owner 

or operator of an affected EGU may use data from a certified 

oxygen (O2) monitor to calculate hourly average CO2
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concentrations, in accordance with §75.10(a)(3)(iii) of this 

chapter. If CO2 concentration is measured on a dry basis, the 

owner or operator of the affected EGU must also install, 

certify, operate, maintain, and calibrate a continuous moisture 

monitoring system, according to § 75.11(b) of this chapter. 

75.11(b) of this chapter. Alternatively, the owner or operator 

of an affected EGU may either use an appropriate fuel-specific 

default moisture value from §75.11(b) or submit a petition to 

the Administrator under §75.66 of this chapter for a sitespecific default moisture value

(ii) For each monitoring system the“valid operating hour” 

(as defined in paragraph (a)(2) of this section), calculate the 

hourly CO2 mass emission rate (tons/hr), either from Equation F11 in Appendix F to part 75 of this chapter (if CO2 concentration 

is measured on a wet basis), or by following the procedure in 

section 4.2 of Appendix F to part 75 of this chapter (if CO2

concentration is measured on a dry basis). 

(iii) Next, multiply each hourly CO2 mass emission rate by 

the EGU or stack operating time in hours (as defined in §72.2 of 

this chapter), to convert it to tons of CO2. Multiply the result 

by 2,000 lbs/ton to convert it to lbs. 

(iv) The hourly CO2 tons/hr values and EGU (or stack) 

operating times used to calculate CO2 mass emissions are required 

to be recorded under §75.57(e) of this chapter and must be 
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reported electronically under §75.64(a)(6), if required by a 

plan. The owner or operator usesmust use these data, or 

equivalent data, to calculate the hourly CO2 mass emissions. 

(v) Sum all of the hourly CO2 mass emissions values from 

paragraph (a)(3)(ii) of this section over the entire compliance 

period. 

(vi) For each continuous monitoring system used to 

determine the CO2 mass emissions from an affected EGU uses, the 

monitoring system must meet the applicable certification and 

quality assurance procedures in § 75.20 of this chapter and 

Appendices BA and DB to part 75 of this chapter. 

(iii (4) The owner or operator of an affected EGU must use 

only unadjusted exhaust gas volumetric flow rates tothat 

exclusively combusts liquid fuel and/or gaseous fuel may, as an 

alternative to complying with paragraph (a)(3) of this section,

determine the hourly CO2 mass emissions from the affected 

facility; the owner or operator of an affected EGU must not 

apply the bias adjustment factors described in section 7.6.5 of 

Appendix A to part 75 of this chapter to the exhaust 

gasaccording to paragraphs (a)(4)(i) through (a)(4)(vi) of this 

section. 

(i) Implement the applicable procedures in appendix D to 

part 75 of this chapter to determine hourly EGU heat input rates 

(MMBtu/hr), based on hourly measurements of fuel flow rate and 
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periodic determinations of the gross calorific value (GCV) of 

each fuel combusted. The fuel flow rate datameter(s) used to 

measure the hourly fuel flow rates must meet the applicable 

certification and quality-assurance requirements in sections 

2.1.5 and 2.1.6 of appendix D to part 75 (except for qualifying 

commercial billing meters). The fuel GCV must be determined in 

accordance with section 2.2 or 2.3 of appendix D, as applicable. 

(3(ii) For each measured hourly heat input rate, use 

Equation G-4 in Appendix G to part 75 of this chapter to 

calculate the hourly CO2 mass emission rate (tons/hr). 

(iii) For each “valid operating hour” (as defined in 

paragraph (a)(2) of this section), multiply the hourly tons/hr 

CO2 mass emission rate from paragraph (a)(4)(ii) of this section 

by the EGU or stack operating time in hours (as defined in §72.2 

of this chapter), to convert it to it to tons of CO2. Then, 

multiply the result by 2,000 lbs/ton to convert it to lbs. 

(iv) The hourly CO2 tons/hr values and EGU (or stack) 

operating times used to calculate CO2 mass emissions are required 

to be recorded under §75.57(e) of this chapter and must be 

reported electronically under §75.64(a)(6), if required by a 

plan. You must use these data, or equivalent data, to calculate 

the hourly CO2 mass emissions. 
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(v) Sum all of the hourly CO2 mass emissions values (lb) 

from paragraph (a)(4)(iii) of this section over the entire 

compliance period. 

(vi) The owner or operator of an affected EGU may determine 

site-specific carbon-based F-factors (Fc) using Equation F-7b in 

section 3.3.6 of appendix F to part 75 of this chapter, and may 

use these Fc values in the emissions calculations instead of 

using the default Fc values in the Equation G-4 nomenclature. 

(4(5) For both rate-based and mass-based standards, the 

owner or operator of an affected EGU (or group of affected units 

that share a monitored common stack) must install, calibrate, 

maintain, and operate a sufficient number of watt meters to 

continuously measure and record on an hourly basis net electric 

output. Measurements must be performed using 0.2 accuracy class 

electricity metering instrumentation and calibration procedures 

as specified under ANSI Standards No. C12.20. Further, the owner 

or operator of an affected EGU that is a combined heat and power 

facility must install, calibrate, maintain and operate equipment 

to continuously measure and record on an hourly basis useful 

thermal output and, if applicable, mechanical output, which are 

used with net electric output to determine net energy output. 

The owner or operator must use the following procedures to 

calculate net energy output, as appropriate for the type of 

affected EGU(s). 
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(i) Determine Pnet the hourly net energy output in MWh. For 

rate-based standards, perform this calculation only for valid 

operating hours (as defined in paragraph (a)(2) of this 

section). For mass-based standards, perform this calculation for 

all unit (or stack) operating hours, i.e., full or partial hours 

in which any fuel is combusted. 

(ii) If there is no net electrical output, but there is 

mechanical or useful thermal output, either for a particular 

valid operating hour (for rate-based applications), or for a 

particular operating hour (for mass-based applications), the 

owner or operator of the affected EGU must still determine the 

net energy output for that hour. 

(iii) For rate-based applications, if there is no (i.e., 

zero) gross electrical, mechanical, or useful thermal output for 

a particular valid operating hour, that hour must be used in the 

compliance determination. For hours or partial hours where the 

gross electric output is equal to or less than the auxiliary 

loads, net electric output shall be counted as zero for this 

calculation. 

(iv) Calculate Pnet for your affected EGU (or group of 

affected EGUs that share a monitored common stack) using the 

following equation. All terms in the equation must be expressed 

in units of MWh. To convert each hourly net energy output value 

reported under part 75 of this chapter to MWh, multiply by the 
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corresponding EGU or stack operating time. 

ܲ௡௘௧ = ሺܲ݁ሻௌ் ൅	 ሺܲ݁ሻ஼் 	൅	 ሺܲ݁ሻூா െ ሺܲ݁ሻ஺

TDF 	൅	ሾ ሺܲݐሻ௉ௌ 	൅	 ሺܲݐሻுோ 	൅	 ሺܲݐሻூா ሿ

Where: 

Pnet = Net energy output of your affected EGU for each 

valid operating hour (as defined in 

60.5860(a)(2)) in MWh. 

(Pe)ST = Electric energy output plus mechanical energy 

output (if any) of steam turbines in MWh. 

(Pe)CT = Electric energy output plus mechanical energy 

output (if any) of stationary combustion 

turbine(s) in MWh. 

(Pe)IE = Electric energy output plus mechanical energy 

output (if any) of your affected EGU’s integrated 

equipment that provides electricity or mechanical 

energy to the affected EGU or auxiliary equipment 

in MWh. 

(Pe)A = Electric energy used for any auxiliary loads in 

MWh. 

(Pt)PS = Useful thermal output of steam (measured relative 

to SATP conditions, as applicable) that is used 

for applications that do not generate additional 

electricity, produce mechanical energy output, or 

enhance the performance of the affected EGU. This 
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is calculated using the equation specified in 

paragraph (a)(5)(v) of this section in MWh. 

(Pt)HR = Non steam useful thermal output (measured 

relative to SATP conditions, as applicable) from 

heat recovery that is used for applications other 

than steam generation or performance enhancement 

of the affected EGU in MWh. 

(Pt)IE = Useful thermal output (relative to SATP 

conditions, as applicable) from any integrated 

equipment is used for applications that do not 

generate additional steam, electricity, produce 

mechanical energy output, or enhance the 

performance of the affected EGU in MWh. 

TDF = Electric Transmission and Distribution Factor of 

0.95 for a combined heat and power affected EGU 

where at least on an annual basis 20.0 percent of 

the total gross or net energy output consists of 

electric or direct mechanical output and 20.0 

percent of the total net energy output consist of 

useful thermal output on a 12-operating month 

rolling average basis, or 1.0 for all other 

affected EGUs. 

(v) If applicable to your affected EGU (for example, for 

combined heat and power), you must calculate (Pt)PS using the 
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following equation: 

ሺܲݐሻ௉ௌ 	ൌ	ܳ௠ 	ൈ ܪ	

ܨܥ

Where: 

Qm = Measured steam flow in kilograms (kg) (or pounds 

(lbs)) for the operating hour. 

H = Enthalpy of the steam at measured temperature and 

pressure (relative to SATP conditions or the 

energy in the condensate return line, as 

applicable) in Joules per kilogram (J/kg) (or 

Btu/lb). 

CF = Conversion factor of 3.6 x 109 J/MWh or 3.413 x 

106 Btu/MWh. 

(v) For rate-based standards, sum all of the values of Pnet

for the valid operating hours (as defined in paragraph (a)(2) of 

this section), over the entire compliance period. Then, divide 

the total CO2 mass emissions for the valid operating hours from 

paragraph (a)(3)(v) or (a)(4)(v) of this section, as applicable, 

by the sum of the Pnet values for the valid operating hours plus 

any ERC replacement generation (as shown in §60.5790(c)), to 

determine the CO2 emissions rate (lb/net MWh) for the compliance 

period. 

(vi) For mass-based standards, sum all of the values of Pnet

for all operating hours, over the entire compliance period. 
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(6) In accordance with §60.13(g), if two or more affected 

EGUs implementing the continuous emissions monitoring provisions 

in paragraph (a)(2) of this section share a common exhaust gas 

stack and are subject to the same emissions standard, the owner 

or operator may monitor the hourly CO2 mass emissions at the 

common stack in lieu of monitoring each EGU separately. If an 

owner or operator of an affected EGU chooses this option, the 

hourly net electric output for the common stack must be the sum 

of the hourly net electric output of the individual affected 

EGUs and the operating time must be expressed as “stack 

operating hours” (as defined in §72.2 of this chapter). 

(7) In accordance with §60.13(g), if the exhaust gases from 

an affected EGU implementing the continuous emissions monitoring 

provisions in paragraph (a)(2) of this section are emitted to 

the atmosphere through multiple stacks (or if the exhaust gases 

are routed to a common stack through multiple ducts and you 

elect to monitor in the ducts), the hourly CO2 mass emissions and 

the “stack operating time” (as defined in §72.2 of this chapter) 

at each stack or duct must be monitored separately. In this 

case, the owner or operator of an affected EGU must determine 

compliance with an applicable emissions standard by summing the 

CO2 mass emissions measured at the individual stacks or ducts and 

dividing by the net energy output for the affected EGU. 

(8) Consistent with §60.5775 or §60.5780, if two or more 
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affected EGUs serve a common electric generator, you must 

apportion the combined hourly net energy output to the 

individual affected EGUs according to the fraction of the total 

steam load contributed by each EGU. Alternatively, if the EGUs 

are identical, you may apportion the combined hourly net 

electrical load to the individual EGUs according to the fraction 

of the total heat input contributed by each EGU. 

(b) For mass-based standards, the owner or operator of an 

affected EGU must determine the CO2 mass emissions (tons) for the 

compliance period as follows: 

(1) For each operating hour, calculate the hourly CO2 mass 

(tons) according to paragraph (a)(3) or (a)(4) of this section, 

except that a complete data record is required, i.e., CO2 mass 

emissions must be reported for each operating hour. Therefore, 

substitute data values recorded under part 75 of this chapter 

for CO2 concentration, stack gas flow rate, stack gas moisture 

content, fuel flow rate and/or GCV shall be used in the 

calculations; and 

(2) Sum all of the hourly CO2 mass emissions values over the 

entire compliance period. 

(3) The owner or operator of an affected EGU must install, 

calibrate, maintain, and operate a sufficient number of watt 

meters to continuously measure and record on an hourly basis net 

electric output. Measurements must be performed using 0.2 
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accuracy class electricity metering instrumentation and 

calibration procedures as specified under ANSI Standards No. 

C12.20. Further, the owner or operator of an affected EGU that 

is a combined heat and power facility must install, calibrate, 

maintain and operate equipment to continuously measure and 

record on an hourly basis useful thermal output and, if 

applicable, mechanical output, which are used with net electric 

output to determine net energy output. (Pnet). The owner or 

operator must calculate net energy output according to 

paragraphs (a)(5)(i)(A) and (B) of this section.

(5) In accordance with § 60.13(g), if two or more affected 

EGUs implementing the continuous emissions monitoring provisions 

in paragraph (a)(2) of this section share a common exhaust gas 

stack and are subject to the same emissions standard, the owner 

or operator may monitor the hourly CO2 mass emissions at the 

common stack in lieu of monitoring each EGU separately. If an 

owner or operator of an affected EGU chooses this option, the 

hourly net electric output for the common stack must be the sum 

of the hourly net electric output of the individual affected 

facility and the operating time must be expressed as “stack 

operating hours” (as defined in § 72.2 of this chapter). 

(6) In accordance with § 60.13(g), if the exhaust gases 

from an affected EGU implementing the continuous emissions 

monitoring provisions in paragraph (a)(2) of this section are 
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Page 2113 of 2153

emitted to the atmosphere through multiple stacks (or if the 

exhaust gases are routed to a common stack through multiple 

ducts and you elect to monitor in the ducts), the hourly CO2 mass 

emissions and the “stack operating time” (as defined in § 72.2 

of this chapter) at each stack or duct must be monitored 

separately. (c) Your plan must require the owner or operator of 

each affected EGU covered by your plan to maintain the records, 

as described in (b)(1) through (2) of this subpartIn this case, 

the owner or operator of an affected EGU must determine 

compliance with an applicable emissions standard by summing the 

CO2 mass emissions measured at the individual stacks or ducts and 

dividing by the net energy output for the affected EGU.

(b) The owner or operator of an affected EGU must maintain 

records, as required by a plan, for at least 5 years following 

the date of each compliance period, occurrence, measurement, 

maintenance, corrective action, report, or record. 

(1) The owner or operator of an affected EGU must maintain 

each record on site for at least 2 years after the date of each 

compliance period, compliance true-up period, occurrence, 

measurement, maintenance, corrective action, report, or record, 

whichever is latest, according to § 60.7. The owner or operator 

of an affected EGU may maintain the records off site and 

electronically for the remaining year(s). 
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(2) The owner or operator of an affected EGU must keep all 

of the following records: 

(i) All documents, data files, and calculations and methods 

used to demonstrate compliance with an affected EGU’s emission 

standard under § 60.57905775. 

(ii) Copies of all reports submitted to the stateState

under paragraph (c) of this section. 

(iii) Data that isare required to be recorded by 40 CFR 

Part 75 Subpart F. 

(iv) Data with respect to any ERCs (if applicable)generated 

by the affected EGU or used by the affected EGU in its 

compliance demonstration including the information in paragraphs 

(bc)(2)(iv)(A) through (Cand (B) of this section. 

(A) All correspondence and other commercial documents 

related to any ERC transactions that involved qualifying ERCs 

and anyused in a compliance demonstration, including each 

eligibility application, EM&V plans related to those ERCs. 

(B) All plan, M&V report, and independent third party 

verifier verification assurance plans. report associated with 

the issuance of each specific ERC.

(CB) All records and reports relating to the surrender and 

retirement of ERCs for compliance with this regulation, and all 

information specified in § 60.5793(j).including the date each 
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individual ERC with a unique serial identification number was 

surrendered and/or retired.

(c) The (d) Your plan must require the owner or operator of 

an affected EGU must covered by your plan to include in a report 

required bysubmitted to you at the plan coveringend of each 

compliance period the information in paragraphs (d)(1) through 

(5) of this section. 

(1) Owners or operators of an affected EGU must include in 

the report all hourly CO2 emissions, all , for each affected EGU 

(or group of affected EGUs that share a monitored common stack). 

(2) For rate-based standards, each report must include: 

(i) The hourly CO2 mass emission rate values (tons/hr) and 

unit (or stack) operating times, (as monitored and reported 

according to part 75 of this chapter), for each valid operating 

hour in the compliance period; 

(ii) The net electric output and all the net energy output 

(Pnet) values for each valid operating hour in the compliance 

period; 

(iii) The calculated CO2 mass emissions (lb) for each valid 

operating hour in the compliance period; 

(iv) The sum of the hourly net energy output measurements 

for a CHP facility calculated from data monitored according to 

values and the sum of the hourly CO2 mass emissions values, for 

all of the valid operating hours in the compliance period; 
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(v) ERC replacement generation (if any), properly justified 

(see paragraph (ac)(5) of this section); and 

(vi) The calculated CO2 mass emission rate for the 

compliance period (lbs/net MWh). 

(3) For mass-based standards, each report must include: 

(i) The hourly CO2 mass emission rate value (tons/hr) and 

unit (or stack) operating time, as monitored and reported

according to the procedures in 40 CFR Part 75 Subpart G. In 

addition part 75 of this chapter, for each unit or stack 

operating hour in the compliance period; 

(ii) The calculated CO2 mass emissions (tons) for each unit 

or stack operating hour in the compliance period; 

(iii) The sum of the CO2 mass emissions (tons) for all of 

the unit or stack operating hours in the compliance period; 

(iv) The net electric output and the net energy output 

(Pnet) values for each unit or stack operating hour in the 

compliance period; and 

 (v) The sum of the hourly net energy output values for all 

of the unit or stack operating hours in the compliance period. 

(vi) Notwithstanding the requirements in paragraphs 

(c)(3)(i) through (c)(3)(iii) of this section, if the compliance 

period is a discrete number of calendar years (e.g., one year, 

three years), in lieu of reporting the information specified in 

those paragraphs, the owner or operator may report: 
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(A) The cumulative annual CO2 mass emissions (tons) for each 

year of the compliance period, derived from the electronic 

emissions report for the fourth calendar quarter of that year, 

submitted to EPA under §75.64(a plan must require reports to be 

submitted ) of this chapter; and 

(B) The sum of the cumulative annual CO2 mass emissions 

values from the EGUs that include the information in 

paragraphsparagraph (c)(1) and (23)(v)(A) of this section., if 

the compliance period includes multiple years. 

(14) For each affected EGU’s compliance period, owners and 

operators of affected EGUs the report must also include in their 

report theirthe applicable emission standard calculated and 

demonstration that it met the emission standard. An owner or 

operator must also include in the report the affected EGU’s 

calculated emission performance as a CO2 emission rate or 

cumulative mass in units of the emission standard required in § 

§§60.5790(b) through (d) and 60.5855, as applicable. 

(25) If the owner or operator of an affected EGU is 

complying with an emission standard by using ERCs, they must 

include in theirthe report a list of all unique ERC serial 

numbers that were retired for the compliance period that an 

affected EGU used to complyin the compliance period, and, for 

each ERC, the date an ERC was surrendered and retired and 

eligible resource identification information sufficient to 
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demonstrates that it meets the requirements of §60.5800 and 

qualifies to be issued ERCs (including location, type of 

qualifying generation or savings, date commenced generating or 

saving, and date of generation or savings for which the ERC was 

issued). 

(6) If the owner or operator of an affected EGU is 

complying with an emission standard, and all other information 

specified in § 60.5793(e) of this section. or State measures by 

using allowances, they must include in the report a list of all 

unique allowance serial numbers that were retired in the 

compliance period, and, for each allowance, the date an 

allowance was surrendered and retired and if the allowance was a 

set-aside allowance the eligible resource identification 

information sufficient to demonstrate that it meets the 

requirements of §60.5815(c) and qualifies to be issued set-aside 

allowances (including location, type of qualifying generation or 

savings, date commenced generating or saving, and date of 

generation or savings for which the allowance was issued).

(de) The owner or operator of an affected EGU must follow 

any additional requirements for monitoring, recordkeeping and 

reporting in a plan that are required under § 60.5785, if 

applicable. 
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(f) If an affected EGU captures CO2 to meet the applicable 

emission limit, owners and operator must report in accordance 

with the requirements of 40 CFR Part 98 Subpart PP and either: 

(1) Report in accordance with the requirements of 40 CFR 

Part 98 subpart RR, if injection occurs on-site, or 

(2) Transfer the captured CO2 to an EGU or facility that 

reports in accordance with the requirements of 40 CFR Part 98 

subpart RR, if injection occurs off-site. 

(3) Transfer the captured CO2 to a facility that has 

received an innovative technology waiver from EPA pursuant to 

paragraph (g) of this section. 

(g) Any person may request the Administrator to issue a 

waiver of the requirement that captured CO2 from an affected EGU 

be transferred to a facility reporting under 40 CFR Part 98 

subpart RR. To receive a waiver, the applicant must demonstrate 

to the Administrator that its technology will store captured CO2

as effectively as geologic sequestration, and that the proposed 

technology will not cause or contribute to an unreasonable risk 

to public health, welfare, or safety. In making this 

determination, the Administrator shall consider (among other 

factors) operating history of the technology, whether the 

technology will increase emissions or other releases of any 

pollutant other than CO2, and permanence of the CO2 storage. The 

Administrator may test the system itself, or require the 
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applicant to perform any tests considered by the Administrator 

to be necessary to show the technology’s effectiveness, safety, 

and ability to store captured CO2 without release. The 

Administrator may grant conditional approval of a technology, 

the approval conditioned on monitoring and reporting of 

operations. The Administrator may also withdraw approval of the 

waiver on evidence of releases of CO2 or other pollutants. The 

Administrator will provide notice to the public of any 

application under this provision, and provide public notice of 

any proposed action on a petition before the Administrator takes 

final action. 

Recordkeeping and Reporting Requirements 

§ 60.58255865 What are my state recordkeeping requirements? 

(a) StatesYou must keep records of all information relied 

upon in support of any demonstration of plan components, plan 

requirements, supporting documentation, and the status of 

meeting the plan requirements defined in the plan for theeach

interim steps 1, 2 and 3step and the interim plan period from 

2022-2029.. After 2029 states, States must keep records of all 

information relied upon in support of any continued 

demonstration that the final emissions goals are being achieved. 

(b) StatesYou must keep records of all data submitted by 

the owner or operator of each affected EGU that is used to 

determine compliance with each affected EGU emissions standard 
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or state requirement.requirements in an approved State plan, 

consistent with the affected EGU requirements listed in 

§60.5860. 

(c) If a stateyour State has a requirement for all hourly 

CO2 emissions and net generation information to be used to 

calculate compliance with an annual emissions standard or State 

measure for affected EGUs, any information that is submitted by 

the owners or operators of affected EGUs to the EPA 

electronically pursuant to requirements in Part 75 meets the 

recordkeeping requirement of this section and a state isyou are

not required to keep records of information that would be in 

duplicate of paragraph (b) of this section. 

(d) A stateYou must keep records at a minimum for 10 years, 

for the interim period, and 5 years, for the final period, from 

the date the record is used to determine compliance with an 

emissions standard, plan requirement or , CO2 emission 

performance rate or CO2 emissions goal. Each record must be in 

the interim period. a form suitable and readily available for 

expeditious review.

§ 60.58305870 What are my state reporting and notification 

requirements? 

(a) In lieu of the annual report required under § 60.25 (e) 

and (f) of this part, you must report the information in 

paragraphs (b) through (ef) of this section. 
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(b) You must submit a report covering each interim step 

within the interim period and each of the final 2-calendar year 

periods due no later than July 1 of the year following the end 

of the period. The interim period reporting starts with a 

reporting covering interim step 1 (2022-2024) due no later than 

July 1, 2025. The final period reports start with a 2030-2031 

bi-annual reportbiennual report covering the first final 

reporting period (which is due by July 1, 2032), a 2-calendar 

year average of emissions or cumulative sum of emissions used to 

determine compliance with the final CO2 emission performance rate 

or CO2 emission goal (as applicable). The report must include the 

following:information in paragraphs (b)(1) through (4) of this 

paragraph.

(1) The report must include the emissions performance 

achieved by all affected EGUs during the reporting period, 

consistent with the plan approach according to § 60.5745(a), and 

identification of whether each affected EGU is in compliance 

with its emission standard and whether the collective of all 

affected EGUs covered by the State are on schedule to meet the 

applicable CO2 emission performance rate or emission goal during 

the performance periods and compliance periods, as specified in 

the plan. 

(2) AThe report must include a comparison of the CO2

emission performance rate or CO2 emission goal identified in the 
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stateState plan for the applicable interim step period versus 

the actual average or, cumulative, or adjusted CO2 emission 

performance (as applicable) achieved by all affected EGUs. 

 ((i) For interim step 3) All, you do not need to 

include a comparison between the applicable interim step 3 CO2

emission performance rate or emission goal; you must only submit 

the average, cumulative or adjusted CO2 emission performance (as 

applicable) of your affected EGUs during that period in units of 

your applicable CO2 emission performance rate or emission goal. 

 (3) The report must include all other required information, 

as specified in your stateState plan according to 

§60.5740(a)(5). 

 (4) The report must include a program review that your 

State has conducted that addresses all aspects of the 

administration of the state plan and overall program, including 

State evaluations and regulatory decisions regarding eligibility 

applications for ERC resources and M&V reports (and associated 

EM&V activities), and State issuance of ERCs. The program review 

must assess whether the program is being administered properly 

in accordance with the approved plan, that reported annual MWh 

of generation and savings from qualified ERC resources are being 

properly quantified, verified, and reported in accordance with 

approved EM&V plans, and that appropriate records are being 

maintained. The program review must also address determination 
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of the eligibility of verifiers by the State and the conduct of 

verifiers, including the quality of verifier reviews. 

(c) If your plan includes staterelies upon State measures, 

in lieu of or in addition to emission standards, thanthen you 

must submit an annual report to the EPA in addition to the 

reports required under paragraph (b) of this section for the 

interim period. In the final periodsperiod, you must submit biannualbiennual reports consistent with those required under 

paragraph (b).) of this section. The annual reports in the 

interim period must be submitted no later than July 1 following 

the end of each calendar year starting with the annual year 2022 

(January 1, 2022 to December 31, 2022). The annual and biannualbiennual reports must include the information in 

paragraphs (c)(1) and (2) of this section. 

(1) You must include in your report the status of 

implementation of federally enforceable emission standards (if 

applicable) and stateState measures.

(2) You must include information regrindingregarding the 

status of the periodic programmatic milestones to show progress 

in program implementation. The programmatic milestones with 

specific dates for achievement must be consistent with the 

stateState measures included in the stateState plan submittal. 

(d) If your plan includes the requirement for emission 

standards on your affected EGUs than, then you must submit a 
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notification in the report required under paragraph (b) of this 

section to the EPA if your affected EGUs exceed a CO2 emission 

performance rate or CO2 emission goal (on average for rate or 

cumulatively for mass) by 10 percent or greater thus 

triggeringtrigger corrective measures required under your 

plan.as described in §60.5740(a)(2)(i). If corrective measures 

are required you must follow the requirements in 60.5785 for 

revising your plan to implement the corrective measures.

(e) If your plan includes staterelies upon State measures, 

in lieu of or in addition to emission standards, than you must 

submit a notification as required under paragraphs (e)(1) and 

(2) orof this section. 

(1) You must submit a notification in the report required 

under paragraph (c) of this section to the EPA if at the end of 

the calendar year your stateState did not meet a programmatic 

milestone included in your plan submittal. This notification 

must detail the implementation of the backstop required in your 

plan to be fully in place within 18 months of the due date of 

the report required in paragraph (b) of this section. In 

addition, the notification must describe the steps taken by the 

stateState to inform the affected EGUs in its State that the 

backstop has been triggered. 

(2) You must submit a notification in the report required 

under paragraph (b) of this section to the EPA if your affected 
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EGUs, at the end of any interim performance step or final 

period, exceed a CO2 emission performance rate or CO2 emission 

goal (on average for rate or cumulatively for mass) by 10 

percent or greater thus triggering the implementation ofyou 

trigger the backstop required in your plan.as described in 

§60.5740(a)(3)(i). This notification must detail the 

implementation ofsteps that will be taken by you to implement

the backstop to beso that it is fully in place within 18 months 

of the due date of the report required in paragraph (b) of this 

section. In addition, the notification must describe the steps 

taken by the stateState to inform the affected EGUs that the 

backstop has been triggered. 

 (f) You must include in your 2029 report (which is due by 

July 1, 2030) the calculation of average emissions or,

cumulative sum of emissions, or adjusted emissions (as 

applicable) over the 2022-2029 interim period and a comparison 

of those values to your interim period used to determine 

compliance with your interim CO2 emission performance rate or 

emission goal. The calculated value must be in units consistent 

with the approach you set in your plan for the interim period. 

§ 60.5835 (g) The notifications listed in paragraphs (g)(1) 

through (3) of this section are required for the reliability 

safety valve allowed in §60.5785(e). 

(1) As required under §60.5785(e), you must submit an 
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initial notification to the appropriate EPA regional office 

within 48 hours of an unforeseen, emergency situation. The 

initial notification must: 

(i) Include a full description, to the extent that it is 

known, of the emergency situation that is being addressed; 

(ii) Identify the affected EGU or EGUs that are required to 

run to assure reliability; and 

(iii) Specify the modified emission standards at which the 

identified EGU or EGUs will operate. 

(2) Within 7 days of the initial notification in 

§60.5870(g)(1), the State must submit a second notification to 

the appropriate EPA regional office that documents the initial 

notification. If the State fails to submit this documentation on 

a timely basis, the EPA will notify the State, which must then 

notify the affected EGU(s) that they must operate or resume 

operations under the original approved State plan emissions 

standards. This notification must include the following: 

(i) A full description of the reliability concern and why 

an unforeseen, emergency situation that threatens reliability 

requires the affected EGU or EGUs to operate under modified 

emission standards from those originally required in the State 

plan including discussion of why the flexibilities provided 

under the state’s plan are insufficient to address the concern; 

(ii) A description of how the State is coordinating or will 
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coordinate with relevant reliability coordinators and planning 

authorities to alleviate the problem in an expedited manner; 

(iii) An indication of the maximum time that the State 

anticipates the affected EGU or EGUs will need to operate in a 

manner inconsistent with its or their obligations under the 

State’s approved plan; 

(iv) A written concurrence from the relevant reliability 

coordinator and/or planning authority confirming the existence 

of the imminent reliability threat and supporting the temporary 

modification request or an explanation of why this kind of 

concurrence cannot be provided; 

(v) The modified emission standards or levels that the 

affected EGU or EGU will be operating at for the remainder of 

the 90 day period if it has changed from the initial 

notification; and 

(vi) Information regarding any system-wide or other 

analysis of the reliability concern conducted by the relevant 

planning authority, if any. 

(3) At least 7 days before the end of the 90-day 

reliability safety valve period, the State must notify the 

appropriate EPA regional office that either: 

(i) The reliability concern has been addressed and the 

affected EGU or EGUs can resume meeting the original emissions 

standards in the State plan approved prior to the short-term 
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modification; or 

 (ii) There still is a serious, ongoing reliability issue 

that necessitates the EGU or EGUs to emit beyond the amount 

allowed under the State plan. In this case, the State must 

provide a notification to the EPA that it will be submitting a 

State plan revision according to paragraph §60.5785(a) of this 

section to address the reliability issue. The notification must 

provide the date by which a revised State plan will be submitted 

to EPA and documentation of the ongoing emergency with a written 

concurrence from the relevant reliability coordinator and/or 

planning authority confirming the continuing urgent need for the 

EGU or EGUs to operate beyond the requirements of the State plan 

and that there is no other reasonable way of addressing the 

ongoing reliability emergency but for the EGU or EGUs to operate 

under an alternative emission standard than originally approved 

under the State plan. After the initial 90 day period, any 

excess emissions beyond what is authorized in the original 

approved State plan will count against the State’s overall CO2

emission goal or emission performance rate for affected EGUs. 

§60.5875 How do I submit information required by these Emission 

Guidelines to the EPA?

(a) You must submit to the EPA the information required by 

these emission guidelines following the procedures in paragraphs 

(b) through (e) of this section. 
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(b) All negative declarations, stateState plan submittals, 

supporting materials that are part of a stateState plan 

submittal, any plan revisions, and any stateall State reports 

required to be submitted to the EPA by the State plan must be 

reported through EPA’s State Plan Electronic Collection System 

(SPeCS). ConfidentialSPeCS is a web accessible electronic system 

is accessed at the EPA’s Central Data Exchange (CDX) 

(http://www.epa.gov/cdx/). States who claim that a State plan 

submittal or supporting documentation includes confidential

business information that is part of an official submittal to 

EPA must also be submitted electronically into the SPeCS.(CBI) 

must submit that information on a compact disc, flash drive, or 

other commonly used electronic storage media to the EPA. The 

electronic media must be clearly marked as CBI and mailed to 

U.S. EPA/OAQPS/CORE CBI Office, Attention: State and Local 

Programs Group, MD C539-01, 4930 Old Page Rd., Durham, NC 27703. 

(c) Only a submittal by the Governor’sGovernor or the 

Governor’s designee by an electronic submission through SPeCS 

shall be considered an official submittal to the EPA under this 

subpart. If the Governor wishes to designate another responsible 

official the authority to submit a stateState plan, the EPA must 

be notified via letter from the Governor prior to the August 

31September 6, 2016, deadline for plan submittal so that they 

have the ability to submit the initial or final plan submittal 
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in the SPeCS. If the Governor has previously delegated authority 

to make CAA submittals on the Governor’s behalf, a stateState

may submit documentation of the delegation in lieu of a letter 

from the Governor. The letter or documentation must identify the 

designee to whom authority is being designated and must include 

the name and contact information for the designee and also 

identify the stateState plan preparers who will need access to 

SPeCS. A stateState may also submit the names of the stateState

plan preparers via a separate letter prior to the designation 

letter from the Governor in order to expedite the stateState

plan administrative process. Required contact information for 

the designee and preparers includes the person’s title, 

organization and email address. 

(d) The submission of the information by the authorized 

official must be in a non-editable format. In addition to the 

non-editable version all plan components designated as federally 

enforceable must also be submitted in an editable version. 

Following initial plan approval, states shallStates must provide 

the EPA with an editable copy of any submitted revision to 

existing approved federally enforceable plan components, 

including stateState plan backstop measures. The editable copy 

of any such submitted plan revision must indicate the changes 

made at the stateState level, if any, to the existing approved 

federally enforceable plan components, using a mechanism such as 
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redline/strikethrough. These changes are not part of the 

stateState plan until formal approval by EPA. 

(e) You shallmust provide the EPA with a non-editable and 

editable copycopies of any submitted revision to existing 

approved federally enforceable plan components, including 

stateState plan backstop measures. The editable copy of any such 

submitted plan revision must indicate the changes made at the 

stateState level, if any, to the existing approved federally 

enforceable plan components, using a mechanism such as 

redline/strikethrough. These changes are not part of the 

stateState plan until formal approval by EPA. 

Definitions 

§ 60.5840 5880 What definitions apply to this subpart? 

As used in this subpart, all terms not defined herein will 

have the meaning given them in the Clean Air Act and in subparts 

A (General Provisions) and B of this part. 

Adjusted CO2 emission rate means the reported CO2 emission 

rate of an affected EGU, adjusted as described in §60.5790(c)(1) 

to reflect any ERCs used by an affected EGU to demonstrate 

compliance with its CO2 emission standards. 

Affected electric generating unit or Affected EGU means a 

steam generating unit, integrated gasification combined cycle 

(IGCC), or stationary combustion turbine that meets the relevant 

applicability conditions in section §60.5845. 
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Allowance means an authorization for each specified unit of 

actual CO2 emitted from an affected EGU or a facility during a 

specified period. 

Allowance system means a control program under which the 

owner or operator of each affected EGU is required to hold an 

authorization for each specified unit of CO2 emitted from that 

facility during a specified period and which limits the total 

amount of such authorizations available to be held for CO2 for a 

specified period and allows the transfer of such authorizations 

not used to meet the authorization-holding requirement. 

Annual capacity factor means the ratio between the actual 

heat input to an EGU during a calendar year and the potential 

heat input to the EGU had it been operated for 8,760 hours 

during a calendar year at the base load rating. 

Affected electric generating unit or Affected EGU means a 

steam generating unit, an IGCC facility, or a stationary 

combustion turbine that meets the applicability conditions in 

section § 60.5800. 

Base load rating means the maximum amount of heat input 

(fuel) that an EGU can combust on a steady stateState basis, as 

determined by the physical design and characteristics of the EGU 

at ISO conditions. For a stationary combustion turbine, base 

load rating includes the heat input from duct burners.

Biomass means biologically based material that is living or 
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dead (e.g., trees, crops, grasses, tree litter, roots) above and 

below ground, and available on a renewable or recurring basis. 

Materials that are biologically based include non-fossilized, 

biodegradable organic material originating from modern or 

contemporarily grown plants, animals, or microorganisms 

(including plants, products, byproducts and residues from 

agriculture, forestry, and related activities and industries, as 

well as the non-fossilized and biodegradable organic fractions 

of industrial and municipal wastes, including gases and liquids 

recovered from the decomposition of non-fossilized and 

biodegradable organic material). 

CO2 emission goal means a statewide rate-based CO2 emission 

goal or mass-based CO2 emission goal specified in § 60.5815. 

Coal means all solid fuels classified as anthracite, 

bituminous, subbituminous, or lignite by the American Society of 

Testing and Materials in ASTM D388 (incorporated by reference, 

see § 60.17), coal refuse, and petroleum coke. Synthetic fuels 

derived from coal for the purpose of creating useful heat, 

including but not limited to solvent-refined coal, gasified coal 

(not meeting the definition of natural gas), coal-oil mixtures, 

and coal-water mixtures are included in this definition for the 

purposes of this subpart5855. 

Combined cycle unit means an electric generating unit that 

uses a stationary combustion turbine from which the heat from 
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the turbine exhaust gases is recovered by a heat recovery steam 

generating unit to generate additional electricity.

Combined heat and power unit or CHP unit, (also known as 

“cogeneration”) means an electric generating unit that use a 

steam-generating unit or stationary combustion turbine to 

simultaneously produce both electric (or mechanical) and useful 

thermal output from the same primary energy source. 

Common practice baseline or CPB means a baseline derived 

based on a default technology or condition that would have been 

in place at the time of implementation of an EE measure in the 

absence of the EE measure (for example, the standard or marketaverage or pre-existing equipment that a typical 

consumer/building owner would have continued to use or would 

have installed at the time of project implementation in a given 

circumstance, such as a given building type, EE program type or 

delivery mechanism, and geographic region). 

Compliance Period means a discrete time period for an 

affected EGU to comply with either an emission standard or State 

measure. Compliance periods for affected EGUs required in plans 

must meet the requirements of §60.5770. 

Control area operator means an electric system or systems, 

bounded by interconnection metering and telemetry, capable of 

controlling generation to maintain its interchange schedule with 
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other control areas and contributing to frequency regulation of 

the interconnection.

Demand-side energy efficiency means an installed piece of 

equipment or system, a modification of existing equipment or 

system, or a strategy intended to affect consumer electricityuse behavior, that results in a reduction in electricity use (in 

MWh) at an end-use facility, premises, or equipment connected to 

the electricity grid.

Derate means a decrease in the available capacity of an 

electric generating unit, due to a system or equipment 

modification or to discounting a portion of a generating units 

capacity for planning purposes. 

Design efficiency means the rated overall net efficiency 

(e.g., electric plus thermal output) on a higher heating value 

basis of the EGU at the base load rating and ISO conditions. 

Distillate oil means fuel oils that comply with the 

specifications for fuel oil numbers 1 and 2, as defined by the 

American Society of Testing and Materials in ASTM D396 

(incorporated by reference, see § 60.17); diesel fuel oil 

numbers 1 and 2, as defined by the American Society for Testing 

and Materials in ASTM D975 (incorporated by reference, see § 

60.17); kerosene, as defined by the American Society of Testing 

and Materials in ASTM D3699 (incorporated by reference, see § 

60.17); biodiesel as defined by the American Society of Testing 
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and Materials in ASTM D6751 (incorporated by reference, see § 

60.17); or biodiesel blends as defined by the American Society 

of Testing and Materials in ASTM D7467 (incorporated by 

reference, see § 60.17). 

Eligible resource means a resource that meets the 

requirements of §60.5800(a). 

Emission Rate Credit or ERC means a tradable compliance 

instrument that meets the requirements of §60.5790(c).

EM&V plan means a plan that meets the requirements of

§60.5830. 

ERC tracking system means a system for the issuance, 

surrender and retirement of ERCs that meets the requirements of 

§60.5810. 

Essential generating characteristics means any 

characteristic that affects the eligibility of the qualifying 

energy generatingan eligible resource for generating ERCs 

pursuant to this regulation, including the type of resource.

Existing stateState program, requirement, or measure means, 

in the context of a stateState plan, a regulation, requirement, 

program, or measure administered by a stateState, utility, or 

other entity that is currently established. This may include a 

regulation or other legal requirement that includes past, 

current, and future obligations, or current programs and 

measures that are in place and are anticipated to be continued 
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or expanded in the future, in accordance with established plans. 

An existing state program, requirement, or measure may have 

past, current, and future impacts 

Final period means the period that begins on EGU CO2

emissions.January 1, 2030, and continues thereafter. The final 

period is comprised of final reporting periods, each of which 

may be no longer than two calendar years (with a calendar year 

beginning on January 1 and ending on December 31).

Final reporting period means an increment of plan 

performance within the final period, with each final reporting 

period being no longer than two calendar years (with a calendar 

year beginning on January 1 and ending on December 31), with the 

first final reporting period in the final period beginning on 

January 1, 2030, and ending no later than December 31, 2031. 

Fossil fuel means natural gas, (as defined in subpart TTTT 

of this part), petroleum, (as defined in subpart TTTT of this 

part), coal, (as defined in subpart TTTT of this part), and any 

form of solid, fuel(as defined in subpart TTTT of this part),

liquid, fuel(as defined in subpart TTTT of this part), or 

gaseous fuel (as defined in subpart TTTT of this part) derived 

from such material for the purpose of creating useful heat. 

Gaseous fuel means any fuel that is present as a gas at ISO 

conditions and includes, but is not limited to, natural gas, 

refinery fuel gas, process gas, coke-oven gas, synthetic gas, 
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and gasified coal. 

 Heat recovery steam generating unit (HRSG) means a unit in 

which hot exhaust gases from the combustion turbine engine are 

routed in order to extract heat from the gases and generate 

useful output. Heat recovery steam generating units can be used 

with or without duct burners. 

Independent verifier means a person (including any company, 

any corporate parent or subsidiary, any contractors or 

subcontractors, and the actual person) who has the appropriate 

technical and other qualifications to provide verification 

reports. The independent verifier must not have, or have had, 

any direct or indirect financial or other interest in the 

subject of its verification report or ERCs that could impact 

their impartiality in performing verification services. 

 Integrated gasification combined cycle facility or IGCC 

facility means a combined cycle facility that is designed to 

burn fuels containing 50 percent (by heat input) or more solidderived fuel not meeting the definition of natural gas plus any 

integrated equipment that provides electricity or useful thermal 

output to either the affected facility or auxiliary equipment. 

The Administrator may waive the 50 percent solid-derived fuel 

requirement during periods of the gasification system 

construction, startup and commissioning, shutdown, or repair. No 

solid fuel is directly burned in the unit during operation. 
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Interim period means the period of eight calendar years 

from January 1, 2022, to December 31, 2029. The interim period 

is composed of at least three interim steps, interim step 1, 

interim step 2, and interim step 3, and may be composed of more 

than three interim steps at your discretion, provided your first 

and second interim steps and no single interim step is longer 

than three calendar years each (with a calendar year beginning 

on January 1 and ending on December 31), and your last interim 

step is no longer than two calendar years (with a calendar year 

beginning on January 1 and ending on December 31).

Interim step means an increment of plan performance within 

the interim period. You must have at least three interim steps 

within the interim period. You may have more than three interim 

steps at your discretion, provided your first and second interim 

steps and no single interim step is longer than three calendar 

years each (with a calendar year beginning on January 1 and 

ending on December 31), and your last interim step is no longer 

than two calendar years (with a calendar year beginning on 

January 1 and ending on December 31).

Interim step 1 means the period of three calendar years 

from January 1, 2022, to December 31, 2024.

Interim step 2 means the period of three calendar years 

from January 1, 2025, to December 31, 2027.

Interim step 3 means the period of two calendar years from 
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January 1, 2028, to December 31, 2029.

ISO conditions means 288 Kelvin (15o C), 60 percent relative 

humidity and 101.3 kilopascals pressure. 

Liquid fuel means any fuel that is present as a liquid at 

ISO conditions and includes, but is not limited to, distillate 

oil and residual oil. 

M&V report means a report that meets the requirements of 

§60.5835]. 

Mechanical output means the useful mechanical energy that 

is not used to operate the affected facility, generate 

electricity and/or thermal output, or to enhance the performance 

of the affected facility. Mechanical energy measured in 

horsepower hour shouldmust be converted into MWh by multiplying 

it by 745.7 then dividing by 1,000,000. 

Nameplate capacity means, starting from the initial 

installation, the maximum rated output of a generator, prime 

mover, or other electric power production equipment under 

specific conditions designated by the manufacturer 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 

equipment, starting from the completion of any subsequent 

physical change resulting in an increase in the maximum 

electrical generating output that the equipment is capable of 
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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 a fluid mixture of hydrocarbons (e.g., 

methane, ethane, or propane), composed of at least 70 percent 

methane by volume or that has a gross calorific value between 35 

and 41 megajoules (MJ) per dry standard cubic meter (950 and 

1,100 Btu per dry standard cubic foot), that maintains a gaseous 

stateState under ISO conditions. In addition, natural gas 

contains 20.0 grains or less of total sulfur per 100 standard 

cubic feet. Finally, natural gas does not include the following 

gaseous fuels: landfill gas, digester gas, refinery gas, sour 

gas, blast furnace gas, coal-derived gas, producer gas, coke 

oven gas, or any gaseous fuel produced in a process which might 

result in highly variable sulfur content or heating value. 

Net allowance export/import means a net transfer of CO2

allowances during an interim step, the interim period, or final 

reporting period which represents the net number of CO2

allowances (issued by a respective State) that are transferred 

from the compliance accounts of affected EGUs in that state to 

the compliance accounts of affected EGUs in another State. This 

net transfer is determined based on compliance account holdings 
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at the end of the plan performance period. Compliance account 

holdings, as used here, refer to the number of CO2 allowances 

surrendered for compliance during a plan performance period, as 

well as any remaining CO2 allowances held in a compliance account 

as of the end of a plan performance period. 

Net-electric output means the amount of gross generation 

the generator(s) produce (including, but not limited to, output 

from steam turbine(s), combustion turbine(s), and gas 

expander(s)), as measured at the generator terminals, less the 

electricity used to operate the plant (i.e., auxiliary loads); 

such uses include fuel handling equipment, pumps, fans, 

pollution control equipment, other electricity needs, and 

transformer losses as measured at the transmission side of the 

step up transformer (e.g., the point of sale). 

Net energy output means: 

(1) The net electric or mechanical output from the affected 

facility, plus 100 percent of the useful thermal output measured 

relative to SATP conditions that is not used to generate 

additional electric or mechanical output or to enhance the 

performance of the unit (e.g., steam delivered to an industrial 

process for a heating application). 

(2) For combined heat and power facilities where at least 

20.0 percent of the total gross or net energy output consists of 

electric or direct mechanical output and at least 20.0 percent 
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of the total gross or net energy output consists of useful 

thermal output on a 12-operating month rolling average basis, 

the net electric or mechanical output from the affected EGU 

divided by 0.95, plus 100 percent of the useful thermal output; 

(e.g., steam delivered to an industrial process for a heating 

application).

PetroleumQualified biomass means crude oil or a fuel 

derived from crude oil, including, but not limited to, 

distillate and residual oil. 

Qualifying energy generating resource means: 

(1) An affected EGU, 

(2) Electric generating technologies using renewable 

energy resources, such as wind, solar, geothermal, 

hydro, wave, and tidal power, 

(3) Biomass co-firing or repowering, 

(4) Nuclear power, and 

(5) Waste heat power. 

Qualifying energy savings measure means a demand-side 

energy efficiency or demand-side management measurebiomass 

feedstock that saves electricity and is calculated on the 

basisis demonstrated as a method to control increases of ex 

poste savings, not “projected” or “claimed” savings. CO2 levels 

in the atmosphere.

Qualifying ERC generating resource means a resource or 
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measure that may generate ERCs that (a) began generating 

electricity or had a capacity uprate no earlier than January 1, 

2013 (in the case of a qualifying energy generating resource) or 

began saving energy no earlier than January 1, 2013 (in case of 

a qualifying energy saving measure), and (b) is connected to, 

and delivers energy to or saves electricity, on the continental 

electric grid in the United States.

Solid fuel means any fuel that has a definite shape and 

volume, has no tendency to flow or disperse under moderate 

stress, and is not liquid or gaseous at ISO conditions. This 

includes, but is not limited to, coal, biomass, and pulverized 

solid fuels. 

Standard ambient temperature and pressure (SATP) 

conditions means 298.15 Kelvin (25o C, 77 oF)) and 100.0 

kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy 

of water at SATP conditions is 50 Btu/lb. 

State agent means an entity acting on behalf of the 

stateState, with the legal authority of the stateState 

State measures means measures that the stateState adopts 

and implements as a matter of stateState law. Such measures are 

enforceable only per stateState law, and are not included in and 

codified as part of the federally enforceable stateState plan. 

Stationary combustion turbine means all equipment, 

including but not limited to the turbine engine, the fuel, air, 
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lubrication and exhaust gas systems, control systems (except 

emissions control equipment), heat recovery system, fuel 

compressor, heater, and/or pump, post-combustion emissions 

control technology, and any ancillary components and subcomponents comprising any simple cycle stationary combustion 

turbine, any combined cycle combustion turbine, and any combined 

heat and power combustion turbine based system plus any 

integrated equipment that provides electricity or useful thermal 

output to the combustion turbine engine, heat recovery system or 

auxiliary equipment. Stationary means that the combustion 

turbine is not self-propelled or intended to be propelled while 

performing its function. It may, however, be mounted on a 

vehicle for portability. If a stationary combustion turbine 

burns any solid fuel directly it is considered a steam 

generating unit. 

Steam generating unit means any furnace, boiler, or other 

device used for combusting fuel and producing steam (nuclear 

steam generators are not included) plus any integrated equipment 

that provides electricity or useful thermal output to the 

affected facility or auxiliary equipment. 

Uprate means an increase in available electric generating 

unit power capacity due to a system or equipment modification. 

Useful thermal output means the thermal energy made 

available for use in any heating application (e.g., steam 
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delivered to an industrial process for a heating application, 

including thermal cooling applications) that is not used for 

electric generation, mechanical output at the affected EGU, to 

directly enhance the performance of the affected EGU (e.g., 

economizer output is not useful thermal output, but thermal 

energy used to reduce fuel moisture is considered useful thermal 

output), or to supply energy to a pollution control device at 

the affected EGU. Useful thermal output for affected EGU(s) with 

no condensate return (or other thermal energy input to the 

affected EGU(s)) or where measuring the energy in the condensate 

(or other thermal energy input to the affected EGU(s)) would not 

meaningfully impact the emission rate calculation is measured 

against the energy in the thermal output at SATP conditions. 

Affected EGU(s) with meaningful energy in the condensate return 

(or other thermal energy input to the affected EGU) must measure 

the energy in the condensate and subtract that energy relative 

to SATP conditions from the measured thermal output.

Valid data means quality-assured data generated by 

continuous monitoring systems that are installed, operated, and 

maintained according to part 75 of this chapter. For CEMS, the 

initial certification requirements in §75.20 of this chapter and 

appendix A to part 75 of this chapter must be met before 

quality-assured data are reported under this subpart; for ongoing quality assurance, the daily, quarterly, and 
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semiannual/annual test requirements in sections 2.1, 2.2, and 

2.3 of appendix B to part 75 of this chapter must be met and the 

data validation criteria in sections 2.1.5, 2.2.3, and 2.3.2 of 

appendix B to part 75 of this chapter apply. For fuel flow 

meters, the initial certification requirements in section 2.1.5 

of appendix D to part 75 of this chapter must be met before 

quality-assured data are reported under this subpart (except for 

qualifying commercial billing meters under section 2.1.4.2 of 

appendix D), and for on-going quality assurance, the provisions 

in section 2.1.6 of appendix D to part 75 of this chapter apply 

(except for qualifying commercial billing meters). 

Waste-to-Energy means a process or unit (e.g., solid waste 

incineration unit) that recovers energy from the conversion or 

combustion of waste stream materials, such as municipal solid 

waste, to generate electricity and/or heat. 

Table 1 to Subpart UUUU of Part 60—CO2 Emission Performance Rates 

(Pounds of CO2 Perper Net MWh) 

Affected EGU Interim Rate Final Rate

Steam generating 

unit or integrated 

gasification 

combined cycle 

(IGCC) 

[X]1,534 12901,305

Stationary 

combustion turbine 

[X]832 780771
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Table 2 to Subpart UUUU of Part 60—Statewide Rate-based CO2

Emission Goals (Pounds of CO2 Perper Net MWh) 

[Placeholder for table] 

Table 3 to Subpart UUUU of Part 60—Statewide Mass-based CO2

Emission Goals (Short Tons of CO2) 

[Placeholder for table] 

State Interim Emission 

Goal Final Emission Goal 

Alabama 1,157 1,018 

Arizona 1,173 1,031 

Arkansas 1,304 1,130 

California 907 828 

Colorado 1,362 1,174 

Connecticut 852 786 

Delaware 1,023 916 

Florida 1,026 919 

Georgia 1,198 1,049 

Idaho 832 771 

Illinois 1,456 1,245 

Indiana 1,451 1,242 

Iowa 1,505 1,283 

Kansas 1,519 1,293 

Kentucky 1,509 1,286 

Lands of the Fort 

Mojave Tribe 832 771 

Lands of the Navajo 

Nation 1,534 1,305 

Lands of the Uintah 

and Ouray 

Reservation 

1,534 1,305 

Louisiana 1,293 1,121 

Maine 842 779 

Maryland 1,510 1,287 

Massachusetts 902 824 

Michigan 1,355 1,169 

Minnesota 1,414 1,213 

Mississippi 1,061 945 

Missouri 1,490 1,272 
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Montana 1,534 1,305 

Nebraska 1,522 1,296 

Nevada 942 855 

New Hampshire 947 858 

New Jersey 885 812 

New Mexico 1,325 1,146 

New York 1,025 918 

North Carolina 1,311 1,136 

North Dakota 1,534 1,305 

Ohio 1,383 1,190 

Oklahoma 1,223 1,068 

Oregon 964 871 

Pennsylvania 1,258 1,095 

Rhode Island 832 771 

South Carolina 1,338 1,156 

South Dakota 1,352 1,167 

Tennessee 1,411 1,211 

Texas 1,188 1,042 

Utah 1,368 1,179 

Virginia 1,047 934 

Washington 1,111 983 

West Virginia 1,534 1,305 

Wisconsin 1,364 1,176 

Wyoming 1,526 1,299 

Table 3 to Subpart UUUU of Part 60—Statewide Mass-based CO2

Emission Goals (Short Tons of CO2)

State Interim Emission 

Goal (2022-2029) 

Final Emission Goals 

(2 year blocks 

starting with 2030-

2031) 

Alabama 497,682,304 113,760,948 

Arizona 264,495,976 60,341,500 

Arkansas 269,466,064 60,645,264 

California 408,216,600 96,820,240 

Colorado 267,103,064 59,800,794 

Connecticut 57,902,920 13,883,046 

Delaware 40,502,952 9,423,650 

Florida 903,877,832 210,189,408 

Georgia 407,408,672 92,693,692 

Idaho 12,401,136 2,985,712 
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Illinois 598,407,008 132,954,314 

Indiana 684,936,520 152,227,670 

Iowa 226,035,288 50,036,272 

Kansas 198,874,664 43,981,652 

Kentucky 570,502,416 126,252,242 

Lands of the Fort 

Mojave Tribe 4,888,824 1,177,038 

Lands of the Navajo 

Nation 196,462,344 43,401,174 

Lands of the Uintah 

and Ouray 

Reservation 20,491,560 4,526,862 

Louisiana 314,482,512 70,854,046 

Maine 17,265,472 4,147,884 

Maryland 129,675,168 28,695,256 

Massachusetts 101,981,416 24,209,494 

Michigan 424,457,200 95,088,128 

Minnesota 203,468,736 45,356,736 

Missouri 500,555,464 110,925,768 

Mississippi 218,706,504 50,608,674 

Montana 102,330,640 22,606,214 

Nebraska 165,292,128 36,545,478 

Nevada 114,752,736 27,047,168 

New Hampshire 33,947,936 7,995,158 

New Jersey 139,411,048 33,199,490 

New Mexico 110,524,488 24,825,204 

New York 268,762,632 62,514,858 

North Carolina 455,888,200 102,532,468 

North Dakota 189,062,568 41,766,464 

Ohio 660,212,104 147,539,612 

Oklahoma 356,882,656 80,976,398 

Oregon 69,145,312 16,237,308 

Pennsylvania 794,646,616 179,644,616 

Rhode Island 29,259,080 7,044,450 

South Carolina 231,756,984 51,997,936 

South Dakota 31,591,600 7,078,962 

Tennessee 254,278,880 56,696,792 

Texas 1,664,726,728 379,177,684 

Utah 212,531,040 47,556,386 

Virginia 236,640,576 54,866,222 

Washington 93,437,656 21,478,344 

West Virginia 464,664,712 102,650,684 

Wisconsin 250,066,848 55,973,976 

Wyoming 286,240,416 63,268,824 
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Table 4 to Subpart UUUU of Part 60— Statewide Mass-based CO2

Goals plus New Source CO2 Emission Complement (Short Tons of CO2)

State Interim Emission 

Goal (2022-2029) 

Final Emission Goals 

(2 year blocks 

starting with 2030-

2031) 

 Alabama 504,534,496 115,272,348 

Arizona 275,895,952 64,760,392 

Arkansas 272,756,576 61,371,058 

California 430,988,824 105,647,270 

Colorado 277,022,392 63,645,748 

Connecticut 58,986,192 14,121,986 

Delaware 41,133,688 9,562,772 

Florida 917,904,040 213,283,190 

Georgia 412,826,944 93,888,808 

Idaho 13,155,256 3,278,026 

Illinois 604,953,792 134,398,348 

Indiana 692,451,256 153,885,208 

Iowa 228,426,760 50,563,762 

Kansas 200,960,120 44,441,644 

Kentucky 576,522,048 127,580,002 

Lands of the Fort 

Mojave Tribe 5,186,112 1,292,276 

Lands of the Navajo 

Nation 202,938,832 45,911,608 

Lands of the Uintah 

and Ouray 

Reservation 

21,167,080 4,788,708 

Louisiana 318,356,976 71,708,642 

Maine 17,592,128 4,219,936 

Maryland 131,042,600 28,996,872 

Massachusetts 103,782,424 24,606,744 

Michigan 429,446,408 96,188,604 

Minnesota 205,761,008 45,862,346 

Mississippi 221,990,024 51,332,926 

Missouri 505,904,560 112,105,626 

Montana 105,704,024 23,913,816 

Nebraska 167,021,320 36,926,888 

Nevada 120,916,064 29,436,214 

New Hampshire 34,519,280 8,121,182 
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New Jersey 141,919,248 33,752,728 

New Mexico 114,741,592 26,459,850 

New York 272,940,440 63,436,364 

North Carolina 461,424,928 103,753,712 

North Dakota 191,025,152 42,199,354 

Ohio 667,812,080 149,215,950 

Oklahoma 361,531,056 82,001,704 

Oregon 72,774,608 17,644,106 

Pennsylvania 804,705,296 181,863,274 

Rhode Island 29,819,360 7,168,032 

South Carolina 234,516,064 52,606,510 

South Dakota 31,963,696 7,161,036 

Tennessee 257,149,584 57,329,988 

Texas 1,707,356,792 396,210,498 

Utah 220,386,616 50,601,386 

Virginia 240,240,880 55,660,348 

Washington 97,691,736 23,127,324 

West Virginia 469,488,232 103,714,614 

Wisconsin 252,985,576 56,617,764 

Wyoming 295,724,848 66,945,204