The EPA Administrator, Gina McCarthy, signed the following notice on 8/3/2015, and EPA is submitting it for 

publication in the Federal Register (FR). While we have taken steps to ensure the accuracy of this Internet version 

of the rule, it is not the official version of the rule for purposes of compliance. Please refer to the official version in 

a forthcoming FR publication, which will appear on the Government Printing Office's FDSys website 

(http://gpo.gov/fdsys/search/home.action) and on Regulations.gov (http://www.regulations.gov) in Docket No. 

EPA–HQ–OAR–2013-0602. Once the official version of this document is published in the FR, this version will be 

removed from the Internet and replaced with a link to the official version.

[Type here]

6560-50

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 to 

follow in developing pans 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 subcategories of 

existing fossil fuel-fired EGUs – fossil fuel-fired electric 

utility steam generating units and stationary combustion 

turbines, 2) 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 accomplished by meeting 
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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 60 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 

public docket, visit the EPA Docket Center homepage at 

http://www2.epa.gov/dockets.
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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 

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:
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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 and 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)

CEIP Clean Energy Incentive Program

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

MW Megawatt

MWh Megawatt-hour

NAAQS National Ambient Air Quality Standards

NAICS North American Industry Classification System 

NAS National Academy of Sciences

NGCC Natural Gas Combined Cycle

NOx Nitrogen Oxides
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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 Organization

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

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. Challenges in Controlling Carbon Dioxide Emissions

E. Clean Air Act Regulations for Power Plants

F. Congressional Awareness of Climate Change

G. International Agreements and Actions
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H. Legislative and Regulatory Background for CAA Section 111

I. Statutory and Regulatory Requirements

J. Clean Power Plan Proposal and Supplemental Proposal

K. Stakeholder Outreach and Consultations

L. 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. Subcategory-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

B. Reconstituting 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 and Provisions to 

Encourage Early Action

C. State Plan Approaches 
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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 State Plans

H. 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. Community Engagement in State Plan Development

C. Providing Communities with Access to Additional Resources

D. Federal Programs and Resources Available to Communities 

E. Multi-pollutant Planning and Co-pollutants

F. Assessing Impacts of State Plan Implementation

G. EPA Continued Engagement

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

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 (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 
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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 

clean energy innovation, development and deployment, 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 climate 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, 
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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.

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. These final guidelines, when fully implemented, will 

achieve significant reductions in CO2 emissions by 2030, while

offering states and utilities substantial flexibility and 

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

EPA is 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 – that expresses the “best system of emissions 

reduction... adequately demonstrated” (BSER) for CO2 from the power 

sector.1 The EPA is also establishing state-specific rate-based 

 

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 
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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. 

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 approved by 

the EPA pursuant to 40 CFR 49.9 as eligible to develop and 

implement a CAA section 111(d) plan.2 Because Vermont and the 

 

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.

2 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 
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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 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.

The emission standards in a state’s plan may incorporate

the subcategory-specific CO2 emission performance rates set by 

the EPA or, in the alternative, may be set at levels that ensure 

that the state’s affected EGUs, individually, in aggregate, or 

in combination with other measures undertaken by the state

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, 2) show how goals for the interim and final periods 

 

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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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 subcategory-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 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 is promulgating: 1) subcategory-specific CO2

emission performance rates, 2) state rate-based goals, and 

3) state mass-based CO2 goals that represent the equivalent 

of each state’s rate-based goal. This will facilitate 

states’ choices 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. The EPA received 

significant comment to the effect that mass-based allowance 

trading was not only highly familiar to states and EGUs, 
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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 this rule, 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 RIA, the 

response to comments (RTC) documents, and various TSDs and

memoranda addressing specific topics.

2. Purpose of this rule

The purpose of this rule is to protect human health and the 

environment by reducing CO2 emissions from fossil fuel-fired 

power plants in the U.S. These plants are by far the largest 

domestic stationary source of emissions of CO2, the most 

prevalent of the group of air pollutant 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. These 

guidelines will lead to significant reductions in CO2 emissions, 

result in cleaner generation from the existing power plant 

fleet, and support continued investments by the industry in 

cleaner power generation to ensure reliable, affordable 
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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. Specifically, 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 measures to set achievable emission 

performance rates that will lead to cost-effective pollutant 

emission reductions, in this case CO2 emission reductions at 

power plants, across the country. In fact, the emission 

guidelines reflect strategies, technologies and approaches 
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already in widespread use by power 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) relies on the well-established state-EPA 

partnership to accomplish the required 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 the 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 state-specific rate- and massbased goals.

This final rule is a significant step forward in 
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implementing the President’s Climate Action Plan.3 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 32 percent from CO2 emission levels 

in 2005.

The EPA projects that these reductions, along with 

reductions in other air pollutants resulting directly from this 

rule, will result in net climate and health benefits of $25

billion to $45 billion in 2030. At the same time, coal and 

 

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

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

climateactionplan.pdf.
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natural gas will remain the two leading sources of electricity 

generation in the U.S., with coal providing about 27 percent of 

the projected generation and natural gas providing about 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 

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
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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 

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 
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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 

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 
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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.

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
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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 EE 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 

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, 
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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 

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 
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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 

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 
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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 

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

that the EPA is proposing concurrently with this action.4

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. 

 

4 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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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 

employing to reduce the covered pollutant (in this case, CO2) 

from affected sources (in this case, fossil fuel-fired EGUs).5

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

considerations were not limited solely to specific technologies 

 

5 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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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.

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 
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standards for affected EGUs, do so by incorporating

emissions trading.6 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 

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 rate-

 

6 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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based 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 massbased 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 
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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 

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.7

 

7 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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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. 

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 
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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 

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.8 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 

 

8 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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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 

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, 
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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 

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.9 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 

 

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

independent notice and comment rulemaking.
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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).10 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

 

10 40 CFR 60.23.
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 Demonstration that the plan submittal is projected to 

achieve the state’s CO2 emission performance rates or 

state CO2 goal11

 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. 

 

11 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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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. 

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 
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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. 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 
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been engaging with the public, including vulnerable communities, 

and a description of how they intend to meaningfully engage with 

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 RE and in EE 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 rates or equivalent statewide 

goals by no later than 2030. The EPA is establishing an 8-year 
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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. 

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 
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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. 

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. 
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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.

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 
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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 

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 
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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 

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 EE. The federal government is committed to ensuring that 

all communities share in these benefits. 
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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.

(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 
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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.12

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.13

(7) 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, 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 

 

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

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

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 
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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

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, 
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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 

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 
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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 

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 
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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 

available via a dedicated website.14

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. 

4. Key changes from proposal

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 

 

14 www.epa.gov/cleanpowerplantoolbox.
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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 

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. In this final rule, we are retaining the key design 

elements of the proposal and making certain adjustments to 

respond to a variety of very constructive comments on ways that 
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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. In 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 for states to adopt mass-based programs 

and for utilities accustomed to operating across broad multistate grids to be able to avail themselves of more “ready-made” 

emissions trading regimes. The inclusion of both of these new 

features – mass-based state goals in addition to rate-based 

goals, and source-level emission performance rates for the two
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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.

Many 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 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. 
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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 

continuing beyond that with consultations and meetings with 

stakeholders. The result of this extensive 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. Comments were provided by stakeholders that include 

state environmental and energy officials, tribal officials, 

public utility commissioners, system operators, owners and 

operators of every type of power generating facility, other 
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industry representatives, labor leaders, public health leaders, 

public interest advocates, community and faith leaders, and 

members of the public. 

The insights gained from public comments contributed to the 

development of final emission guidelines that build on the 

proposal 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. The improved guidelines reflect information and 

ideas that states and utilities provided to us about both the 

best approach to establishing CO2 emission reduction 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 

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 faith-based, 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, 
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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 zeroemitting power generation.

c. Key changes. The most significant changes in these final 

guidelines are: 1) the period 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, 2) a revised BSER 

determination that focuses on narrower generation options that 

do not include demand-side EE measures and that includes 

refinements to the building blocks, more complete incorporation 

in the BSER of the realities of electricity operations over the 

three regional interconnections, and up-to-date information 

about the cost and availability of clean generation options, 3) 

establishment of source-specific CO2 emission performance rates

that are uniform across the two fossil fuel-fired subcategories 

covered in these guidelines, as 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 –
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called here the “state measures” approach - that continues 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 that achieve early 

reductions, including a Clean Energy Incentive Program (CEIP), 

8) a combination of provisions expressly designed to ensure 

electric system reliability, 9) the addition of employment 

considerations for states in plan development, and 10) the 

expansion of considerations and programs for low-income and 

vulnerable communities. 

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 
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three regional sessions. The information provided by workshop 

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 them to implement strategies to achieve CO2 reductions. 

They expressed concern that, in the proposal, at least some 

states would 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, as well as about stranded assets. To many 

commenters, the proposal’s requirement for CO2 emission 

reductions beginning in 2020, together with the stringency of 

the interim CO2 goal, posed 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 to be a 

gradual glide path separated into three steps, 2022-2024, 2025-

2027, and 2028-2029, that is also achievable “on average” over 

the 8-year interim period. In response to the concerns of 
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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’ 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 reliable 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.

(2) Revised BSER determination.
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Commenters urged the EPA to confine its BSER determination 

to actions that involve what they characterized as more 

“traditional” generation. 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 nor the emission performance 

rates for the two subcategories 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 

treated as functionally interchangeable with other forms of 

generation for planning and operational purposes, as EE measures 

are in widespread use across the country and provide energy 

savings that reduce emissions, lower electric bills, and lead to 
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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. Sections V.C 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 
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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 

subcategory-specific emission performance rates take into 

account 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, 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 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 
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for companies to take advantage of improved clean energy 

technologies as potential least cost options. 

(3) Uniform emission performance rates.

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 previous new 

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

was that the proposal created de facto emission standards for 

all affected EGUs but that these de facto standards varied 

widely depending on the state in which a given EGU happened to 

be located. Instead, these and other commenters stated, section 

111 requires that EPA establish the BSER specifically for 

affected sources, rather than by means of merely setting statespecific 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 carbonintensive states and a lesser emission reduction burden on 

sources and states that were higher-emitting or more carbonintensive. This, they argued, was both inequitable and at odds 

with the way in which NSPS have been applied in the past, where 

the higher-emitting sources have made the greater and more costeffective reductions, while lower-emitting sources, whose 

reduction opportunities tend to be less cost-effective, have 
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been required to make fewer reductions to meet the applicable 

standard. 

At the same time, state and utility commenters expressed 

concern that relying on state-specific goals and state-by-state 

planning could 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 
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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 performancebased 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 
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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 

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 
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industrial sectors, namely setting source-level, source

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 in the state plan approaches included at 

proposal, but many raised concerns about its legality, with 

respect, in particular, to the CAA’s enforceability 

requirements. Some of these commenters identified a “state 

commitment approach” with backstop measures as a variation of 

the “portfolio” approach that would retain the benefits of the 

“portfolio” approach while resolving legal and enforceability 
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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. 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 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, 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 that complement source-specific 

requirements or, save for the contingent backstop requirement, 

supplant them entirely. This revision provides consistency in 

the treatment of sources while still providing maximum 

flexibility for states to design their plans around reduction 

approaches that best suit their policy objectives.

(5) Emission trading programs.
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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, 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 

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 system to support state emissions trading 

programs.

(6) Extension of plan submittal date.

Stakeholders, particularly states, provided compelling 

information establishing that it could take longer than the 
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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 recognize commenters’ 

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

revised state plan submittal schedule. For states that cannot 

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

those states to make an initial submittal by that date to assure 

that states begin to address the urgent needs for reductions 

quickly, and is providing until September 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.

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 
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importance of these perspectives, and as a result has determined 

to provide a program – called the 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 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 

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 stateissued early action ERCs and allowances up to an amount that 

represents the equivalent of 300 million short tons of CO2

emissions.
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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 lowincome 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 
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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 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 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 EGUs could 

meet their emission reduction requirements without being 
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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. 

The final guidelines support electric system 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 8-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.
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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

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. In 

addition, the final rule 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. 

(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 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 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 
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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.15 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,16 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

agree. The federal 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-

 

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

16 https://www.whitehouse.gov/the-press-office/2015/03/27/factsheet-partnerships-opportunity-and-workforce-and-economicrevitaliz.
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side EE continue to be a major compliance option. The CEIP will 

encourage early investment in these types of projects as well. 

In addition to carbon reduction benefits, we expect significant 

near- and long-term public health benefits in communities 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 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. 

5. Additional context for this final rule

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

in an essential series of long-term actions that are achieving 

and must continue to achieve the GHG emission reductions needed 
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to address the serious threat of climate 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 emissions17 and 82 percent of 

U.S. GHG emissions.18 The May 2014 report of the National Climate 

Assessment19 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 

since 2009, when the EPA determined that GHGs pose a threat to 

 

17 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.

18 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.

19 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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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, well-being, and ways of life 

of indigenous peoples in the U.S.

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

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

power plants.20 This is because fossil fuel-fired EGUs are by far 

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

stationary sources in the U.S. and among fossil fuel-fired EGUs, 

coal-fired units are by far the largest emitters of GHGs. To 

accomplish the goal of reducing CO2 emissions from power plants,

 

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

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

climateactionplan.pdf.
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President Obama issued a Presidential Memorandum21 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 fuel-fired EGUs. This CAA section 111(d) action 

builds on actions states and utilities are already taking to 

move toward cleaner generation of electric power.

The utility power sector is unlike other industrial 

sectors. 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 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 

 

21 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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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 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, system 

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 using available generation and demand-side resources, 

including EE, demand response and a wide range of low- and zeroemitting sources. These resources are 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 entities working in 

coordination and considering overall system reliability. For 

example, in an independent system operator (ISO) or regional 

transmission organization (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 
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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. 

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.

In this integrated system, numerous entities have both the 

capability and the responsibility to maintain a reliable 

electric system. FERC, DOE, state public utility commissions, 

ISOs, 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. 
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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.22 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.”23 The U.S. Supreme Court has explicitly recognized the 

interconnected nature of the electricity grid.24

 

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

Systems, IEEE Press, at 159 (2d ed. 2010).

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

Systems, IEEE Press, at 160 (2d ed. 2010).

24 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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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 

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. This is

evidenced in the enactment or promulgation of pollution 

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

implementation plan (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 
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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, which enabled pollution 

reduction by increasing reliance on RE and demand-side EE. 

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 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 subcategory-specific emission 

performance rates, and the pathways offered to achieve them, 

reflect and are tailored to the unique characteristics of the 

utility power sector. 

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

U.S. is already changing as a result of advancements in 

innovative power sector technologies and in the availability and 

cost of low-carbon fuel, RE and 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 address 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 
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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 of the need to 

take account of the age of current assets and infrastructure. 

Historically, 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 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 404 entities identified as owners or operators of 

affected EGUs, representing ownership of 82 percent of the total 

capacity of the affected EGUs, 178 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 25 percent of the aggregate 

amounts of their affected EGU capacity.25 In addition, funding 

for utility EE programs has been growing rapidly, increasing 

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

 

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

2015.
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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 

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.

6. Projected national-level emission reductions

Under the final guidelines, the EPA projects annual CO2

reductions of 22 to 23 percent below 2005 levels in 2020, 

28 to 29 percent below 2005 levels in 2025, and 32 percent 

below 2005 levels in 2030. These guidelines will also 
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result in important reductions in emissions of criteria air 

pollutants, including SO2, 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.

7. 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 

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 EE. 

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 RIA for this final action presents two scenarios 

designed to achieve these goals, which we term the “rate-
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based” illustrative plan approach and the “mass-based” 

illustrative plan approach.

In summary, we estimate the total combined climate benefits 

and health co-benefits for the rate-based approach to be $3.5 to 

$4.6 billion in 2020, $18 to $28 billion in 2025, and $34 to $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 15 through 22 of this 

preamble.

The annual compliance costs are estimated using the 

Integrated Planning Model (IPM) and include demand-side EE

program and participant costs as well as monitoring, reporting 

and recordkeeping costs. In 2020, total compliance costs of the 

final guidelines are approximately $2.5 billion (2011$) under 

the rate-based approach and $1.4 billion (2011$) under the massbased approach. In 2025, total compliance costs of the final 

guidelines are approximately $1.0 billion (2011$) under the 

rate-based approach and $3.0 billion (2011$) under the massbased approach. In 2030, total compliance costs of the final 

guidelines are approximately $8.4 billion (2011$) under the 
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rate-based approach and $5.1 billion (2011$) under the massbased approach.

The quantified net benefits (the difference between 

monetized benefits and compliance costs) in 2020 are estimated 

to range from $1.0 billion to $2.1 billion (2011$) 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 $17 billion to $27 billion (2011$) 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 $26 billion to $45 billion (2011$) 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$]

Rate-based Approach, 2020

3% Discount Rate 7% Discount rate

Climate benefits b $2.8

Air pollution health 

co-benefits c $0.70 to $1.8 $0.64 to $1.7

Total Compliance 

Costs d $2.5 $2.5

Net Monetized 

Benefits e $1.0 to $2.1 $1.0 to $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

Rate-based Approach, 2025

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

Rate-based Approach, 2030

Climate benefits b $20
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Air pollution health 

co-benefits c $14 to $34 $13 to $31

Total Compliance 

Costs d $8.4 $8.4

Net Monetized 

Benefits e $26 to $45 $25 to $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 

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 EE program and participant costs.
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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. Summary of the Monetized Benefits, Compliance Costs, 

and Net Benefits for the Final Guidelines in 2020, 2025 and 2030a

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
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Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury

Visibility impairment

Mass-based Approach, 2030

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 
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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 EE 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 GHGs

(e.g., nitrous oxide and methane)26 and co-benefits from 

reducing direct exposure to SO2, NOX, and HAP (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 

 

26 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 EE. In 2030, we 

project a net decrease in job-years of about 31,000 under 

the rate-based approach and 34,000 under the mass-based 

approach27 for construction, plant operation and 

maintenance, and coal and natural gas and a gain of 52,000 

to 83,000 jobs in the demand-side EE 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 

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, 

 

27 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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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 

three building blocks and our key considerations in making the 

determination. Section VI provides the subcategory-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 XIII.

We note that this rulemaking is being promulgated 

concurrently with two related rulemakings: the final 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), and the proposed federal plan and model rules [INSERT 
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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, the challenges associated with controlling carbon dioxide 

emisions, the uniqueness of the utility power sector, and 

drecent and continuing trends and transitions in the 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 statutory and regulatory requirements relevant to this 

rulemaking. In addition, we provide background information on 

the EPA’s June 18, 2014 Clean Power Plan proposal, the November 

4, 2014 supplemental proposal, and other actions associated with 

this rulemaking,28 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 

 

28 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). 
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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.”29

In 2009, based on a large body of robust and compelling 

scientific evidence, the EPA Administrator issued the 

Endangerment Finding under CAA section 202(a)(1).30 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 U.S. We summarize these adverse 

effects on public health and welfare briefly here. 

1. Public health impacts detailed in the 2009 Endangerment 

Finding

 

29 National Research Council, Climate Stabilization Targets, p.3. 

30 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases Under Section 202(a) of the Clean Air Act,” 74 FR 66496 

(Dec. 15, 2009) (“Endangerment Finding”).
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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 U.S. Compared to a future without climate 

change, climate change is expected to increase ozone pollution 

over broad areas of the U.S., especially on the highest ozone 

days and in the largest metropolitan areas 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 
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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. 

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
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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. 

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 
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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 

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 U.S. will be impacted by “increased extreme weather events, 

wildfire, decreased air quality, threats to mental health, and 

illnesses transmitted by food, water, and disease-carriers such 

as mosquitoes and ticks.” The most recent assessments now have 
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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. 

The NCA3 also finds that climate change, in addition to 

chronic stresses such as extreme poverty, is negatively 

affecting indigenous peoples’ health in the U.S. 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 wellbeing 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 
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exposed locations along ocean, lake, or river shorelines.”31 In 

addition, increasing temperatures and loss of Arctic sea ice 

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. 

 

31 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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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.

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.32 In fact, that assessment stated that 

“the magnitude and rate of the present GHG 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.”33 Because of these unprecedented changes, several 

assessments state that we may be approaching critical, poorly 

understood thresholds. As stated in the assessment, “As Earth 

continues to warm, it may be approaching a critical climate 

 

32 National Research Council, Understanding Earth’s Deep Past, p. 

1.

33 Id., p.138.
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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, 

or because climatic conditions are changing more rapidly than 

the species can move or adapt. While the NRC determined that it 
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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 

likely warm even faster than the global average. However, 

according to the NCA3, significant reductions in emissions would 
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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 

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, 
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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,”34 and the NRC Climate 

Stabilization Targets assessment states that an increase of 3°C 

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 

 

34 NRC, 2011: National Security Implications of Climate Change 

for U.S. Naval Forces. The National Academies Press, p. 28.
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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.”35 Also, because of the inertia of the oceans, sea level 

rise will continue for centuries after GHG 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 has suggested that 

even present day CO2 levels could be sufficient to exceed that 

threshold.

In general, climate change impacts are expected to be 

unevenly distributed across different regions of the U.S. and 

have a greater impact on certain populations, such as indigenous 

peoples and the poor. The NCA3 finds climate change impacts such 

 

35 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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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 

U.S. 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.”36 The IPCC AR5 notes, 

“Climate-related hazards exacerbate other stressors, often with 

negative outcomes for livelihoods, especially for people living 

in poverty (high confidence). 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.”37

 

36 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.

37 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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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 

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 
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hundreds of thousands of years.”38 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.”39 

Events outside the U.S., 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 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 U.S. 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 

 

38 NRC, 2010: Ocean Acidification: A National Strategy to Meet 

the Challenges of a Changing Ocean. The National Academies 

Press, p. 5.

39 Ibid.
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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 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 
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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 

about 280 parts per million.40 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.41 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 

 

40ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.tx

t.

41 http://www.esrl.noaa.gov/gmd/ccgg/trends/.
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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 1993.42 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 2002.43 The 

first months of 2015 have also been some of the warmest on 

record. 

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.”44 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 

GHGs is on the higher end of the estimated range.

 

42 Blunden, J., and D. S. Arndt, Eds., 2014: State of the Climate 

in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238.

43 http://www.ncdc.noaa.gov/sotc/global/2014/13.

44 NRC, 2011: America’s Climate Choices, The National Academies 

Press.
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 Waiting for unacceptable impacts to occur before taking 

action is imprudent because the effects of GHG 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 

U.S., noting that changes in physical climate 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 
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events is a larger increase in extreme precipitation than 

experienced in any other U.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 

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 
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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 

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 U.S., 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 
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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.

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 GHG emissions), with the greatest warming is expected 

during the summer. Continued increases in global GHG emissions 

are projected to result in up to a 30 percent decrease in summer 

precipitation. Earlier snowpack melt and lower summer stream 
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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 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 U.S. 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 
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the 1940s, when recordkeeping began. Climate change impacts are 

harming the health, safety and livelihoods of Native Alaskan 

communities. 

By the end of this century, continued increases in GHG

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 
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millions of waterfowl and shorebirds that winter in the lower 48 

states. Warmer ocean temperatures, acidification, and declining 

sea ice will contribute to changes in the location and 

availability of 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 
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increase vulnerability to floods for hundreds of thousands of 

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 

that are already the most vulnerable to weather and climate 
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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 

level rise will reduce the quantity and quality of freshwater in 

coastal aquifers, especially on low islands. In areas where 
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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.

B. GHG Emissions from Fossil Fuel-fired EGUs45

 

45 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 
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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 Sinks46 (the U.S. GHG Inventory). 

The EPA implements a separate program under 40 CFR Part 98 

called the Greenhouse Gas Reporting Program47 (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. 

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 mass-based state goals presented in section VII of this 

preamble, and discussed elsewhere in this preamble, are 

presented in short tons.

46 “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

47 U.S. EPA Greenhouse Gas Reporting Program Dataset, see 

http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html.
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the information in Table 3 below, which presents total U.S. 

anthropogenic emissions and sinks48 of GHGs, including CO2

emissions, for the years 1990, 2005 and 2013.

Table 3. U.S. GHG Emissions and Sinks by Sector (million metric 

tons carbon dioxide equivalent (MMT CO2 Eq.))49

SECTOR 1990 2005 2013

Energy50

 

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

Land Use, Land-Use 

Change and Forestry 

(Sinks)

 

(775.8) (911.9) (881.7)

Net Emissions (Sources 

and Sinks)

 

5,525.2 6,438.3

 

5,791.2

 

48 Sinks are a physical unit or process that stores GHGs, such as 

forests or underground or deep sea reservoirs of carbon dioxide.

49 From Table ES-4 of “Inventory of U.S. Greenhouse Gas Emissions 

and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, U.S.

Environmental Protection Agency, April 15, 2015.

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

50 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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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.51 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.52 Table 4

below presents total CO2 emissions from fossil fuel-fired EGUs, 

for years 1990, 2005 and 2013.

Table 4. U.S. GHG Emissions from Generation of Electricity from 

Combustion of Fossil Fuels (MMT CO2)53

 

51 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

.

52 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

53 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

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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In addition to preparing the official U.S. GHG Inventory to 

present comprehensive total U.S. GHG 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 5

below presents total GHG emissions in 2013 for the largest 

emitting industrial sectors as reported to the GHGRP. As shown 

in Table 4 and Table 5, 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 5. Direct GHG Emissions Reported to GHGRP by Largest 

Emitting Industrial Sectors (MMT CO2e)54

 

54 U.S. EPA Greenhouse Gas Reporting Program Dataset as of August 

18, 2014. http://ghgdata.epa.gov/ghgp/main.do.

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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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 

greater than any other air pollutant.55 In fact, CO2 is emitted 

in far greater quantities than all other air pollutants 

combined. Total emissions of all non-GHG air pollutants in the 

U.S., from all sources, in 2013, were 121 million metric

 

55 Lackner et al., “Comparative Impacts of Fossil Fuels and 

Alternative Energy Sources”, Issues in Environmental Science and 

Technology (2010).
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tons.56,57 As noted above, total emissions of CO2 from coal-fired 

power plants alone – the largest stationary source emitter --

 

56 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.

57 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.

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.)
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were 1.575 billion metric tons in that year,58 and total 

emissions of CO2 from all sources were 5.5 billion metric 

tons.59,60 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.61 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

is relatively unreactive and difficult to remove directly from 

the atmosphere.62,63

CO2’s huge quantities and lack of reactivity make it

challenging to remove from the smokestack. Retrofitted equipment 

 

58 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

.

59 U.S. EPA, Greenhouse Gas Inventory Data Explorer, 

http://www.epa.gov/climatechange/ghgemissions/inventoryexplorer/

#allsectors/allgas/gas/current.

60 As another point of comparison, except for carbon dioxide, SO2

and NOx are the largest air pollutant emissions from coal-fired 

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).

61 Each atom of carbon in the fuel combines with 2 atoms of 

oxygen in the air.

62 Seinfeld J. and Pandis S., Atmospheric Chemistry and Physics: 

From Air Pollution to Climate Change (1998).

63 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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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 

the fuel, and, as a result, it can be reduced by using lowsulfur coal or by using flue-gas desulfurization (FGD) 

technologies. Emissions of 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. 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 
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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

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,64

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.65 During the early 1900s, smaller systems 

 

64 Regulatory Assistance Project (RAP), Electricity Regulation in 

the US: A Guide, at 1 (2011), available at 

http://www.raponline.org/document/download/id/645.

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

Systems, IEEE Press, at 2-4 (2d ed. 2010).
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consolidated, allowing generation resources to be shared over 

larger areas. Interconnecting systems have reduced generation 

investment costs and improved reliability.66 Local and state 

governments initially regulated these growing electricity 

systems with federal regulation coming later in response to 

public concerns about rising electricity costs.67

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.68 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 

 

66 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.

67 Burn, An Energy Journal, The Electricity Grid: A History, 

available at http://burnanenergyjournal.com/the-electric-grid-ahistory/ (last visited Mar. 9, 2015). 

68 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.
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allow state regulation to directly burden interstate commerce.69

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.70 The Supreme Court 

found that Rhode Island’s regulation was impermissible because 

it imposed a "direct burden upon interstate commerce."71 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."72

Under FPA section 205, the FPC was tasked with ensuring that 

rates for jurisdictional services are just, reasonable, and not 

 

69 New York v. Federal Energy Regulatory Commission, 535 U.S. 1, 

5 (2002) (citation omitted).

70 Public Utils. Comm'n of Rhode Island v. Attleboro Steam & 

Elec. Co., 273 U.S. 83 (1927).

71 Public Utils. Comm'n of Rhode Island v. Attleboro Steam & 

Elec. Co., 273 U.S. 83, 89 (1927).

72 16 U.S.C. § 824(b)(1).
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unduly discriminatory or preferential.73 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.74 In 1938, Congress passed 

the Natural Gas Act (NGA), giving the FPC jurisdiction over the 

transmission or sale of natural gas in interstate commerce.75 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.”76 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.77 These regulated 

monopolies are referred to as vertically-integrated utilities.

 

73 16 U.S.C. § 824d.

74 16 U.S.C. § 824e.

75 Energy Information Administration, Natural Gas Act of 1938, 

available at 

http://www.eia.gov/oil_gas/natural_gas/analysis_publications/ngm

ajorleg/ngact1938.html.

76 Energy Information Administration, Natural Gas Act of 1938, 

available at 

http://www.eia.gov/oil_gas/natural_gas/analysis_publications/ngm

ajorleg/ngact1938.html.

77 Burn, An Energy Journal, The Electricity Grid: A History, 

available at http://burnanenergyjournal.com/the-electric-grid-ahistory/(last visited Mar. 9, 2015).
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As utilities built larger and larger electric generation 

plants, the cost per unit to generate electricity decreased.78 

However, these larger plants were extremely capital intensive 

for any one company to fund.79 Some neighboring utilities solved 

this issue by agreeing to share electricity reserves when 

needed.80 These utilities began building larger transmission 

lines to deliver power in times when large generators 

experienced outages.81 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.82 Some power 

pools evolved into today’s RTOs and ISOs. 

In the past, electric utilities generally operated as state 

regulated monopolies, supplying end-use customers with 

 

78 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.

79 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.

80 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.

81 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.

82 Shively, B, Ferrare, J, Understanding Today’s Electricity 

Business, Enerdynamics, at 94 (2012).
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generation, distribution, and transmission service.83 However, 

the ability of electric utilities to operate as natural 

monopolies came with consumer protection safeguards.84 “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.”85 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.86 In the early 1990s, some states began to consider 

 

83 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).

84 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.

85 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.

86 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).
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allowing competition to enter retail electric service.87 Federal 

and state efforts to allow competition in the electric utility 

industry have resulted in independent power producers (IPPs)88

producing approximately 37 percent of net generation in 2013.89

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 U.S.90

These utilities include both investor-owned utilities91 and 

consumer-owned utilities.92 

 

87 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-pol-act/epact-finalrpt.pdf (last visited Mar. 20, 2015).

88 These entities are also referred to as merchant generators.

89 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.

90 Regulatory Assistance Project (RAP), Electricity Regulation in 

the US: A Guide, at 9 (2011), available at 

http://www.raponline.org/document/download/id/645.

91 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.

92 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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Over time, the grid slowly evolved into a complex, 

interconnected transmission system that allows electric 

generators to produce electricity that is then fed onto 

transmission lines at high voltages.93 These larger transmission 

lines are able to access generation that is located more 

remotely, with transmission lines crossing many miles, including 

state borders.94 Closer to end users, electricity is transformed 

 

93 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 U.S. and parts of Canada.” 

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

IEEE Press, at 5-6 (2d ed. 2010).

94 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 
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into a lower voltage that is transported across localized 

transmission lines to homes and businesses.95 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.96 Electricity from a diverse set of 

generation resources such as natural gas, nuclear, coal, and 

 

Canada: Causes and Recommendations, at 6 (Apr. 2004), available 

at http://www.ferc.gov/industries/electric/indusact/reliability/blackout/ch1-3.pdf.

95 Peter Fox-Penner, Electric Utility Restructuring: A Guide to 

the Competitive Era, Public Utility Reports, Inc., at 5 (1997).

96 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 U.S. into three synchronous 

interconnections – the Eastern Interconnection, Western 

Interconnection, and the Texas Interconnection.97 These three

synchronous systems each act like a single machine.98 Diverse 

resources generate electricity that is transmitted and 

distributed through a complex system of interconnected 

components to industrial, business, and residential consumers. 

 

97 Regulatory Assistance Project (RAP), Electricity Regulation in 

the US: A Guide, 2011, at 1, available at

http://www.raponline.org/document/download/id/645.

98 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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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 resources99, 

such as EE100 and demand response.101 Generation, outages, and 

 

99 “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. 

100 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. 

101 Demand response involves “[c]hanges in electric usage by 

demand-side resources from their normal consumption patterns in 
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transmission changes in one part of the synchronous grid can 

affect the entire interconnected grid.102 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.”103 The U.S. Supreme Court has similarly recognized the 

interconnected nature of the electricity grid.104

 

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.

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

Systems, IEEE Press, at 159 (2d ed. 2010).

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

Systems, IEEE Press, at 160 (2d ed. 2010).

104 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 (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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Today, federal, state, and local entities regulate 

electricity providers.105 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.”106 

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 

electricity are privately owned.107 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.108 “The role of the 

regulator now includes support for the development of open and 

 

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

Systems, IEEE Press, at 214 (2d ed. 2010).

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

Systems, IEEE Press, at 213 (2d ed. 2010).

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

Systems, IEEE Press, at 213 (2d ed. 2010).

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

Systems, IEEE Press, at 214 (2d ed. 2010).
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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.”109 

2. Electric system dispatch

System operators typically dispatch the electric system 

through a process known as Security Constrained Economic 

Dispatch.110 Security Constrained Economic Dispatch has two 

components – economic generation of generation facilities and 

ensuring that the electric system remains reliable.111

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 costeffective manner possible. The cost of operating electric 

generation varies based on a number of factors, such as fuel and 

generator efficiency. 

 

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

Systems, IEEE Press, at 214 (2d ed. 2010).

110 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).

111 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).
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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.112 Renewables, hydroelectric, and nuclear have little 

to no variable costs. If electricity demand decreases or 

additional generation becomes available on the system, this 

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 reasons generally 

operated at their maximum output whenever they are available. 

When lower cost units are available to run, higher variable cost 

units, such as fossil-fuel generators, are generally the first 

to be displaced.

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 

 

112 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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ISOs coordinate, control, and monitor electricity transmission 

systems to ensure cost-effective 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 

Canada.113 In 1965, the northeastern U.S. and southeastern 

Ontario, Canada experienced the largest power blackout to date, 

impacting 30 million people.114 In response to the 1965 blackout 

and a Federal Power Commission recommendation,115 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 

 

113 North American Electric Reliability Corporation, History of 

NERC, at 1 (2013), available at

http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.

114 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. 

115 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.
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Canada’s participation.116 The North American Electric 

Reliability Council became the North American Electric 

Reliability Corporation in 2007.117 

In August 2003, North America experienced its worst 

blackout to date creating an outage in the Midwest, Northeast, 

and Ontario, Canada.118 This blackout was massive in scale 

impacting an area with an estimated 50 million people and 61,800 

megawatts of electric load.119 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.120

 

116 North American Electric Reliability Corporation, History of 

NERC, at 2 (2013), available at

http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.

117 North American Electric Reliability Corporation, History of 

NERC, at 4 (2013), available at

http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.

118 North American Electric Reliability Corporation, History of 

NERC, at 3 (2013), available at

http://www.nerc.com/AboutNERC/Documents/History%20AUG13.pdf.

119 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.

120 U.S.-Canada Power System Outage Task Force, Final Report on 

the August 14, 2003 Blackout in the United States and Canada: 
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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 

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.121 In 2006, the Federal Energy Regulatory 

Commission (FERC) certified NERC as the ERO.122 “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.”123

 

Causes and Recommendations, at 2 (Apr. 2004), available at

http://www.ferc.gov/industries/electric/indusact/reliability/blackout/ch1-3.pdf.

121 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)).

122 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).

123 North American Electric Reliability Corporation, Frequently 

Asked Questions, at 2 (Aug. 2013), available at

http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf.
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The U.S., Canada, and part of Mexico are divided up into 

eight reliability regional entities.124 These regional entities 

include Florida Reliability Coordinating Council (FRCC), Midwest 

Reliability Organization (MRO), Northeast Power 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).125 Regional entity members come from 

all segments of the electric industry.126 NERC delegates 

authority, with FERC approval, to these regional entities to 

enforce reliability standards, both national and regional 

reliability standards, and engage in other standards-related 

duties delegated to them by NERC.127 NERC ensures that there is a 

 

124 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.

125 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.

126 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.

127 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 
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consistency of application of delegated functions with 

appropriate regional flexibility.128 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/RTOs129, and other planning authorities 

also consider the reliability of the electric system. There are 

 

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. 

128 North American Electric Reliability Corporation, Frequently 

Asked Questions, at 5 (2013), available at 

http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf.

129 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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numerous remedies that can be utilized to solve a potential 

reliability problem, including long-term planning, transmission 

system upgrades, installation of new 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 

renewables such as wind, solar, and hydroelectric power. Coal 

provided the largest percentage of the fossil fuel generation.130

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.131 In 2013, fossil fuels supplied 67 

percent of U.S. electricity,132 but the amount of renewable 

 

130 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).

131 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).

132 U.S. Energy Information Administration, “Table 7.2b 

Electricity Net Generation: Electric Power Sector” data from 
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generation capacity continued to grow.133 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.134 Renewable 

electricity generation, including from large hydro-electric 

projects, grew from 8 percent to 13 percent over that time 

period.135 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 RE facilities.136 In 2015, the U.S. Energy 

 

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).

133 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 REsources: 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.

134 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).

135 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). 

136 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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Information Administration (EIA) projected the need for 28.4 GW 

of additional base load or intermediate load generation capacity 

through 2020.137 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 EEresources 

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. 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. 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 

 

137 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.
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distribution systems, some of which originated in the 1880s.”138

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.”139 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 

supplies of natural gas have dramatically increased. Natural gas 

net generation increased by approximately 32 percent between 

2005 and 2014.140 In 2014, natural gas accounted for 

 

138 American Society for Civil Engineers, 2013 Report Card for 

America’s Infrastructure (2013), available at

http://www.infrastructurereportcard.org/energy/.

139 American Society for Civil Engineers, 2013 Report Card for 

America’s Infrastructure (2013), available at

http://www.infrastructurereportcard.org/energy/.

140 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
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approximately 27 percent of net generation.141 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 2040.142 

Renewable sources of electric generation also have a 

history of meeting electricity demand in the U.S. and are 

expected to have an increasing role going forward. A series of 

energy crises provided the impetus for RE development in the 

early 1970s. The OPEC oil embargo in 1973 and 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 

 

http://www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=e

pmt_1_1 (last visited May 26, 2015).

141 Id.

142 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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facilities (QFs).143 QFs were either cogeneration facilities144 or 

small generation resources that use renewables such as wind, 

solar, biomass, geothermal, or hydroelectric power as their 

primary fuels.145 Through PURPA, Congress supported the 

development of more RE 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.146

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, up from 9 percent in 2005.147 In 2013, U.S. non-

 

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

Systems, IEEE Press, at 220-221 (2d ed. 2010).

144 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).

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

Systems, IEEE Press, at 220-221 (2d ed. 2010).

146 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). 

147 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.
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hydro RE capacity for the total electric power industry exceeded 

80,000 MW, reflecting a fivefold increase in just 15 years.148 In 

particular, there has been substantial growth in the wind and 

photovoltaic (PV) markets in the past decade. Since 2009, U.S. 

wind generation has tripled and solar generation has grown 

twenty-fold.149

The global market for RE is projected to grow to $460 

billion per year by 2030.150 RE growth is further encouraged by 

the significant amount of existing natural resources that can 

support RE production in the U.S.151 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.152 In the reference case, RE generation 

 

148 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/.

149 Energy Information Administration, Monthly Energy Review, May 

2015, Table 7.2b, available at

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.

150 “Global Renewable Energy Market Outlook.” Bloomberg New Energy 

Finance (Nov. 16, 2011), available at

http://bnef.com/WhitePapers/download/53.

151 Lopez et al., NREL, ‘‘U.S. Renewable Energy

Technical Potentials: A GIS-Based Analysis,’’ (July 2012).

152 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.
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increases by more than 70 percent from 2013 to 2040 and accounts 

for over one-third of new generation capacity.153

Price pressures caused by oil embargoes in the 1970s also 

brought the issues of conservation and EE to the forefront of 

U.S. energy policy.154 This trend continued in the early 1990s. 

EE has been utilized to meet energy demand to varying levels 

since that time. As of April 2014, 25 states155 have “enacted 

long-term (3+ years), binding energy savings targets, or energy 

 

153 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).

154 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.

155 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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efficiency resource standards (EERS).”156 Funding for EE programs 

has grown rapidly in recent years, with budgets for electric 

efficiency programs totaling $5.9 billion in 2012.157

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 

 

156 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.

157 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.158

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.159 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.160 Congress 

also established an energy conservation and RE reserve from 

which up to 300,000 allowances could be allocated for qualified 

energy conservation measures or qualified RE.161

The second phase, beginning in 2000, expanded coverage to 

more than 2,000 generating units and set a national cap at 8.90 

 

158 42 U.S.C. § 7651(b).

159 42 U.S.C. § 7651c (Table A).

160 42 U.S.C. § 7651c(b) and (d).

161 42 U.S.C. § 7651c(f) and (g).
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million tons.162 Generally, allowances were allocated at a rate 

of 1.2 lbs./mmBtu multiplied by the unit’s baseline and divided 

by 2000.163 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.164

The provisions of the EPA’s Acid Rain Program are 

implemented through permits issued under the EPA’s Title V 

Operating Permit Program.165 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.166

2. Transport rulemakings

 

162 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).

163 See 42 U.S.C. § 7651d.

164 42 U.S.C. § 7651o.

165 42 U.S.C. § 7651g.

166 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 

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). 
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CAA section 110(a)(2)(D)(i)(I), the “Good Neighbor 

Provision,” requires SIPs to prohibit emissions that “contribute 

significantly to nonattainment . . . or interfere with 

maintenance” of the NAAQS in any other state.167 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.168

In three major rulemakings — the NOx SIP Call,169 the Clean 

Air Interstate Rule (CAIR),170 and the Cross State Air Pollution 

Rule (CSAPR)171 — 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 

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 

 

167 42 U.S.C. § 7410(a)(2)(D)(i)(I).

168 EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584, 

1600–01 (2014) (citing 42 U.S.C. § 7410(c)). 

169 63 FR 57356 (Oct. 27, 1998).

170 70 FR 25162 (May 12, 2005).

171 76 FR 48208 (Aug. 8, 2011).
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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.172 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.173 

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.174

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 

 

172 63 FR at 57377–78. 

173 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.

174 Michigan v. EPA, 213 F.3d 663 (D.C. Cir. 2000).
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EGUs.”175 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.176 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.177

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 

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.178 In the same action establishing these 

emission reduction requirements, the EPA promulgated FIPs that 

subjected states to trading programs developed to achieve the 

 

175 70 FR at 25163.

176 70 FR at 25273–75; 71 FR 25328 (April 28, 2006).

177 531 F.3d 896, 917–22 (D.C. Cir. 2008), modified on rehearing 

550 F.3d 1176, 1178 (D.C. Cir. 2008). 

178 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.
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necessary reductions within each state.179 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.180 

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.181 Though CAMR was later vacated by the D.C. 

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).182 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 

 

179 76 FR at 48209–16.

180 EPA v. EME Homer City Generation, L.P., 134 S. Ct. 1584 

(2014).

181 See 70 FR 28606 (May 18, 2005).

182 New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008).
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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.183 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.”184 Based on this analysis, EPA determined that 

the BSER “refers to the combination of the cap-and-trade 

mechanism and the technology needed to achieve the chosen cap 

level.”185

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 

 

183 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.

184 70 FR 28606, at 28619.

185 70 FR 28606, at 28620. 
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Units.”186 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.”187

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 

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 

 

186 70 FR 28606, at 28621.

187 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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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 

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. 
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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.

5. Regional Haze Rule 

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.188 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 . . . .”189 One such measure that Congress deemed 

necessary to make reasonable progress was a requirement that 

certain older stationary sources that cause or contribute to 

 

188 42 U.S.C. § 7491(a)(1).

189 42 U.S.C. § 7491(b)(2).
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visibility impairment “procure, install, and operate, as 

expeditiously as practicable . . . the best available retrofit 

technology,” more commonly referred to as BART.190 When 

determining BART for large fossil-fuel fired utility power 

plants, Congress required states to adhere to guidelines to be 

promulgated by the EPA.191 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.192

In 1999, the EPA promulgated the Regional Haze Rule to 

satisfy Congress’ mandate that EPA promulgate regulations 

directing states to address visibility impairment.193 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.194 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 

 

190 42 U.S.C. § 7491(b)(2)(A).

191 42 U.S.C. § 7491(b)(2).

192 42 U.S.C. §§ 7410(c); 7491(b)(2)(A).

193 64 FR 35714 (July 1, 1999) (codified at 40 CFR 51.308-309).

194 40 CFR 51.308(e)(1) & (2).
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source-specific BART.195 In 2005, the EPA promulgated BART 

Guidelines to assist states in determining which sources are 

subject to BART and what emission limitations to impose at those 

sources.196

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.197 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.198

F. Congressional Awareness of Climate Change in the Context of 

the Clean Air Act Amendments199

 

195 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).

196 70 FR 39104 (July 6, 2005) (codified at 40 CFR pt. 51, app. 

Y).

197 See 40 CFR 51.308(d)(1)(i)(B), (f).

198 See 42 U.S.C. § 7491(b)(2); 40 CFR 51.308(d)(3).

199 The following discussion is not meant to be exhaustive. There 

are many other instances outside the context of the CAA, before 
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During its deliberations on the 1970 Clean Air Act 

Amendments, Congress learned that ongoing pollution, including 

from manmade carbon dioxide, could “threaten irreversible 

atmospheric and climatic changes.”200 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.”201 The CEQ’s 

First Annual Report, which was transmitted to Congress, devoted 

a chapter to “Man’s Inadvertent Modification of Weather and 

Climate.”202 Moreover, Charles Johnson, Jr., Administrator of the 

 

and after 1970, when Congress discussed or was presented with 

evidence on climate change.

200 Sen. Scott, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA 

Legis. Hist. at 349.

201 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.”).

202 Council on Environmental Quality, “The First Annual Report of 

the Council on Environmental Quality,” p. 93-104 (Aug. 1970)
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Consumer Protection and Environmental Health Service, testified 

before the House 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.”203 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.”204 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.”205

 

203 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.

204 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.

205 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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Scientific reports on climatic change continued to gain 

traction in Congress through the mid-1970s, including while 

Congress was considering the 1977 CAA Amendments. However, 

uncertainty continued as to whether the increased warming 

brought about by carbon dioxide emissions would be offset by 

cooling brought about by particulate emissions.206 Congress 

ordered, as part of the 1977 CAA Amendments, 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.”207

Between the 1977 and 1990 Clean Air Act Amendments, 

scientific uncertainty yielded to the predominant view that 

global warming “was likely to dominate on time scales that would 

 

206 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 

Pollution” into the record, which noted that “there is near 

unamity [sic] that carbon dioxide concentrations in the 

atmosphere are increasing rapidly.”).

207 “Clean Air Act Amendments of 1977,” § 125, 91 Stat. at 728.
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be significant to human societies.”208 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 GHGs -- from all sources subject to the newly 

enacted operating permit program under Title V.209 Although 

Congress did not require the EPA to take immediate action to 

address climate change, Congress did identify certain tools that 

were particularly helpful in addressing climate change in the 

utility power sector. The Senate report discussing the acid rain 

provisions of Title IV noted that some of the measures that 

would reduce coal-fired power plant emissions of the precursors 

to acid rain would also reduce those facilities’ emissions of 

CO2. 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.’ 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. 

Accordingly, new title IV shapes an acid rain 

reduction policy that encourages energy efficiency and 

 

208 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.

209 “Clean Air Act Amendments of 1990,” § 820, 104 Stat. at 2699.
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other policies aimed at controlling greenhouse 

gases.210

Similarly, Title IV provisions to encourage RE were justified 

because “renewables not only significantly curtail sulfur 

dioxide emissions, but they emit little or no nitrogen oxides 

and carbon dioxide”.211

G. International Agreements and Actions 

In this final rule, the U.S. is taking action to limit GHGs 

from one of its largest emission sources. Climate change is a 

global problem, and the U.S. is not alone in taking action to 

address it. The United Nations Framework Convention on Climate 

Change (UNFCCC)212 is the international treaty under which 

countries (called “Parties”) cooperatively consider what can be 

done to limit anthropogenic climate change213 and adapt to 

 

210 Sen. Chaffe, S. Debate on S. 1630 (Jan. 24, 1990), 1990 CAA

Legis. Hist. at 8662. 

211 Additional Views of Rep. Markey and Rep. Moorhead, H.R. Rep. 

No. 101-490, at 674 (May 17, 1990).

212 http://unfccc.int/2860.php

213 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 

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
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climate change impacts. Currently, there are 195 Parties to the 

UNFCCC, including the U.S. 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 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 GHG 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 

before December. In April 2015, the U.S.announced its commitment 

to reduce GHG emissions 26-28 percent below 2005 levels by 

2025.214

As Parties to both the UNFCCC and the Kyoto Protocol215, the 

European Union (EU) and member countries have taken aggressive 

action to reduce GHG emissions.216 EU initiatives to reduce GHG

emissions include the EU Emissions Trading System, legislation 

 

214 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.

215 http://unfccc.int/kyoto_protocol/items/2830.php.

216 http://ec.europa.eu/clima/policies/brief/eu/index_en.htm.
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to increase the adoption of RE sources, strengthened EE 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 EE. In March 2015, the EU announced its 

commitment to reduce domestic GHG emissions by at least 40% from 

1990 levels by 2030.

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 GHGs 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 
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deforestation rate in Brazil in 2014 was roughly 75 percent

below the average for 1996 to 2005.217 

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.

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 U.S.is contributing its share of the 

global effort that is needed to address climate change.218 This 

demonstration encourages other major economies to take on 

similar contributions, which is critical given the global impact 

 

217 http://www.nature.com/news/stopping-deforestation-battle-forthe-amazon-1.17223

218 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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of GHG 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 

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 

U.S. 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.

H. 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.”219 The Air Quality Act—which expanded 

 

219 Sen. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 1970 CAA 

Legis. Hist. at 224. 
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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.”220 In fact, “[o]ver 200 million tons of contaminants ... 

spilled into the air” each year.221 The 1970 CAA Amendments were 

designed to face this crisis “with urgency and in candor.”222

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 

 

220 Sen. Muskie, S. Consideration of H.R. Conf. Rep. No. 91-1783 

(Dec. 18, 1970), 1970 CAA Legis. Hist.pa at 123. 

221 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. 

222 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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effect on public health or welfare”.223 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 

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.224

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.225 For 

existing sources in a listed source category, CAA section 111(d) 

set out procedures for the establishment of federally 

 

223 “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).

224 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1680.

225 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1684.
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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”.226 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.227

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 112.228 That said, states, including Texas and New 

Jersey, levied “substantial criticisms” against the EPA for not 

moving rapidly enough.229 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 

 

226 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1685.

227 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1685.

228 H.R. Rep. No. 95-294, at 194 (May 12, 1977).

229 H.R. Rep. No. 95-294, at 194 (May 12, 1977).
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competitive industries,” and lastly “provide a check on the 

Administrator’s inaction or failure to control emissions 

adequately.”230

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.231

Despite significant changes to this definition in 1977, Congress 

reversed course in 1990 and largely reinstated the original 

definition.232 As presently defined, the term applies to the 

regulation of new and existing sources under CAA sections 111(b) 

and (d).233

 

230 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 

231 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1683. 

232 “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). 

233 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 
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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. 

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”.234 The House also 

proposed to prohibit the construction or operation of new 

sources of “extremely hazardous” pollutants.235 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 

 

in 1977 and the same term is used in both CAA sections 111(b) 

and (d). 

234 H.R. 17255, 91st Cong. § 5 (1970).

235 H.R. 17255, 91st Cong. § 5 (1970).
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available control technology, processes, operating methods, or 

other alternatives.”236 The Senate also would have authorized 

“national emission standards” for hazardous air pollution and 

other “selected air pollution agents.”237

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).238 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, 

 

236 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). 

237 S. 4358, 91st Cong. § 6 (1970).

238 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 112.239

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.”240

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 112.241 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 

 

239 See S. Rep. No. 91-1196, at 18 and 20 (Sept. 17, 1970).

240 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).

241 See “Clean Air Act Amendments of 1970,” § 12, 84 Stat. at 

1706.
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fuels, processes, and operating methods which will result in 

elimination or significant reduction of emissions.”242 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 1971.243 The first category listed was 

for fossil-fuel fired steam generators, for which EPA proposed 

and promulgated standards for particulate matter, SO2, and NOx.244

Several years later, the EPA proposed its implementing 

regulations for CAA section 111(d).245 These regulations were 

finalized in November 1975, and provided for the publication of 

 

242 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1679.

243 “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).

244 36 FR at 15704-706; and “Standards of Performance for New 

Stationary Sources,” 36 FR 24876, 24879 (Dec. 23, 1971).

245 See “State Plans for the Control of Existing Facilities,” 39 

FR 36102 (Oct. 7, 1974).
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emission guidelines.246 The first emission guidelines were 

proposed in May 1976 and finalized in March 1977.247

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.248 Most 

notably, an increase in coal use as a result of the oil crisis 

meant that “vigorous and effective control” of air emissions was 

 

246 See “State Plans for the Control of Certain Pollutants from 

Existing Facilities,” 40 FR 53340 (Nov. 17, 1975).

247 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)

248 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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“even more urgent.”249 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.250

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.251

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 

 

249 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. 

250 See “Clean Air Act Amendments of 1977,” Pub. L. 95-95, §§ 

127-129, 91 Stat. 685 (Aug. 7, 1977).

251 “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 697.
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system of continuous emission reduction.’”252 For fossil-fuel 

fired stationary sources, Congress further required a percentage 

reduction in emissions from the use of fuels.253 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.”254

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)”.255 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 

 

252 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).

253 “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 700.

254 “New Stationary Sources Performance Standards; Electric 

Utility Steam Generating Units,” 44 FR 33580, 33581-82 (June 11, 

1979).

255 H.R. Rep. No. 95-294, at 195 (May 12, 1977).
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reduction.”256 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.257

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.”258 Indeed, in 1988, 

President George Bush said that “‘progress has not come quickly 

enough and much remains to be done.’”259 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 

 

256 Sen. Muskie, S. Consideration of the H.R. Conf. Rep. No. 95-

564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353.

257 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).

258 H.R. Rep. No. 101-490, at 144 (May 17, 1990).

259 H.R. Rep. No. 101-490, at 144 (May 17, 1990).
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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 1977.260 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.261

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.262

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 

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 

 

260 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. 

261 “Clean Air Act Amendments of 1990,” § 403, 104 Stat. at 2631.

262 “Clean Air Act Amendments of 1990,” § 301, 104 Stat. at 2631.
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public health or welfare.”263 The EPA has listed more than 60 

stationary source categories under this provision.264 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.265

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 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. 

 

263 CAA section 111(b)(1)(A).

264 See 40 CFR 60 subparts Cb – OOOO.

265 CAA section 111(b)(1)(B), 111(a)(1).
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“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.”266 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.267 Once a state receives the 

EPA’s approval of its plan, the provisions in the plan become 

federally enforceable against the entity responsible for 

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, 

 

266 CAA section 111(d)(2)(A).

267 CAA section 111(d)(2)(A).
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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 

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 
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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 country268 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 

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. 

In these final emission guidelines, the term “state” 

 

268 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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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.

The EPA issued regulations implementing CAA section 111(d) 

in 1975,269 and has revised them in the years since.270 (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.271 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,272

and the EPA must take final action on the state plans within 4 

months of the due date for those plans,273 although the EPA has 

authority to extend those deadlines.274 In this rulemaking, the 

 

269 “State Plans for the Control of Certain Pollutants from

Existing Facilities,” 40 FR 53340 (Nov. 17, 1975).

270 The most recent amendment was in 77 FR 9304 (Feb. 16, 2012).

271 40 CFR 60.22. In the 1975 rulemaking, the EPA explained that 

it used the term “emission 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 FR at 

53343.

272 40 CFR 60.23(a)(1).

273 40 CFR 60.27(b).

274 See 40 CFR 60.27(a).
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EPA is following the requirements of the implementing 

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)).275 In addition, the agency has 

regulated additional pollutants under CAA section 111(d) in 

conjunction with CAA section 129.276 The agency has not 

previously regulated CO2 or any other GHGs under CAA section 

111(d). 

The EPA’s previous CAA section 111(d) actions were 

necessarily geared toward the pollutants and industries 

regulated. Similarly, in this rulemaking, in defining CAA 

 

275 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). 

276 See, e.g., “Standards of Performance for New Stationary 

Sources and Emission Guidelines for Existing Sources: Sewage 

Sludge Incineration Units, Final Rule,” 76 FR 15372 (Mar. 21, 

2011). 
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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.277

 

277 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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In this action, the EPA is promulgating emission guidelines 

for states to follow in developing their CAA section 111(d) 

plans to reduce emissions of CO2 from the utility power sector. 

J. 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 GHG emissions 

from existing fossil fuel-fired electric generating units 

(EGUs). Specifically, the EPA proposed rate-based goals for 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-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 RE, 

demand-side EE and other new low- or zero-emitting electricity 

generation across international boundaries in a state plan.
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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.

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). 

K. Stakeholder Outreach and Consultations 

Following the direction in the Presidential Memorandum to 

the Administrator (June 25, 2013),278 the EPA engaged in

extensive and vigorous outreach to stakeholders and the general 

 

278 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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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.

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,279 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,280

teleconferences and meetings held all across the country. 

 

279 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. 

280 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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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.

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.
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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 

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 
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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 

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 
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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 

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 
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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 

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 this 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 EE and RE. 

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. 
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The EPA plans to use an integrated project team to solicit 

stakeholder input on the system during development. The team 

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, 

EE and RE 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 

additional outreach for the supplemental proposal included 
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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 RE 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 areas of Indian 

country. Additional detail regarding the EPA’s outreach to 
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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 

also met with energy industries such as coal and natural gas 

interests, as well as companies that offer new technology to 
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prevent or reduce carbon pollution, including companies that 

have expertise in RE and EE. 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). 

7. Electricity grid operators

The EPA had a number of conversations with the ISOs and 

RTOs to discuss the rule and issues related to grid operations 

and reliability. EPA staff met with the ISO/RTO Council on 
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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 

vulnerable 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 

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.
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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 EE and lowcost 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 

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 
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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. 

The purpose of this rule is to substantially reduce 

emissions of CO2, a key contributor to climate change, which 

adversely and disproportionately affects vulnerable and 

disadvantaged communities in the U.S. and around 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 
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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 

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
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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 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 EE. 

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 
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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.

L. 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 
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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 

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 GHG 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 
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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 the following 

three sets of measures or building blocks: 

1. Improving heat rate at affected coal-fired steam 

EGUs.

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 RE generating capacity 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 fuel-
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fired 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 

units, we are finalizing a performance rate of 1,305 lb CO2/MWh. 

For stationary combustion turbines, we are finalizing a 

performance rate of 771 lb CO2/MWh. 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.

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 approved by 

the EPA pursuant to 40 CFR 49.9 as eligible to develop and 
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implement a CAA section 111(d) plan..281Because 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” 

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 

 

281 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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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 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 

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 
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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. 

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 the state’s CO2 interim period goal (for 

2022-2029), interim steps (interim step goal 1 for 2022-
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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 goal282

• State recordkeeping and reporting requirements

• Certification of hearing on state plan

• Supporting documentation

Also, in all state plans, as part of the supporting 

documentation, a state must include a description of how they 

considered reliability in developing its state plan. 

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. 

 

282 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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In addition to these requirements, each state plan must follow 

the EPA implementing regulations at 40 CFR 60.23.

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 

negative declaration submitted to the EPA by September 6, 2016. 

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

area of Indian country,283 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 implementation of its approved state plan, each 

state must demonstrate to the EPA that its affected EGUs are 

 

283 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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meeting the interim and final performance requirements included 

in this final rule through monitoring and reporting 

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.284 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 

 

284 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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standards of performance for CO2 emissions from new fossil fuelfired 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;285 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-

 

285 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 environmental impacts or 

impose adverse energy requirements, and they are each wellestablished among affected EGUs. It should be emphasized that 

these measures are consistent with current trends in the 

electricity sector. 

Building blocks 2 and 3 may be implemented through a set of 

measures, including reduced generation from the fossil fuelfired EGUs. These measures do not, however, reduce the amount of 

electricity that can be sold or that 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 

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 cost-
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effective. Because trading facilitates implementation of the 

building blocks and may help to optimize cost-effectiveness, 

trading is a method of implementing the BSER as well.

As a result, an affected EGU has a set of choices for 

achieving its emission standards. For example, an affected coalfired 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 RE assets to purchasing 

ERCs 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. The 

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 coal-fired steam generating unit may 

implement building block 1 measures, purchase mass-based 

emission allowances from other 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. 
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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 

on affected EGUs, result in the achievement of the applicable 

performance 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 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 

provide for implementation and enforcement of the standards of 

performance. 
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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 

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 
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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 provides additional 

information about certain issues 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 
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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).286 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 

CAA section 111(b) rule that 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 

 

286 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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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 Section 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: 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, 16029-32 (March 29, 

2005).

In June 2014, the EPA presented this previous 

interpretation as part of the proposal 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 
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-- including some industry and state commenters that had 

previously endorsed the EPA’s interpretation of the Section 112 

Exclusion in other contexts287 -- argued that the EPA’s 2005 

interpretation was in error because it allowed 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 

 

287 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 Respondent-Intervernors, and 

State Amicus, filed May 18, 2007, at 25. 
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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 the context presented by this 

rule: that the Section 112 Exclusion does not bar the regulation 

under CAA section 111(d) of non-HAP from a source category, 

regardless of whether that source category is 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. 

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 

health or welfare but are not or cannot be controlled under 

sections 108-110 or 112.” 40 FR 53340 (Nov. 17, 1975). 

Six “criteria” pollutants are regulated under sections 108-

110. These are pollutants that the Administrator has concluded 
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“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 HAP, and then establish emissions 

standards for (HAP) emitted by sources within each 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. Section 111 

has two main components. First, section 111(b) requires the EPA 

to promulgate federal “standards of performance” addressing new

stationary sources that cause or contribute significantly to 
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“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 

source emissions that pose any significant danger to public 

health or welfare.” S. Rep. No. 91-1196, at 20 (1970). 288 

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) is intended to cover 

pollutants that are not regulated under either the criteria 

pollutant/NAAQS provisions or the HAP regulated under section 

112. Prior to 1990, this limitation was laid out in plain 

 

288 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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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 

not covered by the criteria pollutant provisions or 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 

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 
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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 HAP; set criteria for listing 

“source categories” of such pollutants; and required the EPA to 

establish standards for each listed source category’s hazardous 

pollutant emissions. 42 U.S.C. § 7412(b), (c) and (d). In the 

course of overhauling the regulation of (HAP) under section 112, 

Congress needed to edit section 111(d)’s reference to section 

112(b)(1)(A), which was to be eliminated as part of the 

revisions to section 112. 

To address the obsolete cross-reference to section 

7412(b)(1)(A), Congress passed two differing amendments – one 

from the Senate and one from the House – 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, § 
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108(g), 104 Stat. 2399, 2467 (1990).289 Both amendments were 

enacted into law, and thus both are part of the current CAA. To 

determine how 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

 

289 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 

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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Unlike the ambiguous amendment to CAA section 111(d) in the 

House amendment (discussed below), the Senate amendment is 

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 

section 111(d) regulation of CO2 emissions from power plants 

notwithstanding that power plants are also regulated for HAP 

under CAA section 112.

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 
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law as part of the 1990 Amendments, as shown in the Statutes at 

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 

instead 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 

vastly different bill (S.1630) at the end of 1989. See S. 1630, 
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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)”). 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 crossreference 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 amendment

a. The 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 
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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. United 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 

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 
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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 

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 & 
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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. 

First, the text of the House-amended version of CAA section 

111(d) could be read literally as authorizing the regulation of 

any pollutant that is not a criteria pollutant. This reading 

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, a literal reading of the 

language of section 111(d) provides that the Administrator may 
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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 

promulgate section 111(d) regulations for CO2 from power plants, 

the result would be that CO2 from power plants coule be regulated 

under section 111(b) because air quality criteria have not been 

issued for CO2 and therefore whether CO2 or power plants are 

regulated under section 112 would be irrelevant. This reading, 

however, is not a reasonable reading of the statute because, 

among other reasons, it gives little or no meaning to the 

limitation covering (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 reading of CAA section 111(d) as revised by the 

House amendment focuses 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 
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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” prescribe 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 as providing for the regulation of 

emissions of pollutants if they are emitted from a source 

category that is regulated under CAA section 112. Like the first 

reading discussed above, this reading would authorize the 

regulation of CO2 emissions from existing power plants under CAA 

section 111(d). But, this second reading is not reasonable 

because it would 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 Congress’s intent that CAA section 

111(d) regulation fill the gap between the other programs by 

covering pollutants that the other programs do not, but not 

duplicate the regulation of pollutants that the other programs 

cover.

If 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 
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“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. As 

the Supreme Court has explained in the context of 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.” 

Under this reading, and assuming the phrase “a source 

category” is read to mean the particular source category, the 

House amendment would preclude the regulation under CAA section 

111(d) of a specific source category for any pollutant if that 
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source category has been regulated for any HAP under CAA section 

112.290 The effect of 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 (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 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, 

(HAP) and the other pollutants that fall outside of those two 

programs and frustrate the role that section 111 is intended to 

 

290 “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 

would be barred from CAA 111(d) regulation under this 

interpretation.
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play.291 Specifically, under this interpretation, the EPA could 

not regulate a source category’s emissions of HAP under CAA 

section 112, and then promulgate regulations for other

pollutants from that source category under CAA section 111(d).292

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 subcategories 

of major sources and area [aka, non-major] sources” of HAP and 

then establish CAA section 112 standards for those categories 

 

291 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). 

292 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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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, this reading would 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 as Congress intended.293 In short, it is not reasonable to 

interpret the Section 112 Exclusion in section 111(d) to mean 

that the existence of CAA section 112 standards covering 

hazardous pollutants from a source category would entirely 

 

293 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 

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.
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eliminate regulation of non-hazardous emissions from that source 

category under section 111(d).294

b. 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 concluded is the 

best, and sole reasonable, interpretation of the House amendment 

as it applies to the issue here.

The EPA’s interpretation of the House amendment as applied 

to the 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 interpretation discussed above) but also 

 

294 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 

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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recognizes that the phrase “regulated under section 112” refers 

only to the regulation of HAP emissions. In other words, the 

EPA’s interpretation recognizes that source categories 

“regulated under section 112” are not regulated by CAA section 

112 with 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 

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). 

There are a number of reasons why the EPA’s interpretation 

is reasonable and avoids the issues discussed above.

First, the 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 categories. 

The other text in subsections 111(d)(1)(A)(i) and (ii) modify 

the phrase “any air pollutant.” Thus, reading the Section 112 
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Exclusion to also address the question of what air pollutants 

may be regulated under CAA section 111(d) is consistent with the 

overall structure and focus of CAA section 111(d)(1)(A). 

Second, the EPA’s interpretation furthers – rather than 

undermines – the purpose of CAA section 111(d) within the longstanding structure of the CAA. That is, this 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)”) 

Third, by avoiding the creation of gaps in the statutory 

structure, the 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 
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pollutants, under more programs, more quickly.295 Conversely, 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.

Fourth, when applied in the context of this rule, the EPA’s 

interpretation of the House amendment is consistent with the 

Senate amendment. Thus, this interpretation avoids creating a 

conflict within the statute. See discussion above of Scialabba, 

134 S. Ct. 2191 at 2220 (citing and quoting, among other 

authorities, A. Scalia & B. Garner, Reading Law: The 

 

295 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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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 this interpretation of the House amendment is 

applied in the context of this rule, the 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. 

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) 

does not foreclose the regulation of non-HAP from a source 

category regardless of whether that source category is also 

regulated under CAA section 112. As applied here, the EPA has 

the authority to promulgate 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
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In a separate, concurrent action, the EPA is also 

finalizing a CAA section 111(b) rulemaking that regulates CO2

emissions from new, modified, and reconstructed EGUs. The 

promulgation of these standards 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 

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 
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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 

that undertake new construction, modifications, or 

reconstructions. 

The EPA is finalizing a 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).296

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 

 

296 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 FR 9905 (March 

12, 1996).
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commenced construction as of January 8, 2014,297 and that meets 

the following criteria, which differ depending on the type of 

unit. To be an affected EGU, 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 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 

 

297 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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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 

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 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 
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combustion turbines that are not capable of combusting natural 

gas (i.e., not connected to a natural gas pipeline); (5) 

combined heat and power units 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 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) municipal waste combustor unit subject to subpart Eb of Part 

60; or (8) commercial or industrial solid waste incineration 

units that are 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 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 non-fossil units, 
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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 the building blocks 

would result 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. 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 
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single-digit percentage reduction in combustion turbine heat 

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 could not be applied to simple cycle 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 result 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.

Additionally, 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 location, 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 including all GHG 

emission guidelines for the affected sources – fossil fuel–fired 
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electric utility steam generating units, as well as stationary 

combustion turbines -- in that newly created subpart.298

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 listing 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 the 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 

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 

 

298 The EPA is not codifying any of the requirements of this 

rulemaking in subparts Da or KKKK.
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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 

rule revise either of the two source categories – fossil fuel–

fired electric utility steam generating units 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 
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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 EEto 

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 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 
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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 unique 

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 EGUs 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. 

The BSER also encompasses a variety of measures or actions that 

individual affected EGUs could take to implement the 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 approaches, where the state-established 

standards of performance to which sources are subject 

incorporate such approaches, and (iii) reduction of highercarbon generation. 
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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 mindful 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 emissionsreducing actions not included in the BSER but nevertheless 

available to help with compliance, ensure that those emission 

limitations are achievable by individual affected EGUs as well. 

The final BSER incorporates certain changes from the 

proposed rule, reflecting the EPA’s consideration of comments 

responding 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 demandside EE and through nuclear generation; a revised approach to 
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determination of emission reductions achievable through 

increased RE generation; 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 

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 method 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 

reformulation of the emission limitations as uniform CO2 emission 
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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 

building blocks included in the final BSER. Further information 

can be found in 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 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. 
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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, as applied to the two subcategories of fossil steam 

units and combustion turbines. In section V.A.5., we explain the 

specific actions that individual affected EGUs in the two 

subcategories may take to implement the building blocks and 

thereby achieve the EPA-identified source subcategory-specific 

emission performance rates 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 EGUs 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 requirements for standards of 

performance under CAA section 111(d)(1) and (a)(1). We based our 
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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 fossil fuelfired 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.299

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.300

b. CAA requirements and court interpretation.301 Section 

 

299 79 FR 1430, 1462 (January 8, 2014).

300 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.

301 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 
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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 

 

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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(taking into account the cost of such reduction) the 

Administrator has determined has been adequately 

demonstrated.302

The EPA’s approach in this rulemaking is to determine the 

BSER on a source subcategory-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 emission performance rates, and they must be achievable 

by the source subcategory 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.”303 A state has broad discretion in doing so. CAA 

section 111(d)(1) requires the EPA’s regulations to “permit the 

State in applying a standard of performance to any particular 

source ... to take into consideration, among other factors, the 

remaining useful life of the ... source....”304 In addition, 

 

302 40 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). 

303 40 CFR 60.24(b)(3).

304 The EPA’s regulations, promulgated prior to enactment of the 

“remaining useful life” provision of section 111(d)(1), provide: 
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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.305 Thus, for any particular source, a state may apply 

a standard of performance that is either more stringent or less 

stringent than the 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. The states must include the standards of 

performance in their state plans and submit the plans to the EPA 

for review.306 Under CAA section 111(d)(2)(A), the EPA approves 

state plans as long as they are “satisfactory.” 

As noted in the January 2014 proposal and discussed in more 

detail above under section II.G, Congress first included the 

 

“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.

305 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.

306 40 CFR 60.23.
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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.307 In addition, although the D.C. 

 

307 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 

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 
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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 2011,308 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 

“best,” “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”309 reduced and the role of 

 

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.

308 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).

309 See Sierra Club v. Costle, 657 F.2d 298, 326 (D.C. Cir. 

1981). 
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“technological innovation.”310 The Court has emphasized that the 

EPA has discretion in weighing those various factors.311, 312

Our overall approach to determining the BSER and emission 

guidelines, which incorporates the various elements, is as 

follows: In developing an emission guideline, we 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” 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, energy requirements, and, in the 

alternative, the advancement of technology (that is, we apply a 

 

310 See Sierra Club v. Costle, 657 F.2d at 347.

311 See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 

Cir. 1999).

312 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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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 rates -- based on the BSER.313 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 

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 

 

313 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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is done; an organized scheme or method; and a group of 

interacting, interrelated, or interdependent elements.314 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 

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 

 

314 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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“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.”315 It does not mean that the system “must be 

in actual routine use somewhere.”316 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.”317 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.”318 Ultimately, the analysis “is partially dependent on 

‘lead time,’” that is, “the time in which the technology will 

have to be available.”319 Unlike for CAA section 111(b) standards 

that are applicable immediately after the effective date of 

 

315 Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. 

Cir. 1973), cert. denied, 416 U.S. 969 (1974).

316 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).

317 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted).

318 Sierra Club v. Costle, 657 F.2d 298, 364 (1981).

319 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. 

Cir. 1973) (citations omitted).
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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 

into account “the cost of achieving” the required emission 

reductions. As described in the January 2014 proposal,320 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,”321 “greater than the industry could bear and 

survive,”322 “excessive,”323 or “unreasonable.”324 These 

formulations appear to be synonymous, and for convenience, in 

this rulemaking, we will use reasonableness as the standard, so 

 

320 79 FR 1430, 1464 (January 8, 2014).

321 Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 

1999).

322 Portland Cement Ass’n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 

1975).

323 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).

324 Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
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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 

costs are unreasonable.325, 326

The D.C. Circuit has repeatedly upheld the EPA’s 

consideration of cost in reviewing standards of performance. In 

 

325 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.

326 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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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.”327 See Essex 

Chemical Corp. v. Ruckelshaus, 486 F.2d 427, 440 (D.C. Cir. 

1973);328 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”).329

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 

 

327 1977 House Committee Report at 184.

328 The costs for these standards were described in the 

rulemakings. See 36 FR 24876 (December 23, 1971), 37 FR 5767, 

5769 (March 21, 1972).

329 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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into account “any nonair quality health and environmental 

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.330

(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. 

 

330 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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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”).331 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 

determining the BSER. 

 

331 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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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.332 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 111.333

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 

 

332 79 FR 1430, 1465 (January 8, 2014) (citing Sierra Club v. 

Costle, 657 F.2d at 351).

333 Sierra Club v. Costle, 657 F.2d at 331 (citations omitted) 

(citing legislative history).
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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.334

In this rule, the EPA is considering costs and energy 

implications on the basis of (i) their source-specific 

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 

emissions that reflect the degree of emission limitation that is 

“achievable” through the application of the BSER. According to 

the D.C. Circuit, a standard of performance is “achievable” if a 

technology can reasonably be projected to be available to an 

 

334 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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individual source at the time it is constructed that will allow 

it to meet the standard.335 Moreover, according to the Court, 

”[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.”336 To be achievable, a standard “must be 

capable of being met under most adverse conditions which can 

reasonably be expected to recur and which are not or cannot be 

taken into account in determining the ‘costs’ of compliance.”337

To show a standard is achievable, the EPA must “(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.”338

 

335 Sierra Club v. Costle, 657 F.2d 298, 364, n. 276 (D.C. Cir. 

1981).

336 Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 (D.C. 

Cir. 1973), cert. denied, 416 U.S. 969 (1974).

337 Nat’l Lime Ass’n v. EPA, 627 F.2d 416, 433, n.46 (D.C. Cir. 

1980).

338 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 
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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 regulations339 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. 

The 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. 

As indicated in the proposed rulemakings for this rule and 

 

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).

339 40 CFR 60.21(e).
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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. 

(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.340 In addition, the Court’s interpretation finds firm 

 

340 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.”).
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support in the legislative history.341 The legislative history 

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);342 (ii) the 

expanded use of the best demonstrated technology;343 and (iii) 

the development of emerging technology.344 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 

 

341 See S. Rep. No. 91-1196 at 16 (1970) (“Standards of 

performance should provide an incentive for industries to work 

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”).

342 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”).

343 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”).

344 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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technological innovation may be considered, and it is reasonable 

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 measures identified in this rule as the BSER even 

without considering the factor of incentivizing technological 

innovation or development. 

(6) 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,”345 and emphasized that “[t]he text gives 

the EPA broad discretion to weigh different factors in setting 

the standard.”346 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 

 

345 Sierra Club v. Costle, 657 F.2d at 319. 

346 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 111.347

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 

subcategorize. The EPA interprets this provision to authorize 

the EPA to exercise discretion as to whether and, if so, how to 

 

347 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. 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.348

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 

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

 

348 40 CFR 60.22(b)(5).
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formulating the guidelines. In order to establish the BSER 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, and have identified the BSER for each 

subcategory as the measures 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.349 After 

identifying the BSER in this manner, the EPA determines the 

performance levels –- in this case, the CO2 emission performance 

rates –- for the steam generators and for the combustion 

turbines. 

In establishing the BSER the 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 mass-based limit, and that meet the 

 

349 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, 

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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other requirements for the BSER. These actions implement the 

BSER and may therefore be understood as part of the BSER. 

An example illustrating the relationship between the 

measures determined to constitute the BSER for the source 

category and the actions that may be undertaken by individual 

sources that are therefore also part of the BSER is the 

substitution of zero-emitting generation for CO2-emitting 

generation. This measure involves two distinct actions: 

increasing the amount of zero-emitting generation and reducing 

the amount of CO2-emitting generation. From the perspective of 

the source category, the two actions are halves of a single 

balanced endeavor, but from the 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: in this 

rule, the EPA determined the BSER, and applied it to the 

category of affected EGUs to determine the performance levels –-

that is, the CO2 emission performance rates -- for steam 

generators and for combustion turbines. States must impose 

standards of performance on their sources that implement the CO2
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emission performance rates, or, as an alternative method of 

compliance, in total, achieve the equivalent 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.350 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 

convert the CO2 emission performance rates into 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 criteria of reasonable cost 

and other BSER criteria, the BSER assures that there is at least 

one pathway –- the CO2 emission performance rates -- 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.

 

350 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.351 The EPA is identifying the BSER as 

a well-established set of measures that 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 EGUs’ CO2 emissions, and that are appropriate for 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) improving heat rate at 

existing coal-fired steam EGUs on average by a specified 

percentage (building 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-emitting 

RE generating capacity for reduced generation at existing fossil 

 

351 Other sections in this preamble describe how EPA calculated 

the CO2 emission performance rates based on the BSER.
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fuel-fired EGUs in specified amounts (building block 3). It 

should be noted that building block 2 incorporates reduced 

generation from steam EGUs and building block 3 incorporates 

reduced generation from all fossil fuel-fired EGUs.352 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 

cross-investment by individual affected EGUs in emission rate 

improvements or emission reduction activities at other locations 

on the interconnected electricity system. The range of 

mechanisms includes bilateral investment of various kinds; the 

issuance and acquisition of ERCsrepresenting the emissionsreducing effects of specific activities, where available under 

state plans; and more general emissions trading using rate-based 

credits or mass-based allowances (as discussed in section 

V.A.2.f. below), where the affected EGUs are operating under 

standards of performance that incorporate emissions trading.353

The set of measures identified as the BSER for the source 

category encompasses a menu of actions that are part of the BSER 

and that individual affected EGUs may implement in different 

 

352 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.

353 Conditions for the use of these mechanisms under various 

state plans are discussed in section VIII.
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amounts and combinations in order to achieve their emission 

limits at reasonable cost. This menu includes actions that: (i) 

affected 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 zero-carbon 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 implement by means of purchasing ratebased emission credits or mass-based emission allowances from 

other affected EGUs, since the effect of the purchase would be 

the same as achieving the other listed actions through direct 

means.354

Importantly, 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 EE, cofiring with natural gas (for coal-fired steam EGUs), and 

investment in new generating units using low- or zero-carbon 

 

354 Again, conditions for the use of these mechanisms under 

various state plans are discussed in section VIII.
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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, 

but the EPA is also refining that analysis as 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. 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.355 In assessing the 

 

355 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

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 
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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.”356

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.”357 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.358

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 

 

the SO2 standard for fossil-fuel-fired steam generators should be 

revised.” Id. at 33587-33588.

356 44 FR 33580, 33582 (June 11, 1979).

357 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. 

358 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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to the level achievable through application of the BSER.359 EPA’s 

identification of this BSER was critically influenced by the 

“unique emission pattern of landfills.”360 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.361 In recognition of 

this salient and unique characteristic of landfills, the EPA set 

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.362 The EPA acknowledged that for some 

landfills, it could take 50 to 100 years for emissions to drop 

below the cutoff.363

 

359 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.

360 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”).

361 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).

362 61 FR 9905, 9907–08.

363 61 FR 9905, 9908.
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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 

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 
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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.”364 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 

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.365 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 

 

364 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).

365 These trends are discussed in more detail in sections V.D. 

and V.E. below.
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increases.366 A survey of integrated resource plans (IRPs), 

included in the docket, shows that fossil fuel-fired EGUs are 

taking actions to reduce emissions of both non-GHG air 

pollutants and GHGs.367 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 RE resources in their 

planning. In addition, some fossil fuel-fired EGUs are using 

those measures to replace their higher-emitting generation. Some 

fossil fuel-fired generators appear to be reducing their higheremitting generation without fully replacing it themselves. These 

measures in aggregate result in the replacement of higheremitting 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) 

 

366 Demand-side energy efficiency measures have also increased, 

and the projected future trends are for continued increase. 

367 See memo entitled “Review of Electric Utility Integrated 

Resource Plans” (May 7, 2015) available in the docket.
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established in more than 25 states.368 They also include marketbased initiatives, such as 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 

to reduce SO2 and NOX, the MATS program to reduce mercury and air 

toxic emissions, and the CSAPR program to reduce SO2 and NOX.369

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 generation shifts 

between fossil fuel-fired EGUs and RE generation –- also reduces 

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

 

368 See 79 FR 34848-34850.

369 Many of these programs are discussed in section II. 
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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 

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 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 approaches 

to achieve the standards of performance established in those 

plans. In short, as discussed in more detail in section V.A.2.f. 

below, it is entirely feasible for states to establish standards 
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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 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.” Further reinforcing our conclusion that reliance 

on trading is appropriate is the extensive interest in using 
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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 unique characteristics of CO2 pollution and the unique, 

interconnected and interdependent manner in 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: measures 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 RE, for 

generation from fossil fuel-fired units; and (iv) increase 

demand-side EE to avoid generation from fossil fuel-fired units. 

In the proposal, we described our evaluations of various 
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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 EE, should not be 

included in the BSER in these guidelines. 

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 zeroemitting sources) may occur through several different actions 

from the perspective of an individual source, all of which are 

equivalent from the perspective of the source category as a 

whole. First, a higher-emitting 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 
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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 investments in lower- or zero-emitting generation. In 

addition, for measures in all of the categories, multiple 

mechanisms exist by which an individual affected EGU 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. 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 for the sources 

that will be operating subject to those standards of 

performance. As part of the EPA’s emission guidelines in this 

rule, and based on the BSER, the EPA is identifying CO2 emission 
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performance rates 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 the 

performance rates into goals for each state. The state, in turn, 

has 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. 

Each 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 that simply reflect the respective CO2 emission 

performance rates for those subcategories 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 
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requires. In addition –- and most importantly for purposes of 

describing the BSER -- a state may set standards of performance 

as mass limits (e.g., tons of CO2 per year) rather than as 

emission rates (e.g., lbs of CO2 per MWh). Moreover, a state may 

make the limits tradable (subject to conditions described in 

section VIII below), whether the limits are rate-based or massbased. 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 as well as what specific nonBSER 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 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 zeroemitting 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 
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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. We now discuss the 

evaluation of potential measures for inclusion in the BSER for 

the source category as 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 

include 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. In this 

final rule, the EPA concludes that those measures do qualify as 

a component of the BSER. However, as described in section V.C. 

below, based on responsive comments and further evaluation, the 

EPA 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 
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the emission reductions available from these measures on a 

nationwide basis as in the proposal, the EPA has quantified the 

emission reductions achievable through building 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. As a result of these refinements, the EPA is 

identifying the heat rate improvements achievable by coal-fired 

steam EGUs as 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 
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state approaches to setting standards of performance, emissions 

trading approaches could be used as mechanisms through which one 

affected EGU could invest in heat rate improvements at another 

EGU. We note this aspect below in describing the actions an 

individual 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, except that they lead to only small 

emission reductions for the source category.370 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 

 

370 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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resulting from the application of these measures is too small 

for these measures to be the BSER by themselves for this source 

category. 

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.371 The EPA also considered implementation of 

carbon capture and storage (CCS).372 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 U.S. and in foreign nations 

are already using to reduce their CO2 emissions. 

 

371 The EPA further addressed co-firing in the October 30, 2014 

Notice of Data Availability. 79 FR 64549-51.

372 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 

RE generating units. 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.373

The 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 

 

373 Many EGUs would also rely on demand-side energy efficiency 

measures.
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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 

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 
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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. 

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 determine the BSER that meets the expectations and 

requirements of the CAA, including the achievement of meaningful 

reductions of CO2, the EPA turned next 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 with 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.
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It bears reiterating that the extent to which the 

operations of individual affected EGUs are integrated with 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. This physical 

interconnectedness exists to serve a 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 
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individual EGU. Likewise, when incorporated into standards of 

performance, emissions trading mechanisms may be readily used 

for implementing these building blocks. We discuss these aspects 

below in describing the actions that individual sources may take 

to implement the building blocks. 

(a) Substituting generation from lower-emitting affected 

EGUs for reduced generation from higher-emitting affected EGUs. 

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 
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(based on nameplate capacity) for NGCC units was feasible and 

should be a component of the BSER.

As 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 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. In 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. We 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 
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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 

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. 

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 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 
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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 

proposed to include replacement of defined quantities of fossil 

generation by RE generation in the BSER.

The 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 
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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 

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 capital-intensive investments that require 

substantial lead times. By comparison, investments in new RE 

generating capacity are 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. We view these factors as distinguishing the underconstruction nuclear units from RE generating capacity, 

indicating that the new nuclear capacity is likely of higher 

cost and therefore less appropriate for inclusion in the BSER.

Accordingly, as described in section V.A.3., the EPA is not 
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finalizing increased generation from under-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 

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 
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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 

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 
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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. 

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 
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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 EE 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 EE. When demandside EE 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. 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 EE programs are 

increasing. We proposed to include avoidance of defined 

quantities of fossil fuel-fired generation through increased 

demand-side EE as a component of the BSER (proposed building 

block 4). However, we also took comment on which building blocks 
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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 EE 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.B.3.c.(8) below, we are not 

finalizing the proposal to include avoided generation achieved 

through demand-side EE as a component of the BSER. However, we 

note that most commenters also supported the use of demand-side 

EE for compliance whether or not it is used in determining the 

BSER, and we are allowing demand-side EE 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 EE.)

(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 
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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 provides greater assurance of the 

achievability of the BSER for the source category and for 

individual sources. We believe this approach is permissible 

under the CAA. Another aspect of our methodology for computing 

the CO2 emission performance rates, further described in section 

V.A.3.f. and section VI, is that the CO2 emission performance 

rate 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).374 This aspect of our 

methodology not only ensures that the nationwide CO2 emission 

performance rates are achievable by affected EGUs in all three 

interconnections but also provides additional headroom within 

 

374 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.
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the BSER for affected EGUs in the two interconnections that did 

not set the CO2 emission performance rates ultimately used. 

Additional headroom within the BSER is available through the use 

of emissions trading approaches, because the final rule does not 

limit the use of these mechanisms to sources within the same 

interconnections. 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 multistate approaches, the guidelines include mechanisms for 

implementing standards of performance that incorporate 

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.)

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 
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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 RE 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 building blocks 2 and 3 also 

meet the criteria for the BSER in combination with one another 

and with building block 1, as described below. 

e. Actions that individual affected EGUs could take to apply or 

implement the building blocks. We now turn to a summary of 

measures or actions that individual 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 for the source category as a whole. As 
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discussed in section V.C., the record makes clear that coalfired steam EGUs can make, and have made, heat rate improvements 

to a greater or lesser degree, resulting in reductions in CO2

emissions. The resulting improvement in an EGU’s CO2 emission 

rate would help the EGU achieve an emission limit imposed in the 

form of an emission rate. If the EGU’s emission limit is imposed 

in the form of a mass standard, the heat rate improvement would 

also lower the EGU’s mass emissions provided that the EGU held 

the amount of its generation constant or increased its 

generation by a smaller percentage than the efficiency 

improvement. Under a mass-based standard that incorporates 

emission trading, an EGU that improves its heat rate 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 individual 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. The affected EGUs 

can: (a) invest in lower- or zero-emitting generation, which 

will lead to reductions in higher-emitting generation at other 

units in the integrated system; (b) reduce their generation, 
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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 incentivize 

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. 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 acquire the CO2-reducing effects of 

that increased generation in 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 RE generating capacity and acquire the CO2-reducing effects 

of that increased generation. Alternatively, an owner/operator 
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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, it would be reasonable for state plans to 

authorize affected EGUs to use an approved and validated 

instrument such as an “emission rate credit” (ERC) representing 

the emissions-reducing benefit of the investment.375

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 perspective of the 

overall source category. Thus, a source could achieve a standard 

of performance identical to the applicable CO2 emission 

performance rate in the EPA emission guidelines, through 

implementation of the actions described above for building 

blocks 2 and 3, along with the actions described further above 

for building block 1. 

The EPA anticipates that in instances where section 111(d) 

plans provide for the use of instruments such as ERCs as a 

mechanism to facilitate use of these measures, organized markets 

 

375 Criteria for issuance of valid ERCs and for tracking credits 

after issuance are discussed in section VIII below.
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will develop so that owner/operators of affected EGUs that have 

invested in measures eligible for the issuance of ERCs 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, 
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thereby reducing transaction costs. Similar developments have 

occurred in state-level renewable portfolio standard programs.376

If states choose to allow through their section 111(d) 

plans mechanisms or standards of performance involving 

instruments such as ERCs, the EPA believes that there 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 EGUs in two of the three 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 each source category are the 

emission rates achievable by that source subcategory through 

 

376 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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application of the building blocks in the 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 guidelines provide for 

states to set standards of performance incorporating emissions 

trading on an interstate basis among affected EGUs in different 

interconnections, all sources can take advantage of the headroom 

available in other interconnections. As a result, significant 

amounts of existing NGCC capacity and potential for RE remain 

available to serve as the basis for issuance of ERCs for all 

affected EGUs in both source subcategories to rely on to achieve 

their emission limits. Because 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 

that a virtually nationwide emissions trading market for 

compliance will emerge, and that ERCs will be effectively 
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available to any affected EGU wherever located, as long as its 

state plan authorizes emissions trading among affected EGUs.377

 

377 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 

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 RE would 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 
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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 its emission limit, in a state that sets emission 

limits in a mass-based form these measures are not taken into 

account directly in computations to determine whether an 

individual affected EGU has achieved its emission limit.

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 facilitates

the ability of the individual EGUs within the region to achieve 

their 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 ERCs, to 

achieve its emission rate; and if the affected EGU is subject to 

 

no further ERCs are accessible, and the total amount of building 

block 2 ERCs to be created.
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a mass emission 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 because lower-emitting (or zeroemitting) 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 EGUs can implement 

the building blocks by reducing generation to achieve their 

emission performance standards.378 Individual affected steam EGUs 

can reduce their generation in the amounts of building blocks 2 

 

378 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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and 3, while individual affected NGCC units can reduce their 

generation in the amount of building block 3. 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, 

the resulting reduction in overall fossil fuel-fired generation 

will incentivize investment in additional RE 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.

(c) Emissions trading. 

As described above, viewed from the perspective of the 

source category as a whole, it is reasonable for our analysis of 

the BSER to include an element of source-category-wide multiunit compliance which could be implemented via a state-set 

standard of performance incorporating emissions trading, under 

which EGUs could engage in trading of rate-based emission 

credits or mass-based emission allowances. By the same token, 

viewed from the perspective of an individual EGU, consideration 

of the ready availability to states of the opportunity to 

establish standards of performance that incorporate emissions 

trading is integral to our analysis. Accordingly, our assessment 

of the actions available to individual EGUs for achieving 
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standards of performance reflecting the BSER includes the 

purchase of rate-based 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 EGUs’ states’ section 111(d) plans and 

would have to meet conditions set out for such approaches in 

section VIII below. The role of emissions trading in the BSER 

analysis is discussed further in section V.A.2.f. below.

f. 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 
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standards of performance that incorporate emissions trading.379

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 

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.380

 

379 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.

380 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 
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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 

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); RGGI (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 zero-carbon 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).
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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. 

 

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 

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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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.

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.381

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 RE standards) when it was 

appropriate to do so given the program objective. The 

 

381 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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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 

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 
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specific emissions from any one EGU. The fact that trading 

allows sources to shift emissions from one location to another 

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 

RE. The affected EGUs could do so in any number of ways, 

including acquiring ownership interests in existing NGCC or RE

facilities or entering into bilateral transactions with the 

owners of existing NGCC facilities or RE sources. As discussed 

elsewhere, it is reasonable to expect that these actions can 

develop into discrete, tradable commodities (e.g., an 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 

commodities also incentivizes over-compliance by affected EGUs, 

which can then sell their over-compliance in the form of ERCs or 
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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 EE

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 

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 
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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.

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 
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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),382 the 

Regional Haze trading programs, the Clean Air Mercury Rule,383

 

382 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 RIA. “Regulatory Impact Analysis for the 

Federal Implementation Plans to Reduce 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 SIPs that authorize interstate emissions trading.

383 Although the CAMR trading program never took effect because 

the rule was vacated on other grounds, it consisted of a 
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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 RE

standards that promote RE 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 

 

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 HAP that caused adverse local impacts. 
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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 RE, 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 

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 
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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 EE implementable by affected EGUs; 

new or uprated 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 reducing the obligations on 

affected EGUs, such as demand-side EE 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.

h. 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 
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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 on crossinvestment 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 RE generating capacity in addition to coal-fired capacity. 

As a legal matter, it is not necessary that each affected EGU be 

able to implement the BSER, but in any event, in this rule, all 

affected EGUs can do so. Since states can reasonably be expected 

to establish standards of performance incorporating emissions 

trading, affected EGUs may rely on emissions trading 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.

i. Subcategorization. As noted above, in this rule, we are 

treating all fossil fuel-fired EGUs as a single category, and, 
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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 

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 whether and how to permit emissions trading --

including investment in the building blocks, replaced or reduced 
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generation, and purchase of emission credits or 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 EGUs, including investment in 

demand-side EE measures. Such compliance options may also 

indirectly help affected EGUs achieve compliance under a massbased 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 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
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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 

modifications to the proposed BSER. In this subsection we 

describe the most important modifications, including some that 

relate to individual building blocks and some that are more 

general. Additional modifications 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 modifications yield 

emission reductions requirements that commence more gradually 

than the proposed goals but are projected to produce greater 

overall annual emission reductions by 2030.384 We also note that 

the modifications lead to requirements that are more uniform 

across states than the 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 

 

384 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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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 

EGUs.385 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.

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 

EGUs 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 EGUs, 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 be accomplished only through government 

 

385 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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mandates. Further discussion of these points can 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, 

better 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 to 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 EGUs in each individual state, and because the relative 

magnitudes of these opportunities varied by state, states with 

similar EGU fleet compositions could have faced state goals of 

different stringencies, potentially making it difficult for 

multiple states to set the same standards of performance for 

affected EGUs using the same technologies (assuming the states 

were interested in setting standards of performance for their 

various affected EGUs in such a manner). Some commenters viewed 

this potential result as inconsistent with section 111(a)(1), 

inequitable, or both. In response, we took further comment on 

these potential disparities in the October 30, 2014 Notice of 
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Data Availability. In this final rule, we are obviating those 

concerns by assessing the emission reduction opportunities at an 

appropriate regional scale, consistent with alternatives on 

which we sought comment, and using this regional information to 

reformulate the proposed emissions standards as nationally 

uniform emissions standards for the emission guidelines.386

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 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 RE 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 

 

386 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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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 sought comment 

on an additional approach of aggregating the state-level 

information to a regional level, as suggested by some 

commenters. In this final rule we are adopting a combination of 

these approaches that uses historical RE generating capacity 

deployment data aggregated to a regional level, supported and 

confirmed by projections of market potential developed through a 

techno-economic approach. 

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. In response 

to the EPA’s request for comment on this approach, commenters 

observed that the 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 
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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 generation.387 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 

under-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 EGUs. 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 

 

387 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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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. While we 

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 under-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 units are being built and that the inclusion of the 

generation in the goals is premature because the units’ actual 

completion dates could 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 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 
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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 in 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 goals for the particular 

states where the units are located would be overly stringent 

either in absolute terms or relative to other states, we also 

acknowledge that, 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 decreasing costs, are not as clearly 

evidenced in nuclear generation. We view these factors as 

distinguishing the under-construction nuclear units from RE 

generating capacity, indicating that the new nuclear capacity is 

likely of higher cost and therefore less appropriate for 

inclusion in the BSER. Excluding the under-construction nuclear 

units from the BSER, but allowing emission reductions 
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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. 

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 

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 noted in 
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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 individual affected 

EGUs could use for compliance, as further discussed in section 

VIII.K.1.a.(8).388

d. Exclusion from the BSER of emission reductions from demandside EE. The June 2014 proposal included demand-side EE measures 

in building block 4 as part of the BSER. 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 EE as 

an integral part of the electricity system, emphasized its costeffectiveness as a means of reducing CO2 emissions from the 

 

388 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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utility power sector, and strongly supported its inclusion in 

the BSER, other commenters expressed significant concerns. 

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 EE 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, 

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 
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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. In the October 2014 

Notice of Data Availability, we requested comment on using 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.389 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. Under 

this approach, each of the building blocks is quantified and 

applied at the regional level, resulting in the computation for 

 

389 79 FR 64543, 64551-62
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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 stringent subcategory-specific 

performance rates to the baseline data for the EGU fleet in each 

state to establish state goals of consistent stringency across 

the country. (Note that the actual state goals vary among states 

to reflect the differences in generation mix among states 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.), CO2

emission performance rate computation (section VI), and state 

goal computation (section 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 

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 
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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 

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 
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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 RE generating 

capacity is relatively favorable can overcomply with its own 

standard of performance and sell rate-based emission credits or 

mass-based emission allowances to other affected EGUs. Purchase 

of the credits or allowances by the other EGUs represents crossinvestment 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, 

Western, and Texas Interconnections.390 In determining that the 

appropriate regional level for quantification of the BSER was 

the level of the interconnection, the EPA considered several 

 

390 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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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 –-

specifically the Eastern, Western, and Texas Interconnections. 

The Bulk Power System (BPS) in the contiguous U.S. (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 lowcapacity direct current (DC) tie lines. Each interconnection is 

managed to maintain a single frequency and to maintain stable 

voltage levels 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 
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over the transmission facilities of a third area.”391 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 

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 

 

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

Systems, IEEE Press, at 188 (2d ed. 2010).
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variety of organizations plan and operate these subregions, 

those activities always occur in the context of the 

interconnections, and 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 

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 subregions 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 
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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. 

Moreover, some planning and standard setting activities are 

undertaken explicitly at the interconnection level. For example, 

interconnections also have interconnection reliability operating 

limits (IROLs).392 A joint FERC-NERC report on the September 8, 

2011 Arizona-Southern California outages outlined the importance 

of IROLs.393 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 

 

392 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).”). 

393 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.
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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.”394

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.395 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 

 

394 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.

395 American Reinvestment and Recovery Act of 2009, Title IV, 

Public Law 111-5 (2009).
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interconnection-wide transmission plans.”396 DOE issued awards to 

five organizations that performed work in the Western, Eastern, 

and Texas Interconnections to develop long-term interconnectionwide transmission expansion plans.397

In Order No. 1000, FERC also took a broader regional view 

of transmission planning.398 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 

 

396 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.

397 DOE, Recovery Act Interconnection Transmission Planning, 

available at http://energy.gov/oe/services/electricity-policycoordination-and-implementation/transmission-planning/recoveryact.

398 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).
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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.”399 These principles take a broad view of electric 

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.”400 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).401 Moreover, both WECC and ERCOT have interconnectionwide reliability standards.402 The Eastern Interconnection has 

 

399 NERC, Reliability and Market Interface Principles, at 1, 

available at 

http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInter

facePrinciples.pdf.

400 NERC, Reliability and Market Interface Principles, at 1, 

available at 

http://www.nerc.com/pa/Stand/Standards/ReliabilityandMarketInter

facePrinciples.pdf.

401 NERC, Key Players, available at

http://www.nerc.com/AboutNERC/keyplayers/Pages/default.aspx.

402 WECC, Standards, available at

https://www.wecc.biz/Standards/Pages/Default.aspx (last visited 

July 3, 2015); Texas Reliability Entity, Reliability Standards, 
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multiple reliability regions with some differences in standards, 

but power flows and reliability are managed through a single 

Reliability Coordinator Information System that tracks power 

flows for all transmission transactions.403

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 

 

available at 

http://www.texasre.org/standards_rules/Pages/Default.aspx (last 

visited July 3, 2015).

403 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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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 

problems in any one area in the synchronous network can affect 

the entire network.”404 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.405 The following year, in December 2013, Entergy and its six 

utility operating companies joined MISO, creating the MISO South 

 

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

Systems, IEEE Press, at 159 (2d ed. 2010).

405 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.
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Region.406 The integration of MISO South correspondingly led to 

changes in NERC’s regional assessment areas.407 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.408

Additionally, PacifiCorp and the CAISO recently began operating 

the western Energy Imbalance Market (EIM).409 Other entities such 

as NV Energy, Arizona Public Service Co., and Puget Sound Energy 

are planning to participate in the EIM in the future.410 The EIM 

“creates significant reliability and renewable integration 

 

406 Miso, South Region Integration, available at 

https://www.misoenergy.org/WhatWeDo/StrategicInitiatives/Souther

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.”). 

407 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.

408 SPP, FERC approves Integrates System joining SPP (Nov. 12, 

2014), available at 

http://www.spp.org/publications/FERC%20approves%20IS%20membershi

p.pdf.

409 NREL, Energy Imbalance Market, available at

http://www.nrel.gov/electricity/transmission/energy_imbalance.ht

ml.

410 CAISO, EIM Company Profiles (May 2015), available at

http://www.caiso.com/Documents/EIMCompanyProfiles.pdf.
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benefits for consumers by sharing and economically dispatching a 

broad array of resources.”411 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 

 

411 CAISO, Energy Imbalance Market, available at

http://www.caiso.com/informed/pages/stakeholderprocesses/energyi

mbalancemarket.aspx.
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of RE throughout each interconnection -- as well as the 

management of the interconnected grid as loads are reduced 

through EE, 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 higher-emitting 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 an economic 

incentive for concerned parties to explore ways to relieve the 
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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 EGUs 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 interconnection-wide 

changes in flow that are managed in real time. Moreover, the 

exchange of power is not limited to these areas. For example, 
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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 RECs, 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 EGU should 

also limit the EGU’s transactions for validly issued rate-based 

emission 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 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 
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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. 

Specifically, the final rule establishes a performance rate 

of 1305 lbs. per net MWh for all affected steam EGUs nationwide 

and a performance rate of 771 lbs. per net MWh for all affected 

stationary combustion turbines nationwide. The computations of 

these performance rates and the determinations of state goals 

reflecting the performance rates are described in sections VI 

and VII of the preamble, respectively. 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 
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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. 

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 

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 
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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 subcategory as the basis 

for nationally uniform performance rates for that technology 

subcategory than by using the most stringent of the regional 

performance rates.412 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 

 

412 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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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 

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 RE generating capacity than 

combustion turbines in the third interconnection.413

 

413 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 
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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 

EGUs in the interconnections that do not set the nationwide 

level. This greater “headroom” provides greater nationwide 

compliance flexibility and assurance that the standards set by 

the states based on the emission guidelines will be achievable 

at reasonable cost 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 

 

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 

rate computed for the Eastern Interconnection for the years from 

2027 through 2030.
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be considered the “best” system of emission reduction for each 

technology subcategory. 

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 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 system.

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 for each source subcategory and also translating those 

rates to state-specific weighted average rate-based goals. For 

additional flexibility, we are also translating the statespecific rate-based goals into state-specific mass-based goals. 

Our determinations of the emission performance rates are 
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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 

opportunities based on their states’ borders, and the proposed 

goals therefore were less stringent in states which had 
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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 

in the range bounded by the CO2 emission performance rate for 

NGCC units and the CO2 emission performance rate for steam EGUs 

because all of the state goals are computed as a weighted 
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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 country414 located in the contiguous U.S. that have 

affected EGUs.415 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 –- 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 jurisdictions can be found in 

section VII.F. of the preamble.

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 

 

414 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. 

415 As noted earlier, there are currently no affected EGUs in 

Vermont or the District of Columbia. 
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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 for planning and 

investments necessary for sources to begin implementation 

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 

and will, 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. This will enable the final rule’s 

requirements to be implemented in an orderly manner while 

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., 
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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 

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 
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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, 

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 REgeneration over the next six years. This 

amount would make up between four and five percent of Alabama 

Power’s generation mix.416 In addition, the study of utility IRPs 

 

416 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 
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placed in the docket for this rulemaking417 shows that sources 

are able to replace coal-fired generation with natural-gas fired 

generation and add incremental amounts of RE (as well as take 

other actions, such as implement demand-side EE 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 solicited 

and has made a number of refinements in the final rule based on 

that information. The refinements are discussed in the preamble 

sections for each building block (sections V.C., V.D., and V.E.) 

and emission 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. As 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 interim goals somewhat less stringent 

 

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 

dramatically boost its renewables portfolio,” E&E Publishing, 

July 16, 2015.

417 See memo entitled “Review of Electric Utility Integrated 

Resource Plans” (May 7, 2015) available in the docket.
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than at proposal and the 2030 goals somewhat more stringent than 

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 RE 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 as a whole. Each building 

block can be implemented through standards of performance set by 

the states and includes a set of actions that individual sources 

can use to achieve the emission limitations reflecting the BSER. 

These actions and mechanisms, which include reduced generation 
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and emissions trading approaches where the state-set standards 

of performance incorporate trading and which may be understood 

as part of the BSER, 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 modifications being made in 

this rule is the establishment of uniform performance rates by 

technology subcategory, 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-wide scope of opportunities available for affected EGUs 

to access emission reduction measures. The 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 zero-carbon generation. 

Consequently, in order to achieve uniform performance rates by 

technology subcategory, while respecting these regional 
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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 subcategory, the BSER is the combination of the 

elements described above at the combined stringency that is 

reasonably achievable in the region where the CO2 emission 

performance rates determined to be achievable at reasonable cost 

by the EGUs in that subcategory through application of the 

building blocks were least stringent.418

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 

 

418 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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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 what is reasonably achievable 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 additional 

emission reductions can be achieved at reasonable cost, thereby 

promoting nationwide compliance flexibility. Further, because we 

are authorizing states to establish standards of performance 

that incorporate trading without geographic restrictions, the 

opportunity of affected EGUs to engage in emissions trading, 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 reduce 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: Improving heat rate at affected coal-fired 

steam EGUs 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 zero-emitting 

RE generating capacity for reduced generation from affected EGUs 

in specified quantities. 

a. Building block 1. Building block 1 -- improving heat rate 

at affected coal-fired steam EGUs -- is a component of the BSER 

with respect to coal-fired steam EGUs419 because the measures the 

affected EGUs 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 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.

 

419 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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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 

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 
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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 also 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 

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. 
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However, we believe that our 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, 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. 

b. Building block 2. Building block 2 –-substituting generation 

from less carbon-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 
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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.

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 
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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 longterm 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 recognized that generation shifts among EGUs are a 

means of reducing emissions from 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, 
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legislative history, regulatory precedent, and industry practice 

support interpreting the broad term “system of emission 

reduction” as including substituting lower-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 

increasing operation of an NGCC unit that it already owns or by 

purchasing an existing NGCC unit and increasing operation of 

that unit. Increases in generation by NGCC units over baseline 

levels can also serve as the basis for creation of CO2 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 
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of investment in the underlying emissions 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 ERCs by NGCC units and for the use of such ERCs 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 ERCs. The minimum criteria are discussed in 

section VIII of this preamble. 

We note that an affected EGU 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 EGUs 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 likely to be 

generation from an affected steam EGU. Measures taken by 
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affected EGUs that result in emission reductions from other EGUs 

in the source category may appropriately be deemed measures 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.420 With respect to energy impacts, 

building block 2 represents replacement of electrical energy 

from one generator with electrical energy from another generator 

 

420 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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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 innovation only in the alternative, we note that 

building block 2 promotes 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.421 Through application of this 

building block considered in isolation, some affected EGUs –-

mostly coal-fired steam EGUs -- would reduce their generation 

and CO2 emissions, while other affected EGUs –- 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

 

421 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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emissions from all affected EGUs 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 highly 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 understood 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). Standards of performance that 

incorporate emissions trading can 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 –-substituting 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 EGUs is technically feasible, is of 
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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 ERCs. 

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 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 
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recent industry trends. States are already pursuing policies 

that encourage production of greater amounts of RE, such as the 

establishment of targets for procurement of renewable generating 

capacity. Moreover, as discussed earlier, markets are likely to 

develop for ERCs that would facilitate investment in increased 

RE generation as a means of helping sources comply with their 

standards of performance; indeed, markets for RECs, which 

similarly facilitate investment in RE for other purposes, are 

already well-established. As noted in Section V.A.5. below, an 

allowance system or tradable emission rate system would provide 

incentives for affected EGUs 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 by substituting generation from new RE

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 
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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 

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 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 
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creation of valid ERCs by new RE generators and for the use of 

such ERCs by affected 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 credits. The minimum criteria are discussed 

in section VIII of the preamble. 

As with building block 2, an affected EGU 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 EGUs 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. Measures taken by affected EGUs that result in 

emission reductions from other sources in the source category 

may appropriately be deemed methods 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 variable 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 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.G.2, will ensure the absence of adverse energy 

impacts. With respect to technological innovation, which we 

consider for the BSER only in the alternative, incentives for 

expansion of renewable capacity encourage technological 
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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 

of emission reduction ... adequately demonstrated” for reducing 

CO2 emissions at affected EGUs. 

As already discussed, each of the individual building 

blocks generally performs well with respect to the BSER factors 
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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 

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 
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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 

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 
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EGUs’ efficiency but also to reduce generation from those EGUs 

consistent with replacement of generation by low- or zeroemitting EGUs. 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, 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 
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such climate change, as described in Section II.A. The EPA 

focused on public health and welfare impacts within the U.S., 

but the impacts in other world regions strengthen the case for 

action because impacts in other world regions can in turn

adversely affect the U.S. 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. 
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Also, 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).422 However, we 

believe that the cost of emission reductions achieved through 

heat rate improvements in the context of a three-building block 

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 low enough that the cost per 

ton of CO2 emission reductions will remain reasonable even if 

that cost is substantially increased. Second, although under a 

BSER encompassing all three building blocks the volume of coal-

 

422 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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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.

In contrast with those prior examples, combining the 

building blocks also produces interactive dynamics that 

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 
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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.423 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 

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.424 Applying building blocks 2 and 3 together produces 

significantly more CO2 reductions at a relatively lower cost 

 

423 The EPA’s cost-effectiveness estimate of $24 per ton for 

building block 2 reflects these market dynamics.

424 The EPA’s cost-effectiveness estimate of $37 per ton for 

building block 3 reflects these market dynamics.
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because the countervailing nature of these wholesale power price

dynamics mitigates the primary cost drivers for each building 

block.425

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 

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 

 

425 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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a reduction in cost per ton when compared to cost estimates that 

do not incorporate this interactivity.426

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.

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 

 

426 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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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 

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 
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installing and operating a dry scrubber are approximately $13 to 

$16 per MWh.427

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 

building block 3,428 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.429 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 

 

427 For details of these computations, see the memo “Comparison of 

building block costs to FGD costs” available in the docket.

428 The comparison for an NGCC unit considers only building block 

3 because building blocks 1 and 2 do not apply to NGCC units.

429 For details of these computations, see the memo “Comparison of 

building block costs to FGD costs” available in the docket.
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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 

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.430 In comparison, the 

conservatively high, weighted-average cost of $30 per ton 

removed described above is at the high end of the range of 

 

430 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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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 

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 
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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. 

As required under Executive Order 12866, the EPA conducts 

benefit-cost analyses for major Clean Air Act rules.431 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 

 

431 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.
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Act, and is not using such a test here.432 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.433 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).434 The central values for the 

SC-CO2 range from $40 per short ton in 2020 to $48 per short ton 

 

432 See memo entitled “Consideration of Costs and Benefits Under 

the Clean Air Act” available in the docket.

433 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, 

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.

434 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.
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in 2030.435 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 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.

 

435 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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e. 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 

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 
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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 

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 

deem 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 
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achievability.436 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 

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 

 

436 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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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 

regulatory requirements are able to implement building block 3 

and thereby achieve the emission performance rate for NGCC 

units.437

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 

 

437 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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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 

Based on the determination of the BSER described above, the 

EPA has identified a performance rate of 1305 lbs. per net MWh 

for affected steam EGUs and a performance rate of 771 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 implement or apply the BSER 

and, in that sense, may be understood as part of the BSER. 
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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).

 Directly investing in, or purchasing ERCs created as a 

result of, incremental generation from existing NGCC units 

(building block 2).

 Directly investing in, or purchasing ERCs created as a 

result of, generation from new or uprated RE generators 

(building block 3).

 Reducing its utilization, coupled with direct investment in 

or purchase of ERCs 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.

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).
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 Reducing its utilization and allowing its generation to be 

replaced or avoided through the routine operation of 

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. 

The EPA has determined appropriate CO2 emission performance 

rates for each of the two source subcategories 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 EGU 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 implement 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. The 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 but can 

readily be reflected in an emission rate computation by 

averaging ERCs acquired by the affected EGU into the rate 

computation. 
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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. As summarized below and 

as discussed in greater detail in section VIII.K., the existence 

of a clearly feasible path for usage of ERCs ensures that 

emission reductions achievable 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 ERCs issued on the basis of incremental 

generation from an existing NGCC unit. As permitted under the 
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EGU’s state’s section 111(d) plan, the owner/operator of the 

affected EGU could accomplish this 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 

organized market.438 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 

 

438 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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existing NGCC unit. Those criteria generally concern ensuring 

that the physical basis for the ERC –- i.e., qualifying 

generation by an existing NGCC unit and the NGCC unit CO2

emissions associated with that qualifying generation –- is 

adequately monitored and that there is an adequate 

administrative process for tracking credits to avoid doublecounting. In the case of ERCs related to building block 2, the 

monitoring criteria would generally be satisfied by standard 40 

CFR part 75 monitoring. 

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. As permitted under the EGU’s state’s 

section 111(d) plan, the owner/operator of the affected EGU 

could accomplish this through either common ownership of the RE 
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generating capacity, a bilateral transaction with the 

owner/operator of the RE generating capacity, or a transaction 

for ERCs through an intermediary, which could, but need not,

involve an organized market.439 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. 

 

439 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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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 

adequate administrative process for tracking credits to avoid 

double-counting and to facilitate enforceability of emission 

limits.440

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.

(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. 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 

 

440 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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capacity, generation from new RE generating capacity, or 

purchase from an entity with surplus ERCs. If the owner/operator 

does not average any ERCs 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 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 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 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 

acquire tradable rate-based emission credits representing an 

investment in surplus emission rate reductions not needed by 
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another affected EGU and can average those credits into its own 

emission rate for purposes of demonstrating compliance with its 

rate-based standard of performance. The 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, it is reasonable to presume that such 

authorization will be forthcoming from states that submit plans 

establishing rate-based standards of performance for their 

affected EGUs.

Under a 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 an affected EGU needing additional credits can 

acquire 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. 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 
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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 just as they can 

engage in transactions for other kinds of goods and services.

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.

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 EGU 

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 mass-based standards in the 

typical manner where the standard of performance for each 
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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 

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. 
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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 

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 EE 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 approaches.
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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 acquire 

tradable mass-based emission allowances representing investment 

in surplus emission reductions not needed by another affected 

EGU and can aggregate those allowances with any other allowances 

it already holds for purposes of demonstrating compliance with 

its mass-based standard of performance. The 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 a 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 an 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. As discussed earlier, based on observation of 

market behavior both inside and outside the electricity 

industry, we expect that intermediaries will seek opportunities 
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to participate in such transactions and that 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 
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of stringency reflected in this final rule even if one or more 

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 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. 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, 
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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 are 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 

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 the 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 
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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 reflective of the BSER, as discussed above. 

(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 
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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 

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.
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(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 

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 the 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 
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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 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 combined 

heat and power (CHP) production. While the set of affected EGUs 
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in locations making this measure feasible may be limited, where 

feasible the potential CO2 emission rate improvements can be 

substantial: 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.441)

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 

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 

 

441 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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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, affected EGUs would need to acquire 

ERCs based on the non-BSER activities that could be averaged 

into their emission rate computations for purposes of 

determining compliance with their standards of performance.

(1) Demand-side EE.

One of the major approaches available for achieving CO2

emission reductions from the utility power sector is demand-side 

EE. In the June 2014 proposal, the EPA identified demand-side EE

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 demand-side EE rival those from 

building blocks 2 and 3 in magnitude, and that demand-side EE is 

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 EE in their compliance strategies to 
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the extent permitted, and we received comment that it should be 

permitted.

For the reasons discussed in section V.B.3.c.(8) below, the 

EPA has determined not to include demand-side EE in the BSER in 

this final rule. However, the final rule authorizes generation 

avoided through investments in demand-side EE to serve as the 

basis for issuance of ERCs 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 ensuring that the physical 

basis for the ERC -– in this case, generation avoided through 

implementation of demand-side EE measures –- is adequately 

evaluated, measured, and verified and that there is an adequate 

administrative process for tracking credits. 

Through their authority over legal requirements such as 

building codes, states have the ability to drive certain types 

of demand-side EE measures that are beyond the reach of privatesector 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 
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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 uprated 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 

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 uprates 

to the capacity of existing nuclear units. Requirements for 

state plan provisions intended to serve this purpose are 

discussed in section VIII.K.

(3) Zero-emitting RE generating technologies not reflected 

in the BSER.
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The range of available zero-emitting RE 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 zeroemitting RE technologies not included in the 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 U.S. 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 
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technologies. 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 

qualified biomass or biogenic portions of municipal solid waste 

(MSW) to produce electricity can also replace generation from 

affected EGUs and thereby control CO2 levels in the atmosphere.442

While the EPA believes it is reasonable to consider generation 

from these fuels and technologies to be forms of RE generation, 

the fact that they 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 benefits. 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 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 

 

442 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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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 –- 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. More 

information is provided in section VIII.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 
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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 

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. Further 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. Building blocks 2 and 3 are feasible and 

demonstrated means of reducing CO2 emissions from the utility 

power sector that can be implemented independently 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 
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utility power sector.443 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 

reductions,444 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. 

 

443 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.

444 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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In the event that a court should deem building block 2 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 CO2 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 qualify as part of the BSER 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 the design or operation of the affected source’s own 

production processes or methods or because they are dependent on 

actions by entities other than the affected source; (4) the 

relationship between an affected EGU’s implementation of 

building blocks 2 and 3 and CO2 emissions reductions; (5) how 

reduced generation relates to the BSER; (6) reasons why, 

contrary to assertions by commenters, this rule is within the 
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EPA’s statutory authority, 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 

regulatory authority”;445 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 

 

445 Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2444 (2014).
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Amendments, however, 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).446 The 1970 provision was in effect when the EPA 

issued the 1975 implementing regulations for CAA section 

111(d),447 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.448

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 

 

446 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.

447 See “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340 (Nov. 17, 1975). 

448 See “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340 (Nov. 17, 1975).
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from the source category, while the states have the 

responsibility of assigning emission requirements to their 

sources that assured their achievement of that level of emission 

limitation.449 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.”450 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.”451 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] 

 

449 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. 

450 “State Plans for the Control of Certain Pollutants From

Existing Facilities,” 40 FR 53340, 53342 (Nov. 17, 1975).

451 “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340, 53343 (Nov. 17, 1975).
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section 111(d).”452 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 

reasons discussed in the preamble to the 1975 implementing 

regulations.

 

452 “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53340, 53343 (Nov. 17, 1975).
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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.”453 States, on the other hand, 

“would be responsible for determining the applicability of such 

guidelines to any particular source or sources.”454 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, 

we would not expect the House report to adopt the EPA’s 

terminology to clarify CAA section 111(d). 

 

453 H.R. Rep. No. 95-294, at 195 (May 12, 1977) (emphasis added).

454 H.R. Rep. No. 95-294, at 195 (May 12, 1977) (emphasis added).
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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.”455 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.456 The EPA’s 

 

455 CAA section 129(a)(1)(A) (emphasis added).

456 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 

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 
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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.457

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 

States then issue performance standards for stationary sources 

within their jurisdiction, § 7411(d)(1).”458

As noted in the response to comment document, some 

commenters agreed with our interpretation, just discussed, while 

 

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).

457 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).

458 Am. Elec. Power Co. v. Connecticut, 131 S. Ct. 2527, 2537-38 

(2011).
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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.

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 
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to endanger public health or welfare459 and then to regulate new 

sources within each such source category,460 and which grant the 

EPA discretion whether to subcategorize new sources for purposes 

of determining the BSER.461

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 

compliance options not included in the BSER for this rule are 

also available to all affected sources, including investment in 

demand-side EE measures. Such 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 

 

459 CAA section 111(b)(1)(A).

460 CAA section 111(b)(1)(B).

461 CAA section 111(b)(2).
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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).462

 

462 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

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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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 

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 
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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 rates 

that we include in this rule’s emission 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 (RE) 

cannot, as a legal matter, be considered part of the BSER under 

CAA section 111(d)(1) and (a)(1). These commenters explain that 

in their view, under CAA section 111, the emission performance 

rates must be based on, and therefore the BSER must be limited 

to, methods for emission control that the owner/operator of the 

affected source can integrate into the design or operation of 

the source itself, and cannot be based on actions taken beyond 

the source or actions involving third-party entities.463 For 

 

463 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-the-source’ 
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these reasons, these commenters argue that the phrase “system of 

emission reduction” cannot be interpreted to include building 

blocks 2 and 3. 

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 is

capacious enough to include actions taken by the owner/operator 

of a stationary source designed to reduce emissions from that 

 

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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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. 

Such actions include the measures in building blocks 2 and 3, 

which, when implemented by an affected source, enable the source 

to achieve their emission limits because of the unique 

characteristics of the utility power sector. For purposes of 

this rule, we consider a “system of emission reduction” -- as 

defined under CAA section 111(a)(1) and applied under CAA 

section 111(d)(1) -– to encompass a broad range of pollutionreduction actions, which includes the measures in building 

blocks 2 and 3. Furthermore, the measures in building blocks 2 

and 3 fall squarely within EPA’s historical interpretation of 

section 111, pursuant to which the focus for the BSER has been 

on how to most cleanly produce a good, not on how much of the 

good should be produced.

Our interpretation that a “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 its plain 

meaning and statutory context; our interpretation accommodates 

the very design of CAA section 111(d)(1), which covers a range 
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of source categories and air pollutants;464 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 

CAA provisions that give the EPA similar authority to consider 

such measures and to CAA provisions that would preclude the EPA 

from considering such measures. 

In addition to the reasons stated above, 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 

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 

 

464 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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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,465

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 

measures, the amount of pollution produced at the source.466 (iv) 

Lastly, interpreting the phrase “system of emission reduction” 

to authorize the EPA, in formulating its BSER determination, to 

weigh a broad range of emission-reducing measures that includes 

building blocks 2 and 3 is consistent with Congress’s intent to 

 

465 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).

466 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.
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address urgent environmental problems and to protect 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. 

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.”467 In doing so, Congress established numerous 

programs to address air pollution problems and provided the EPA 

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 

 

467 CAA section 101(a)(2).
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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 

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 
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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 

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.468 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 

 

468 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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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.”

The phrase “system of emission reduction” appears in the 

definition of a “standard of performance” under CAA section 

111(a)(1). 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 
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“building, structure, facility, or installation which emits or 

may emit any air pollutant.”469

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.470 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. 

 

469 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.”)

470 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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When read in context, the phrase “system of emission 

reduction” carries important limitations: because the “degree of 

emission limitation” must be “achievable through the application

of the best system of emission reduction,” (emphasis added), the 

“system of emission reduction” must be limited to a set of 

measures that work 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.”471

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 an emission limitation 

applicable to their existing source.472

 

471 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. 

472 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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In contrast, a “system of emission reduction” does not 

include actions that only a state or other governmental entity 

could take that would have the effect of reducing emissions from 

the source category, and that are 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.”

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.) Thus, in determining the BSER, the Administrator must 
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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, it is not necessary to 

enumerate all of the types of 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.” 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).
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(2) Other indications that the BSER provisions encompass a 

broad range of measures. 

The EPA’s plain meaning interpretation that the BSER 

provisions in CAA section 111(d)(1) and (a)(1) are 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) Scope of CAA section 111(d)(1). 

First, the broad scope of CAA section 111(d)(1) supports 

our interpretation of the BSER 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). 

In the 1970 CAA Amendments, 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 

stationary 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.473

Congress enacted CAA section 111(d) to cover this third category 

 

473 40 FR 53340, 53340 (Nov. 17, 1975) (EPA regulations 

implementing CAA section 111(d)).
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of air pollutants and, in this sense, Congress designed it to 

apply to any air pollutants that were not otherwise regulated as 

toxics or NAAQS pollutants.474 This would include air pollutants 

that the EPA might later, when more information became 

available, designate as NAAQS or hazardous air pollutants, as 

well as air pollutants that Congress may not have been aware of 

at the time.475 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).476 In addition, in the 1990 CAA 

 

474 See S. Rep. No. 91-1196, 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.”).

475 See S. Rep. No. 91-1196, at 20 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 420.

476 See S. Rep. No. 91-1196, 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 
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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.477 Finally, it 

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) to 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 BSER provision, as applied to CAA section 

 

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).

477 See, e.g., Standards of Performance for New Stationary 

Sources and Emission Guidelines for Existing Sources: 

Hospital/Medical/Infectious Waste Incinerators, 62 FR 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 FR 

75338, 75341 (Dec. 1, 2000).
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111(d), have a broad scope so as to accommodate the range of air 

pollutants and source categories. 

(b) Legislative history of CAA section 111. 

(i) Breadth of “system of emission reduction.”

The phrase “system of emission reduction,” 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 

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.478

 

478 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, 

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 
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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 

such emissions to the fullest extent compatible with the 

available technology and economic feasibility, as determined by 

the Secretary.”479 The Senate bill, S. 4358, would have 

 

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.

479 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. 
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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.”480 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.”481 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.482

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.483

 

480 S. 4358, § 6, 1970 Legis. Hist. at 554-55 (emphasis added). 

481 S. Rep. No. 91-1196, at 15-16 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 415-16 (emphasis added).

482 S. Rep. No. 91-1196, at 15-16 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 415-16 (emphasis added).

483 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 
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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.484

While the phrase “system of emission reduction” was not 

discussed in the Conference Report, 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.”485 In light of this summary, the phrase “system of 

 

to include such measures as building blocks 2 and 3 -- are 

appropriate under CAA section 111.

484 CAA section 111(a)(1) under the 1970 CAA Amendments (emphasis 

added).

485 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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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). This 

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 

measures or actions such as the ones in building blocks 2 and 3 

from the EPA’s assessment of the BSER. 

Notwithstanding this broad approach, as we discuss in the 

Legal Memorandum, the legislative history of the 1970 CAA 

Amendments also indicates that Congress intended that new 

sources 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 
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sources to meet emission standards based on the reductions 

achievable through the use of the ”best technological system of 

continuous emission reduction.”486 According to the legislative 

history, [t]his mean[t] that new sources may not comply merely 

by burning untreated fuel, either oil or coal.” 487 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.”488 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.” 489 Congress 

nonetheless recognized that despite narrowing new source 

standards to the best “technological system of continuous 

 

486 CAA section 111(a)(1) (1977).

487 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2659.

488 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2659.

489 New Stationary Sources Performance Standards; Electric 

Utility Steam Generating Units, 44 FR 33580, 33581-33582 (June 

11, 1979). 
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emission reduction,” many “innovative approaches may in fact 

reduce the economic and energy impact of emissions control,” and 

the Administrator should still be encouraged to consider other 

technologically based techniques for emissions reduction, 

including “precombustion cleaning or treatment of fuels.”490 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,”491

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.”492 This was intended to distinguish existing source 

 

490 H.R. Rep. No. 95-294, at 189 (May 12, 1977), 1977 CAA Legis. 

Hist. at 2656.

491 CAA section 111(a)(1)(C) under the 1977 CAA Amendments.

492 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. 
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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.”493,494

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.”495 Further, nothing in the 1990 CAA Amendments or 

their legislative history indicates that Congress intended to 

 

at 2662 (“The Administrator would establish guidelines as to 

what the best system for each such category of existing sources 

is. However, the state would be responsible for determining the 

applicability of such guidelines to any particular source or 

sources.”).

493 Sen. Muskie, S. Consideration of the H.R. Conf. Rep. No. 95-

564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353.

494 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.

495 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 constraints on the types of systems of emission 

reduction that could be considered under CAA section 111(d)(1) 

and (a)(1). In contrast, Congress retained the definition 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).496

 

496 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 

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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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 

histories 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 

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 
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the phrase “system of emission reduction” must not include 

actions taken by entities other than the affected sources.497

As 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.”498 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 

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 

 

497 See, e.g., comments by UARG at 31 (the building blocks other 

than building block 1 take a “‘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.”).

498 1977 CAA Amendments, § 109, 91 Stat. at 700; see also CAA 

section 111(a)(7).
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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”).499 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 

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 within the scope of the best system of 

 

499 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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emission reduction even under the 1970 CAA Amendments),500 and in 

fact, the EPA’s regulations promulgated after the 1990 CAA 

Amendments continue to impose standards of performance that are 

based on third-party coal cleaning.501

(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 authorize 

the EPA’s consideration of the building block 2 and 3 measures 

is consistent with the overall structure of the CAA, 

particularly as it was amended in 1970, 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 

 

500 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)).

501 40 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 FR 32742 (June 13, 2007).
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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 

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. 

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 
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types of pollutants and in determining the standards.502 By and 

large, Congress left these provisions intact in the 1977 CAA 

Amendments.503,504

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 

 

502 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.

503 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. 

504 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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this drafting approach is not unique to the CAA; on the 

contrary, Congress "usually does not legislate by specifying 

examples, but by identifying broad and general principles that 

must be applied to particular factual instances."505

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.

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.

 

505 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 its 

terms limits 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. 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 an 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 lowemitting 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). 

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
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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.” (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.”506 (Emphasis added.) These provisions 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. 

Some 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 

 

506 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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into the source’s design or operations. This 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 CAA section 407(b)(2) NOx

requirements. 

Second, the interpretations that commenters offer for these 

various provisions misapply the text. For example, commenters 

note that under CAA section 111(d)(1), (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), i.e., stationary sources, as 
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opposed to other types of sources, e.g., mobile sources, whose 

emissions are addressed under other CAA provisions (such as CAA 

Title II). This 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. 
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Third, 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 is 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.507 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.”508 The same is necessarily true for existing sources. 

This supports the EPA’s view that the basis for whether a 

control measure qualifies as a “system of emission reduction” 

 

507 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”).

508 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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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 emission 

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 in such cases, the EPA may 

instead impose design standards rather than establish an 

emission standard (i.e., the EPA can require sources to 

implement a particular design, equipment, work practice, or 

operational standard). When an emissions standard is
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appropriate, as in the present rule, CAA section 111(h) is 

silent as to what types of measures –- whether limited to a 

source’s own design or operations -- may be considered as the 

system of emission reduction.509 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. 

Commenters also argue, more generally, that Congress knew 

how to authorize control measures such as RE, as indicated by 

Congress’s inclusion of those measures in Title IV (relating to 

acid rain), so 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 

 

509 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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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 emission reduction measures –- neither RE measures 

(like the ones Congress wanted to incentivize under Title IV),

nor measures that are integrated into the sources’ design or 

operations (like the retrofit control measures Congress 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 as sufficiently broad to encompass a wide range of 

measures for the purpose of emission reduction of a wide range 

of pollutants from a wide range of stationary sources.510

c. Deference to interpret the BSER to include building blocks 2 

and 3. To the extent that it is not clear whether the phrase 

“system of emission reduction” may include the measures in 

building blocks 2 and 3, the EPA’s interpretation of CAA section 

 

510 It should also be noted that Title IV is limited to 

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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111(d) and (a) is reasonable511 in light of our discretion to 

determine “whether and how to regulate carbon-dioxide emissions 

from power plants....”512

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 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 above, electricity is highly 

substitutable and the utility power sector is highly integrated, 

so much so that it has been likened to a “complex machine.”513

Specifically, the utility power sector is characterized by 

physical, as well as operational, interconnections between 

electricity generators themselves, and between those generators 

 

511 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.”).

512 American Electric Power Co. v. Connecticut, 131 S. Ct. 2527, 

2538 (2011) (“AEP”) (emphasis added).

513 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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and electricity users. Because of the physical properties of 

electricity and the current 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 

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.
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Congress,514 the Courts,515 the EPA in its regulatory 

actions,516 and states in their regulatory actions517 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 

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 lead to the instantaneous increase 

in generation from other generators. Thus, the operation of 

individual EGUs is integrated and coordinated with the 

 

514 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 S. Rep. No. 101-228, 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 Title IV).

515 New York v. Federal Energy Regulatory Commission, 535 U.S. 1, 

at 7 (2002) (citing Brief for Respondent FERC 4-5). 

516 “Stack Heights Emissions Balancing Policy,” 53 FR 480, 482 

(Jan. 7, 1988). 

517 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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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 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 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 
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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 CO2.518

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 

“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” 

 

518 See Util. Air. Reg. Group v. EPA, 134 S. Ct. 2427, 2441 

(2014).
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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, 

would be inconsistent with Congressional design that the CAA be 

comprehensive and address the major environmental issues.519

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 

 

519 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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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 

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 
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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 

reducing CO2 emissions520 –- 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 

 

520 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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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 

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 approaches to reducing emissions 

in the utility power sector were first tested around the time 

that Congress adopted the 1970 CAA Amendments.521 Over time, 

these techniques have become more established within the 

industry, and by the 1990 CAA Amendments, Congress based the 

Title IV acid rain program for existing fossil fuel-fired EGUs 

in part on the same measures that are considered 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 

 

521 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 SO2 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.522

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.523 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.”524 As such, Congress viewed federal standards of 

performance as the appropriate backstop to Title IV even for 

sources that could not otherwise be regulated under CAA section 

 

522 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 SO2emitted). Congress believed 

that mandating a technological standard through the percentage 

reduction requirement in section 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 section 111.

523 1990 CAA Amendments, § 406, 104 Stat. at 2632-33; see also S. 

Rep. No. 101-228, at 282 (industrial source emissions totaled 

5.6 million tons of SO2 in 1985).

524 S. Rep. No. 101-228, at 345 (Dec. 20, 1989).
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111(d).525 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 SO2 emissions from coal-fired EGUs by 

adopting a nationwide cap of 8.95 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 (8.95 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 RE, along with add-on controls and other 

measures. Thus, Title IV provides a close analogy to CAA section 

111: generation shift and RE were part of Congress’s basis for 

the Title IV emission requirements, and that is analogous to 

building blocks 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 RE as the 

 

525 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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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

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 
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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 RE. 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”526 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.”527

Congress’s reliance on generation shifting and REto 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 RE. In CAA section 404(f) and (g), Congress set aside 

a special pool of allowances to encourage use of RE. In order to 

 

526 See S. Rep. No. 101-228, at 320 (Dec. 20, 1989).

527 See S. Rep. No. 101-228, at 316 (Dec. 20, 1989) (emphasis 

added). 
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obtain a special allowance (which would authorize emissions from 

a coal-fired utility), an electric utility needed to pay for 

qualifying RE sources “directly or through purchase from another 

person.”528 These measures confirm Congress’s recognition that 

REwas 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 

measures, including shifting to lower-emitting generation as 

well as reliance on RE. 

For example, the Senate Committee Report529 and Senator 

Baucus,530 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 

 

528 CAA section 404(f)(2)(B)(i).

529 S. Rep. No. 101-228 (Dec. 20, 1989), 1990 CAA Legis. Hist. at 

8656.

530 S. 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).
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maximize emissions reductions.” Similarly, statements supporting 

the RE 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.531

(4) Reliance on RE measures to reduce CO2.

The Title IV legislative history also makes clear that 

Congress viewed RE measures as a means to reduce CO2 for the 

purpose of mitigating climate change. By the time of the 1990 

CAA Amendments, Congress had long been aware that emissions of 

CO2 and other GHGs 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 

 

531 H.R. Rep. No. 101-490, at 368-69; 674-76 (May 17, 1990) 

(additional views 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, 

photovoltaics, geothermal, and wind. These clean sources and 

energy, available in virtually limitless supply, are the way of 

the future.”). 
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atmosphere.532 The record for the 1970 CAA Amendments include 

hearings533 and a report by the National Academy of Sciences 

noting that carbon dioxide emissions could heat the 

atmosphere.534 A 1976 report noting the phenomenon was included 

in the record for the 1977 CAA Amendments.535 A 1977 Report by 

the National Academy of Sciences warned that average 

 

532 “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.”).

533 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”).

534 1970 CAA Legis. Hist. at 244, 257 S. 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.”). 

535 122 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”).
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temperatures would rise due to the burning of fossil fuel.536 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 GHG emissions and asserted that as a result of those 

emissions, the climate was in fact already changing.537

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 RE

measures would achieve those reductions. Senator Fowler, the 

author of the provision that established a RE technology reserve 

within the allowance system, noted that RE technologies, “can 

 

536 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).

537 S. Rep. No. 101-228, at 322 (Dec. 20, 1989), at 1990 Legis. 

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 GHGs will 

lead to catastrophic shocks in the global climate system.”); 

History, Jurisdiction, and a Summary of Activities of the 

Committee on Energy and Natural Resources During the 100th

Congress, S. 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-warminghas-begun-expert-tells-senate.html.
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greatly reduce emissions of ... global warming gases. That makes 

them a potent weapon against catastrophic climate change....”538

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.539

(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 

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).540 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 

 

538 Sen. Fowler, S. Debate on S. 1630 (Apr. 3, 1990), 1990 CAA 

Legis. Hist. at 7106.

539 1990 CAA Amendments, § 821, 104 Stat. at 2699.

540 70 FR 28606 (May 18, 2005).
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choosing among a set of measures that included shifting 

generation to lower-emitting units.541 CAMR was vacated by the 

D.C. Circuit on other grounds,542 but it shows that in the only 

other section 111(d) rule that the EPA attempted for affected 

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),543 in which it set statewide emission budgets for 

NOx and SO2 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 loweremitting generation which can be achieved by 2012.”544 The EPA 

developed a federal implementation plan (FIP) that established a 

 

541 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.”).

542 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).

543 76 FR 48208 (Aug. 8, 2011).

544 76 FR at 48452.
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trading program to meet the state-wide 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 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.”545 The U.S. Supreme Court upheld CSAPR in EPA v. EME 

Homer City Generation, L.P.546

With respect to RE, in 2004, the EPA provided guidance to 

states for adopting attainment SIPs under CAA section 110 that 

include RE measures.547 Some states have done so. For example, 

 

545 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 

Interstate Rule (CAIR) (2005), which similarly established 

standards based on analysis of the availability and cost of 

emission reductions achievable through the use of add-on 

controls and generation shifting, and also authorized and 

encouraged the implementation of RE and demand-side EE measures. 

CAIR: 70 FR 25162, 25165, 25256, 25279 (May 12, 2005) (allowing 

use of allowance set-asides for renewables and energy 

efficiency); NOx SIP Call: 63 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).

546 134 S. Ct. 1584 (2014).

547See, 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 
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Connecticut included in its SIP reductions from solar 

photovoltaic installations.548 In 2012, the EPA provided 

additional guidance on this topic.549 In addition, the EPA has 

partnered with the Northeast States for Coordinated Air Use 

Management (NESCAUM) and three states (Maryland, Massachusetts, 

and New York) to identify opportunities for including RE in a 

SIP and to provide real-world examples and lessons learned 

through those states’ case studies.550

(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 

sources. This section summarizes some of those actions. First, 

 

Implementation Plan (SIP) (Sept. 2004), 

http://www.epa.gov/ttn/oarpg/t1/memoranda/evm_ievm_g.pdf. 

548 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_rep

orts/section_8.pdf).

549 “Roadmap for Incorporating EE/RE Policies and Programs into 

SIPs/TIPs” (July 2012), 

http://epa.gov/airquality/eere/manual.html.

550 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-rept-toepa-ee-in-naaqs-sip-roadmap-case-studies-20140522.pdf.
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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 trading of mass-based emission allowances or rate-based 

emission credits, in which many sources meet their emission 

limitation requirements by purchasing allowances or credits from 

other sources that reduce emissions.

(a) Third-party transactions. 

To reiterate, 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 

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 
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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.551 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 arrange 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 

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 

 

551 70 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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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. 

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 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 

credits. As a result, the 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 integrated 
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into their own design or operations, but rather by purchasing 

allowances or 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 

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. 

They include the acid rain trading program in Title IV of the 

CAA, the trading programs in the 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 purchase of those allowances to meet their 
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obligations.552 For the reasons just described, these trading 

rules refute commenters’ arguments for limiting the scope of the 

“system of emission reduction.”

(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 

 

552 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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features of power transmission along the interconnected grid and 

the unique commercial relationships that rely on those 

features.553

Additionally, in 1982, the EPA recognized that utility turbines 

could meet a NOx emission limit without unacceptable economic 

consequences because “other electric generators on the grid can 

restore lost capacity caused by turbine down time.”554 We 

describe the relevant parts of these rules in greater detail in 

the Legal Memorandum. 

(7) Consistency with the purposes of the Clean Air Act. 

Interpreting the term “system of emission reduction” 

broadly to include building blocks 2 and 3 (so that the “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 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 

 

553 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”).

554 47 FR 3767, 3768 (Jan. 27, 1982).
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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 

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;
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(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 

pollution”555 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 

 

555 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). 
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any significant danger to public health or welfare.”556

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 

after World War II,557 as nothing short of a national crisis.558

 

556 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)).

557 See Dewey, Scott Hamilton, Don’t Breathe the Air: Air 

Pollution and U.S. Environmental Politics, 1945-1970 (Texas A&M 

University Press 2000).

558 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 
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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 --

including the precursors for the choking smog that blanketed 

urban areas559 --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”560 and including within the 1970 

 

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.

559 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.”).

560 Train v. NRDC, 421 U.S. 60, 64 (1975).
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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 

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.”561

Similarly, the 1977 and 1990 CAA Amendments were also 

designed to respond to new and/or pressing environmental issues. 

 

561 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)). Note that in 

the 1977 CAA Amendments, the House Committee Report made a 

similar statement. 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 EPA 

to study and then take action to regulate radioactive air 

pollutants and three other air pollutants).
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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.”562 Similarly, by 1990, Congress recognized that “many of 

the Nation’s most important air pollution problems [had] failed 

to improve or [had] grown more serious.”563 Indeed, President 

George H. W. Bush said that “‘progress has not come quickly 

enough and much remains to be done.’”564

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 

 

562 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, 

visibility protections, requirements for nonattainment areas, 

and stratospheric ozone provisions.

563 H.R. Rep. No. 101-490, at 144 (May 17, 1990).

564 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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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.

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.565 This 

interpretation is also consistent with the cooperative purpose 

of section 111(d) to assure that the CAA comprehensively address 

 

565 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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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 

fair reading of legislation demands a fair understanding of the 

legislative plan.”).566

(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 

 

566 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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“[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 

Pollution Prevention and Control.”567 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.568

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 

 

567 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).

568 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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produced or created at the [fossil fuel-fired affected] 

source[s].” Thus, consistent with the CAA’s primary goals, it is 

therefore reasonable to interpret a “system of emission 

reduction,” as including the pollution prevention measures in 

building blocks 2 and 3.

(c) Purpose of advancing technology to control air 

pollution.

This final rule is also consistent with CAA section 111’s 

purpose of promoting the advancement of pollution control 

technology based on the expectation that American industry will 

be able to develop innovative solutions to the environmental 

problems.

The legislative history and case 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);569

(ii) the expanded use of the best demonstrated technology;570 and 

 

569 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”).

570 See S. Rep. No. 91-1196, at 15 (“The maximum use of 

available means of preventing and controlling air pollution 
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(iii) the development of emerging technology.571 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 substantial reductions at reasonable 

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 111 should promote technological innovation. 

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 

 

is essential to the elimination of new pollution 

problems”). 

571 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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man on the moon a year before 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.572

(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.”573 Commenters with this line of comments focused on 

the ramifications 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 

 

572 Sen. Muskie, S. 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 

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).

573 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 Reg. Group v. EPA, 134 S. Ct. 2427, 2444 

(2014).
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respect to building block 4 measures, they are certainly not 

accurate with respect to the three building blocks that the EPA 

is defining as the BSER. This rule would be 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 bold,

far-reaching law designed to address comprehensively an air 

pollution crisis that threatened the health of millions of 

Americans; to have EPA and the States work cooperatively to 

develop state-specific approaches to address a national problem; 

to challenge industry to meet that crisis with creative energy; 

and to 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 (generation shifts and RE), 

and that explicitly acknowledged that those measures (RE) would 

also reduce CO2 and thereby address the dangers of climate 
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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). 

(8) Constraints on the BSER – treatment of building block 4 

and response to comments concerning precedents.

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 our 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 for other sectors.574

As discussed above, the emission limits in the CAA section 

111(d) emission guidelines that this rule promulgates are based 

 

574 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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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 and provide constraints on the types of 

measures or controls that the EPA may determine to include in 

the BSER. 

(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 

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.
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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 

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 
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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. 

Building blocks 2 and 3 entail the production of the same amount 

of the same product -- electricity, a fungible 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 low capacity for storage. 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. 
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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 a wide variety 

of reasons, many 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 well-established 

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 RE.

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 

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. 
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As 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; or by “requiring there 

to be more electric vehicle purchases,” which the commenters 

considered analogous to building block 3.575

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 

 

575 UARG comment at 2-3.
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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. The hypotheticals appear to be premised on 

government action 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 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.576

(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, 

 

576 In any event, it is questionable whether measures such as 

those hypothesized by the commenters would be consistent with 

the provisions of Title II. 
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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.577 In 

interpreting and applying these provisions in this rulemaking to 

regulate CO2 emissions from affected EGUs under section 111(d), 

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 

 

577 See Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 

Cir. 1999).
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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 

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, PM, 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 
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to create power supply disruptions.”578,579 EPA has taken the same 

overall approach in its section 111(d) rules,580 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 

 

578 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.

579 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.

580 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 RE, for compliance purposes. 

While these and other rulemakings for fossil fuel-fired 

EGUs took different approaches towards lower-emitting generation 

and renewable generation, they all were based on control 
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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 RE. 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 

Co. v. Connecticut, that the CAA and the EPA actions it 

authorizes displace any federal common law right to seek 
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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.”581

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.”582 This 

exercise of policy discretion is consistent with Congress’s 

expectation that the Administrator “should determine the 

achievable limits”583 and “would establish guidelines as to what 

the best system for each such category of existing sources 

 

581 American Electric Power Co. v. Connecticut, 131 S. Ct. 2527, 

2539-40 (2011).

582 Sierra Club v. EPA, 657 F.2d 298, 406 (D.C. Cir. 1981). 

Id. at 406 n. 526.

583 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 

operator determine the most economic, acceptable technique to 

apply.”).
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is.”584 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.”585

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.”586

This principle is also consistent with promoting “reasonable ... 

governmental actions ... for pollution prevention.”587

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 

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. 

 

584 H.R. Rep. No. 95-294, at 195 (May 12, 1977).

585 Sierra Club v. Costle, 657 F.2d 298, 330 (D.C. Cir. 1981).

586 CAA section 101(b)(1).

587 CAA section 101(c).
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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 EE 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. 

Excluding demand-side EE 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 
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household in the land.”588 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 EE 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.589

(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 

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 

 

588 See Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2436 

(2014).

589 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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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 

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, 
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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 

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 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, 
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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 

refining our approach to the BSER. Specifically, we are 

determining the BSER as the combination of measures included in 

building blocks 1, 2, and 3.Building blocks 2 and 3 entail 

substitution of lower-emitting generation for higher-emitting 

generation, which ensures that aggregate production levels can 

continue to 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 

determines a portion of the amount of reduced generation that 

affected fossil fuel-fired steam EGUs could undertake to achieve 

building block 2, and the amount of generation from the use of 

expanded lower- or zero-emitting generating capacity that could 

be provided, determines a portion of the amount of reduced 

generation that affected fossil fuel-fired steam EGUs, as well 

as the entire amount of reduced generation that affected NGCC 
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units could undertake to implement building blocks 2 and 3. This 

section discusses the reasons that reduced generation is one 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 

product produced rather than producing the same product with a 

process that has fewer emissions. 

a. Background. As noted, for both rate-based and mass-based 

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 

CO2 per MWh) by acquiring, through one means or another, credits 

from lower- or zero-emitting generation (building blocks 2 or 3) 

to reduce its 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 emission rate.590 Under these circumstances, the affected EGU 

 

590 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 
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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 a mass-based standard -- for 

example, a requirement to 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. Further, reduced generation by 

individual sources offers a pathway to compliance in and of

itself. That is, a state may adopt a mass-based goal, assign 

mass-based standards to its sources, and those sources may 

comply with their mass-based limits by, in addition to 

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. 

 

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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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 

system operators coordinate, control, and monitor the electric 

transmission grid to ensure cost-effective and reliable delivery 

of power. These system operators continuously 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 
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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 operated 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 operators have 

a number of resources potentially available to meet electricity 

demand, including electricity generated by electric generation 

units of various types as well as demand-side resources. 

Importantly, 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 
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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 

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 an EGU was 

expected to rely on to achieve its emission limitations. 

Examples 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.591

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.”592 Both the statutory factors and the 

regulatory definition resemble the definition of the BSER under 

 

591 CAA section 169A(g)(2).

592 40 CFR 51.301.
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CAA section 111(a)(1) (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 coalfired boilers that served as peaking units was caps on baseline 

emissions rates and annual capacity factors of 5 percent and 10 

percent, respectively.593

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, there are numerous 

examples of EGUs that take restrictions on hours of operation in 

their permits for the purpose of avoiding CAA obligations, 

including avoiding 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 HAP 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 

 

593 77 FR 24794, 24810 (Apr. 25, 2012).
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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.594

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.595

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 

 

594 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).

595 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.pdf 

(“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). 
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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,”596 or “legally and 

practicably enforceable by a state or local air pollution 

control agency.”597 The regulations for other air programs 

similarly recognize that potential to emit may be limited 

through restrictions on hours of operations in their 

corresponding definitions of “potential to emit.”598 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.599

 

596 40 CFR 52.21(b)(4)(emphasis added).

597 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.

598 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 Title V operating permit programs), 

and 63.2 (addressing hazardous air pollutants).

599 See, e.g., 40 CFR 52.21(b)(4). 
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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 Title 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 Title V threshold of 100 tpy, and 

carbon monoxide, NOxand SO2below the PSD threshold of 250 tpy.600

As another example, Sunbury Generation LP in Pennsylvania 

obtained a minor new source preconstruction permit, called a 

plan approval, for a repowering project from the Pennsylvania 

 

600 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 

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.”).
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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.601 The Legal Memorandum includes 

numerous other examples of power plants accepting permit limits 

that reduce generation to meet, or avoid the need to meet, 

emission limits.

There are several ways that an affected EGU may implement 

reduced generation. 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 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 

 

601 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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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 to reduce their CO2 emissions by means of 

reducing their generation.

Reduced generation by affected EGUs, in the amounts that 

affected EGUs may rely on to implement 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 if 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 
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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 and are of reasonable cost 

for the affected source category and the nationwide electricity 

system.602 All these results come about because the operation of 

the electrical grid through integrated generation, transmission, 

and distribution networks creates substitutability 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 

substitutability increases over longer timeframes with the 

 

602 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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opportunity to invest in infrastructure improvements, and as 

noted elsewhere, this rule provides an extended state plan and 

source compliance horizon. 

d. 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.”603 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. Building 

blocks 2 and 3 entail substitution of lower- or zero-emitting 

generation for higher-emitting generation, and one 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 in and of itself (and 

therefore reduced generation of the product overall, 

electricity) as the BSER. Rather, the BSER is, in addition to 

building block 1, the substitution 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 numerous methods that affected EGUs may employ to achieve 

 

603 EEI comment, at 284.
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or help achieve the emission limits established by these 

emission guidelines.604 The commenter’s concerns over a perceived 

lack of a limiting principle cannot be taken to mean that 

reduced generation by higher-emitting EGUs cannot be considered 

to be 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 

 

604 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 

neighbor companies during a pollution incident and return this 

borrowed power at some later date.” Id. at 187. 
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reduced generation 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 3.605

Finally, 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 

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 

 

605 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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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 is not 

easily transferrable to another industry.

6. 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 RE

and implementation of a broad range of state and utility demandside EEprograms. 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 Air Regulatory Group v. EPA 
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(UARG)606 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.”607 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 extent 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 

emission guidelines, which generally take the form of emission 

rates applicable to the affected sources. In this case, the EPA 

 

606 134 S. Ct. 2427 (2014).

607 Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427, 2444 

(2014) (citations omitted).
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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 

standards of performance and, in doing so, retain significant 

flexibility 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 

equivalent mass-based emission standards. The sources, in turn, 

are required to comply with their emission standards, and may do 

so through any means they choose. Alternatively, the state may 

adopt the state-measures 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 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. 
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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 ratebased or mass-based emission limit -- implementation of demandside EE measures to natural gas co-firing.608

As some indication of the diverse set of actions we expect 

to comply with the requirements of this rule, we note that 

demand-side EE 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 reduction in the electricity sector.609 In 

addition, we note that the nine RGGI states -- Connecticut, 

Delaware, Maine, Maryland, Massachusetts, New Hampshire, New 

 

608 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.

609 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.
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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.610 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 

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). 

 

610 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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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, the 

EPA is neither requiring nor authorizing the states to regulate 

non-affected EGUs in their CAA section 111(d) plans.611

Moreover, contrary to adverse comments, this rule does not 

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 and imposing ratebased 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 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.

 

611 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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It is certainly reasonable 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 EGUs, 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.

This basic fact that EPA regulation of air pollutants from 

affected EGUs invariably affects the utility sector is wellrecognized 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 
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the energy sector.612 The Courts have recognized that, too. The 

U.S. Supreme Court, in its 2011 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.” § 

 

612 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:

[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 Legis. Hist. 1371; H.R. Rep. No. 95-294, 

95th Cong., 1st Sess. 188 (1977), 4 Legis. Hist. 

2465.]
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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). 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), 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)-

(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.613

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 

 

613 American Electric Power Co. v. Connecticut, 131 S. Ct. 2527, 

2539-40 (2011).
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is, after all, a national standard with long-term 

effects.614

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 

economic policy.”615 This rule has “economic, environmental, and 

 

614 Sierra Club v. EPA, 657 F.2d 298, 330 (D.C. Cir. 1981). 

615 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 meteorological 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 
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energy” impacts, as Congress and the Courts expect in a CAA 

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 BSER616 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 

 

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.

616 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 EE), they request that those measures be available 

for compliance, which indicates their interest in implementing 

those measures.617

We expect that many sources will choose to comply with 

their emission limits through the measures in building blocks 2 

and 3, 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, 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 

 

617 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.”).
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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, coalfired generation declined at a 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 EE.

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 because 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 because, according to the Court, the EPA 

acknowledged that Congress did not intend that such sources be 
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subject to the PSD requirements.618 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 RE 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 category 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 result, 

those entities will not come under CAA jurisdiction619 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, 

 

618 Util. Air Reg. Group v. EPA, 134 S. Ct. 2427, 2443 (2014).

619 States may regulate non-affected EGUs through a state 

measures approach, but those regulations would not be federally 

enforceable.
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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.620 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 

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 

 

620 ACC et al. (Associations) comments at 40, Luminant comments 

at 89.
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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 

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 
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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, 

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 2023.621

 

621 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.
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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.622 

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 

 

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.

622 In addition, because the section 111(d) requirements are 

phased in, states may choose to apply a gradual phase-in of the 

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 section 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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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) 

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.623 In addition, states have the discretion to allow their 

 

623 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 
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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 

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 

 

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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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 

constrain.624 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 

 

624 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.
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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.625

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 

 

625 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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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 

improve heat rate at coal-fired steam EGUs. 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 

EGUs 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.626 In 2012, the generation-weighted 

average annual heat rate of the 884 coal-fired EGUs included in 

EPA’s building block 1 analysis was approximately 9,732 Btu per 

 

626 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.
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gross kWh.627 Because an EGU’s CO2 emissions are driven primarily 

by the amount of fuel consumed, improving (i.e., decreasing) 

heat rate at a coal-fired EGU inherently reduces the carbonintensity of generation.

As discussed above in section V.A and in the June 2014 

proposal,628 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.

 

627 Similarly, within each interconnection, the generationweighted average annual heat rates for those coal-fired EGUs in 

our study population were 9,700 Btu per gross kWh (Eastern); 

9,888 Btu per gross kWh (Western); and 9,789 Btu per gross kWh 

(Texas).

628 See, e.g., 79 FR 34830, 34859 (June 18, 2014).
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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 

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. 
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In the proposal, we used two approaches to analyze the 

variability of an EGU’s gross heat rate using a robust dataset 

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 
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an “equipment upgrade” or “best practice,” such as optimizing 

soot blowing with intelligent systems, using CO monitors for 

optimizing combustion, or applying air heater and duct leakage 

controls. 

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 

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. 
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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 study629 (S&L) and other industry reports and studies. Many 

of these 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 

improvement regionally, within the Eastern, Western and Texas 

Interconnections.630

 

629 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/documents/ipm/coalfired.pdf.

630 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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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 performance” approach; and (3) the “best historical 

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 
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final determination for each region on the value for that region 

supported by all three approaches.

The “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 percent631). Thus, for 

example, one bin would 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 

 

631 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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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) 

during any consecutive two-year period.632 We compared the hourly 

gross heat rate data within each bin to the EGU’s benchmark 

value. Similar 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.633 We refer to this 

percentage improvement value as the “consistency factor,” 

 

632 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.

633 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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because applying it results in values for heat rate that are 

more consistent with the EGU’s benchmark for that bin. In our 

proposal we evaluated 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 

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.634 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. 

The net result was an improved gross heat rate reflecting what 

that EGU would have achieved between 2002 and 2012 if, under 

certain ambient temperature and capacity factor conditions, the 

 

634 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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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 historical average gross heat rate. We 

chose 2012 as the year of comparison because 2012 was 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.635

In addition to the statistical approach described above, we 

employed a “best historical performance” approach refined from 

 

635 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.
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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.636 We then calculated the differences 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.637

Finally, we employed the “best historical performance under 

similar conditions” approach, which combines aspects of the 

other two approaches. First, as with the “efficiency and 

consistency improvements under similar conditions approach,” we 

 

636 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.

637 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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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 bins.638 Similar to the “best 

historical 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.639

As in the proposal, we additionally analyzed the data with 

our analytical approaches using one-year averaging periods in 

 

638 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.

639 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.
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place of the two-year averaging periods described above.640

However, because our conservative overall methodology adopts the 

lowest value that is identified for a region by any of our 

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 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) 

 

640 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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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%

Best historical 

performance 4.1% 2.6% 4.2% 3.1% 6.3% 4.9%

Best historical 

performance under 

similar conditions

4.7% 3.1% 4.9% 3.5% 6.9% 5.3%

Accordingly, we have concluded that a 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 
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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 and best practices. Some EGUs may have faced 

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 can at least 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 supporting the final CPP.

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 
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through heat rate improvements is similar to the way EPA 

ordinarily approaches standards of performance.641

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;642 only that these heat 

 

641 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 

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. 

642 Examples of the many types of best practices and equipment 

upgrades available to coal-fired EGUs include adopting sliding 

pressure operation to reduce turbine throttling losses; 

installing intelligent sootblowing system software; 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 identify potential areas for improved 

performance; developing heat rate improvement procedures and 
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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 

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 

 

training O&M staff on their use; aligning the cycle to isolate 

or capture high-energy fluid leakage from the steam cycle; 

repairing utility boiler air in-leakage; performing utility 

boiler chemical cleaning; installing condenser tube cleaning 

system; retubing condenser; repairing/upgrading flue gas 

desulfurization systems; cleaning air preheater coils; 

adjusting/replacing worn air heater seals; replacing corroded 

air heater baskets; replacing feed pump turbine steam seals; 

overhauling 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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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 corresponding mass-based 

and rate-based state goals. 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, 

affected 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 

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 
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Interconnection, and 2.3 percent in the Texas Interconnection.643

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 

the final rule, have made refinements to our methodology, as 

described above and explained in more detail in the 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 

 

643 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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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 

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 a significant fraction of the 
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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 approximately 

$23 per ton of CO2 removed, as described in detail in the GHG 

Mitigation Measures TSD supporting the final CPP.644 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 Chapter 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 coalfired EGUs in the Eastern, Western and Texas Interconnections, 

respectively, can achieve at a reasonable cost.

3. Response to key comments

 

644 The $100/kW cost figure from the proposal is now particularly 

conservative because it 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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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 

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. However, 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 unitspecific 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 
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random and atypical variations in the data on the overall 

averages, and would thus decrease our confidence in the results.

Furthermore, as a practical matter, states are free to apportion 

reductions in a way that reflects any subcategories of their 

choosing when determining the emission standards for individual 

affected EGUs. 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 further discussion of our reasonable decision not to 

subcategorize among coal-fired EGUs for purposes of determining 

building block 1, see the GHG 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 
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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 

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 affected EGUs based in part on the 
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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 

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. Our 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 
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from upgrades are double-counted within the data used to 

determine heat rate improvements from best practices; and that 

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 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. 
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However, we recognized that the 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 equipment upgrades that were at some point 

achieved by an EGU, but not for the full range of best 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 

unit to that unit’s own performance. By assessing potential heat 
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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 availability of a 

comprehensive dataset of nationwide hourly ambient air 

temperature, and the similar explanatory power of surface water 

temperature and ambient air temperature, it is unlikely that 

separately addressing cooling water temperature would 
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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 GHG Mitigation Measures TSD supporting the 

final CPP for further details about this analysis. As described 

further in that 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 

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.
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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 EPA’s analysis of heat rate improvement potential in the 

applicable region as a guide, while keeping in mind the CO2

emission performance rate. This broad-based approach is 

consistent with the traditional rules evaluating the potential 

for emission reductions on a source-category 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. 

Accordingly, affected EGUs in regions not setting the national 

level have emission reduction opportunities beyond those 

reflected in the applicable performance rate. 

The heat rate improvement measures comprising building 

block 1 would ordinarily be evaluated on a nationwide basis. 
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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 that region. This ensures that the BSER for 

each region is representative of the characteristics and 

opportunities available within that region, rather than a less 

logical combination of opportunities 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 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 systemic 

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, 
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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, 

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 EPA to develop a comprehensive, unit-by-unit heat rate 

improvement study of nearly 900 coal-fired EGUs from scratch, it 

would likely cost the Agency $50,000 to $100,000 to study each 

EGU (almost $50 to $100 million total) and require three to four 

years to complete. Such a granular analysis would not serve the 

broader goal-setting purpose of this rulemaking. We agree with 

commenters who have pointed out that a heat rate improvementestimating effort of that magnitude and duration would be 

unnecessarily lengthy and expensive. Nor would such a granular 
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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-byunit hourly 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 
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factors of coal-fired EGUs, and thus increase, not decrease, 

their heat rates.

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 
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equipment required to operate the EGU itself. By contrast, net 

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.645

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 

 

645 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 2025.646 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 

increase in net heat rate due to power required to operate new 

 

646 When considered on a regional basis, we expect these controls 

to impact heat rate by approximately 0.3 percent in both the 

Eastern and Western Interconnections, and by less than 0.1 

percent in the Texas Interconnection.
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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 GHG

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 

practices or equipment upgrades. In addition, commenters are 
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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 are confident that 

the values adopted for building block 1 are conservative and 

reasonable estimates of the potential for heat rate improvement 

in each region. Some changes in monitoring methodology would 

have the result of tending to cause us to underestimate the 

potential for heat rate improvement. Furthermore, because our 

methodology analyzes percentage heat rate improvement based on 
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2012 gross heat rate data, our results are unaffected by EGUs 

that used more accurate monitoring methodologies 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.647

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 

lower CO2 emissions while accommodating future changes to 

monitoring methodologies. For 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 

 

647 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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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 GHG 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 

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.
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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 the 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 section 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 

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 
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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. 

1. Demonstration of ability to reduce CO2 emissions through 

shifting generation 

a. Background of utility power sector. The ability to shift 

generation from higher- to lower-emitting sources is compatible 

with the way EGUs are generally dispatched.648 The standard 

approach to dispatching generation is through Security 

Constrained Economic Dispatch (SCED), a well-established 

 

648 See preamble section II.C.1, History of the Power Sector, for 

background to this discussion.
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practice in the electric power industry.649 As the name 

indicates, SCED has two defining components: economic operation 

of generating facilities and assurance that the electric system 

remains reliable and secure.650 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,” in which units 

are committed to be ready to provide generation to the system 

when they will be needed – and then dispatched in real time to 

meet the electricity demand of the system. Overall changes in 

the level of generation from different facilities are also 

planned over time periods longer than this 2-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 

 

649 “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.

650 “Security Constrained Economic Dispatch: Definitions, 

Practices, Issues and Recommendations: A Report to Congress”, 

Federal Energy Regulatory Commission, July 31, 2006.
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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 the magnitude and timing of their output 

generally depend on wind and sun conditions rather than the 

operators' discretion. In contrast, fossil fuel-fired EGUs have 

higher variable costs and are also relatively flexible to 

operate. Fossil fuel-fired EGUs 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 fuel-fired 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 
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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. 

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 NGCC units, 

both as a result of construction of additional NGCC units, and 

also as a result of dispatch of pre-existing NGCC units at 

higher capacity factors. As a result, generation 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.651 As we demonstrate in 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 

 

651 Ventyx Electric Power Database.
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NGCC units in recent years and is expected to continue to retire 

coal capacity and add new NGCC capacity. In the reference case 

without implementation of CO2 emission limitations, EIA forecasts 

40 GW of coal retirements and 53 GW of NGCC capacity additions 

from 2014 to 2030.652 An EPA review of state Integrated Resource 

Plans (IRPs) shows a pattern of shifting away from coal steam 

capacity to NGCC capacity and, in some cases, 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.653

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 

 

652 Energy Information Administration, Annual Energy Outlook 2015 

reference case, ref2015.d021915a.

653 For further examples, see the memo entitled “Review of 

Electric Utility Integrated Resource Plans” (May 7, 2015) 

available in the docket.
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serve the remaining 25 percent.654 In states that have maintained 

traditional 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 ISOs or 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 

 

654 Regulatory Assistance Project, Electricity Regulation in the 

US: A Guide, Page 9, March 2011.
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type of control, can use this building block to comply with the 

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 

units will be dispatched less than they otherwise would without 
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such an allowance-holding requirement. The 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.655

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. 

Environmental conditions, such as compliance costs or limits on 

generation, can be factored in with fuel costs 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 

 

655 See the Regulatory Impact Analysis.
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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.656 These data show that most EGU generation relevant 

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. 

 

656 SNL Energy. Data used with permission. Accessed May 2015.
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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, 

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 
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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.

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.657 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 

 

657 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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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 

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. For 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. 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 higher-emitting EGU, in accordance with the 

plan under which it is operating. The amount of generation that 

could be shifted using the approaches described in this 
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paragraph will depend on the type and terms of the commercial 

arrangements, as 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 provides flexibility, both within a year and across 

multiple years, for EGUs to fashion these arrangements to fit 

their circumstances. 

Where permitted under its state plan, an EGU would also be 

able to meet its reduction obligations using ERCs or allowances. 

The particular nature of this alternative will depend on how a 

state elects to develop its plan. If a state chooses a massbased 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 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 ERCs. 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 ERCs that are 

produced by other sources whose emission rates are lower than 
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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 

ERCs that were produced from lower-emitting sources (see section 

VIII for more detail on how state plans can use an ERC approach 

to facilitate a rate-based compliance demonstration of this type 

of emission reduction).658

The approaches shown here collectively demonstrate that all 

steam generators -- regardless of size, 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. Amount 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 

 

658 Stakeholders have recognized that ERCs 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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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 

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. 
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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 EE, would be 

achievable on a phased-in basis between 2020 and 2029, 

reflecting the time needed for deployment.659 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 2.660

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 

 

659 79 FR 34866.

660 79 FR 64543.
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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). 

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 
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2012 and is equal to 22 percent.661 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 

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. 

 

661 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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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 by 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

conne

ction 988 735 896 941 988 988 988 988 988 988 988

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
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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 

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.662 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 

baseload roles at much higher annual utilization rates. Average 

annual availability (that is, the percentage of annual hours 

 

662 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.
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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.663

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.664 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 

 

663 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.

664 http://www.eia.gov/todayinenergy/detail.cfm?id=6990.
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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 

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.665

 

665 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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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. 

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.666 In 

effect, these plants were providing 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 spring and fall periods when electricity 

demand levels are typically lower, these plants were sometimes 

 

666 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).
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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. In 2012, roughly 10 percent of existing NGCC 

plants operated at annual utilization rates of 80 percent or 

higher on a 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 

reduce their need to rely on other emission reduction measures 

or building blocks.

b. Historical generation shifts to NGCC generation. In 2012, 

total electric generation from existing NGCC units was 966 
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TWh.667 After the application of the building block 2 potential 

(increasing NGCC utilization up to a 75 percent capacity factor 

on a net summer basis, including generation from NGCC units that 

were under construction), the total generation from these 

existing sources is assumed to be 1,498 TWh.668

The EPA believes that producing this quantity of generation 

from this set of NGCC units is feasible. To put this level of 

generation into context, NGCC generation increased by 

approximately 439 TWh (an 83 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 44 percent higher than 2014 levels. This reflects 

a smaller growth 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. Sources can achieve increases in utilization of 

existing NGCCs that displace generation from steam sources 

without impacting reliability because this shift in average 

annual utilization across existing EGUs does not inhibit the 

 

667 Appendix 1, CO2 Emission Performance Rate and Goal Computation 

Technical Support Document for CPP Final Rule.

668 Appendix 1, CO2 Emission Performance Rate and Goal Computation 

Technical Support Document for CPP Final Rule.
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power sector’s ability to maintain adequate dispatchable 

resources to continue to meet reserve margins and maintain 

reliability. Furthermore, sources are not required to achieve 

the exact or even the full extent of the building block 2 

generation shift itself, which means that sources will have 

ample flexibility to maintain reliability-relevant operations 

while achieving emission reductions through a variety of 

measures.669

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 potential 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 

 

669 See section VIII for further discussion of electric 

reliability planning.
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above their average utilization rates (which have recently been 

in the range of 40 to 50 percent).670 Fleet-wide combined-cycle 

average monthly utilization rates have reached 65 percent,671

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, the 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 competes with other sectors’ 

demands for natural gas), since increasing annual utilization of 

NGCCs could focus on non-peak periods when NGCC capacity factors 

are currently low.

 

670 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, 

http://www.eia.gov/todayinenergy/detail.cfm?id=14611 (for recent 

data).

671 EIA, Electric Power Monthly, February, 2014. Table 6.7.A.
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The 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.672 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 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, the pipeline industry 

projected that increases of up to 30 percent in total 

deliverability out of the pipeline system would be possible.673

There have been notable pipeline capacity expansions over the 

 

672 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).

673 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.
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past five years, and substantial additional pipeline expansions 

are currently under construction.674 Further, 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 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. 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 to allow NGCC utilization to increase up to an average 

annual capacity factor of 75 percent on a net summer basis.

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 

 

674 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.
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the current trends in the natural gas industry. The EPA expects 

the growth in NGCC generation assumed for 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 25 percent over that same timeframe 

(from 19.2 TCF in 2000 to 24.0 TCF in 2012). EIA’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 235 TWh from 

2012 to reach the level assumed for 2022, and that NGCC 

generation growth would result in increased gas consumption of 

less 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.
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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.

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. 
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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.

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 

quantified in building block 2.675 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 

 

675 See Greenhouse Gas Mitigation Measures TSD for a discussion 

of regional NGCC capacity factors.
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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.676 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 

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 

 

676 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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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. 

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 
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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.

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 ultimately 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 rates 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 
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meet electricity demand at the lowest total cost, 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 base case scenario. For the 

scenario reflecting a 75 percent NGCC utilization rate on a net 

basis with regional fossil generation shifting, comparison to 

the base case indicates that the average cost of the CO2

reductions achieved over the 2022-2030 period was $24 per short 

ton of CO2. 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 quantified 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 boundaries, the 

delivered natural gas price was projected to increase by an

average of 7 percent over the 2022-2030 period, which is well 
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within the range of historical natural gas price variability.677

Projected wholesale electricity price increases over the same 

period were less 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 the 

final rule’s compliance requirements for the following reasons. 

First, this analysis does not capture the building block 2 

phase-in, which assumes an average utilization rate over the 

interim period of less than 75 percent in all three 

interconnections. Second, the analysis overstates the extent to 

which building block 2 is ultimately reflected in the source 

category performance rates. While the performance rate 

computation procedure assumes a maximum NGCC utilization rate of 

75 percent on a net summer basis, the Eastern Interconnection’s 

 

677 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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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 Interconnection if they realized that maximum NGCC 

utilization rate in conjunction 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 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 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 
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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 3 of the GHG Mitigation Measures TSD for 

the CPP Final Rule.

5. Major comments and responses

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 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 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 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 
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supporting this analysis can be found in the Regulatory Impact 

Analysis.

Commenters also expressed 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 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.

Other comments object to the use of a single capacity 

factor for all existing NGCCs to quantify building block 2 

potential on the grounds that not all units may be able to 

achieve this utilization 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 
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generation from existing NGCC capacity, and it does not 

establish any individual unit requirements. 

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 

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 
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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, 

other units running in an intermediate mode can also provide 

load following and ramping.

E. Building Block 3 — New Zero-emitting 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 zero-emitting renewable electricity (RE) generating capacity 

to produce replacement generation. 
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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 ability 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 3, including key comments, changes made from the proposal, 

the method by which RE target generation levels are quantified, 

and the magnitude and timing of increases in RE generation 

associated with this building block. 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, sun 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.678

Following a series of energy crises, new federal organizations 

 

678 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.
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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.679

PURPA was a key step in stimulating RE development. By 

requiring utilities to purchase generation from qualifying 

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.680 In addition, since 1992, federal tax 

policy has provided important financial support via tax credits 

for the production of RE and investments 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 had enforceable RPS or 

 

679 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.

680 “Restructuring or Deregulation?" Smithsonian Museum of 

American History. Accessed March 2015. Available at: 

http://americanhistory.si.edu/powering/dereg/dereg1.htm.
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similar laws.681 These RPS requirements continue to drive robust 

near-term growth of non-hydropower RE.

2. Trends in RE Development

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 electronics allow wind turbines to provide voltage and 

reactive power control at all times).682,683

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 2005.684 In 2013, U.S. non-

 

681 Energy Information Administration, Annual Energy Outlook 2014 

with Projections to 2040, at LR-5 (2014).

682 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.

683 American Wind Energy Association. AWEA Comments on EPA’s 

Proposed Carbon Pollution Emission Guidelines for Existing 

Stationary Sources and Supplemental Proposed Rule. p. 107.

684 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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hydro RE capacity for the total electric power industry exceeded 

80,000 megawatts, reflecting a fivefold increase in just 15 

years.685 In particular, there has been substantial growth in the 

wind and solar photovoltaic (PV) markets in the past decade.

Since 2009, U.S. wind generation has tripled and solar 

generation has grown twentyfold.686

The global market for RE is projected to grow to $460 

billion per year by 2030.687 RE growth is further spurred by the 

significant amount of existing natural resources that can 

support RE production in the U.S.688 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.689 In the reference case, RE generation 

 

685 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 (EIA-860), 

Available at: http://www.eia.gov/electricity/data/state/. 

686 Energy Information Administration, Monthly Energy Review, May 

2015, Table 7.2b. Available at: 

http://www.eia.gov/totalenergy/data/monthly/pdf/sec7_6.pdf.

687 “Global Renewable Energy Market Outlook.” Bloomberg New 

Energy Finance, November 16, 2011, Available at: 

http://bnef.com/WhitePapers/download/53.

688 Lopez et al., NREL, ‘‘U.S. Renewable Energy

Technical Potentials: A GIS-Based Analysis,’’ (July 2012).

689 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at LR-5 (2014), P. 25.
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increases by more than 70 percent from 2013 to 2040 and accounts 

for over one-third of new generation capacity.690

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.691 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 

 

690 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at LR-5 (2014), P. ES-6-7.

691 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.692,693 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.694695 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.696 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 

current rating of the array’s inverter to increase energy 

 

692 “2013 Wind Technologies Market Report,” LBNL, August 2014. 

Available at: http://emp.lbl.gov/publications/2013-windtechnologies-market-report.

693 “2013 Cost of Wind Energy Review,” NREL, Feb 2015. Available 

at: http://www.nrel.gov/docs/fy15osti/63267.pdf.

694 “Tracking the Sun VII” LBNL, Sept 2014. Available at: 

http://emp.lbl.gov/publications/tracking-sun-vii-historicalsummary-installed-price-photovoltaics-united-states-1998-20.

695 “Photovoltaic System Pricing Trends,” NREL, 22 Sept 2014. 

Available at: http://www.nrel.gov/docs/fy14osti/62558.pdf.

696 “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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production and improve project economics.697 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.698 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 

 

697 “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.

698 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).699 A recent IPCC report also concluded that 

RE has large potential to mitigate CO2 emissions.700

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.701

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. Access to RE by Owners of Affected EGUs

The ability of affected EGUs to co-locate or obtain 

incremental RE to reduce CO2 emissions is well-demonstrated, 

 

699 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.

700 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.

701 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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whether it is through direct ownership, bilateral contracts, or 

procurement of the environmental attributes associated with RE 

generation.702 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.

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 

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 

 

702 Refer to the GHG Mitigation Measures TSD for additional 

information on RE ownership and co-location. 
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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 404 entities that owned part of at least one affected EGU 

under this rule, 178 also owned RE (biomass, geothermal, solar, 

water or wind). These 178 owners owned 82 percent of affected 

EGU capacity. As a whole, these entities’ share of RE capacity 

was equal to 25 percent of the total of their affected EGU 

capacity.703

Some of the largest owners of affected EGUs also owned RE 

(see Table 8). For example, NRG Energy, Inc. owns more than 

3,000 megawatts of RE capacity, over 20 percent of which (nearly 

800 megawatts) is solar, and almost 80 percent of which (over 

2,500 megawatts) is wind. Duke Energy Corporation owns 175 

megawatts of solar and over 1,500 megawatts of wind. NextEra 

 

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

2015. 
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Energy, Inc.’s share of RE capacity approaches 40 percent of 

their total affected EGU capacity.704 Table 8 lists a sampling of 

affected EGUs that have large amounts of fossil fuel-fired 

capacity and RE capacity:

TABLE 8. Sample of Owners of Affected EGUs and RE Capacity.705,706

Ultimate Parent Affected EGU 

Capacity (MW)

Renewable 

Capacity (MW)

NRG Energy, Inc. 48,787 3,149

Duke Energy Corporation 39,028 5,526

Southern Company 37,168 3,245

American Electric Power 

Company, Inc.

34,940 1,142

NextEra Energy, Inc. 29,471 11,626

Calpine Corporation 23,878 1,509

Tennessee Valley Authority 21,717 5,427

Berkshire Hathaway Inc. 18,899 6,650

FirstEnergy Corp. 16,175 1,371

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

 

704 Ibid. 

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

2015. 

706 eGRID, EPA. 2012 Unit-Level Data Using the eGRID Methodology. 

June 7, 2015 version.
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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 

of RE for their members. Federal power authorities own or 

contract for significant amounts of RE.707,708

The list of ten electric utilities with the largest amounts 

of wind power capacity on the system (owned 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 first and second with 5,736 

megawatts and 4,992 megawatts of wind capacity, respectively. 

Tennessee Valley Authority, a federal power authority, had 1,572 

megawatts and CPS Energy, a public utility, had 1,059 megawatts 

 

707 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.

708 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.
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of wind power capacity.709 Basin Electric Power Cooperative had 

716 megawatts and was the top 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). 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.710 For instance, Dominion plans for 

over 800 megawatts of wind and solar in their 2015 to 2029 

planning period.711 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 

 

709 American Wind Energy Association. U.S. Wind Industry Annual 

Market Report (2014 data). Accessed July 2015. Available at 

http://www.awea.org/AnnualMarketReport.aspx?ItemNumber=7422&RDto

ken=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.

710 See memo entitled “Review of Electric Utility Integrated 

Resource Plans” (May 7, 2015).

711 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.
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2029. A significant portion (1,670 megawatts) of the planned RE 

is solar.712 Ameren is planning to retire one-third of the coal 

generating capacity, as well as installing an additional 400 

megawatts of wind, 445 megawatts of solar, and 28 megawatts of 

hydroelectric generating capacity.713 

Independent power producers (IPPs) also can and do own both 

RE and fossil generation. For example, NRG 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).714

NRG has already reduced CO2 emissions from its fleet 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 

 

712 Duke Energy Carolinas’ 2014 Integrated Resource Plan, 

September 2014, Available at: 

http://starw1.ncuc.net/NCUC/ViewFile.aspx?Id=c3c5cbb5-51f2-423a9dfc-a43ec559d307. 

713 Integrated Resource Plan Update, October 2014, Available at: 

https://www.ameren.com/missouri/environment/renewables/amerenmissouri-irp.

714 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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that is replaced by RE also owned by the EGU owner is adequately 

demonstrated.

EGU owners can also replace fossil fuel-fired generation 

with RE through bilateral contracts and REC purchases, 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. Any type of EGU owner (utility or otherwise) can 

purchase and retire RECs. 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.

5. REC Markets

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. 

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 are associated with 

the generation of one megawatt-hour of RE and represent certain 

information or characteristics of the generation, called 
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attributes.715 RECs may be traded and transferred regardless of 

the actual energy flow. 

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 observed that states 

created RECs to facilitate programs designed to promote 

increased use of RE, and that “attributes associated with the 

[RE] facilities are separate from, and may be sold separately 

from, the capacity and energy.”716

In complying with states’ RPS requirements, utilities have 

contracted for RECs from in-state and out-of-state resources in 

accordance with RPS requirements. Utilities may have sourced 

RECs from out-of-state to reduce the cost of compliance, to 

 

715 EPA Green Power Partnership, Renewable Energy Certificates 

July 2008). Available at 

http://www.epa.gov/greenpower/documents/gpp_basics-recs.pdf. 

716 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).
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source RECs from specific generation types, or for other 

reasons.717

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 

fuel-fired generation with RE as an emission reduction measure.

6. Quantification of RE Generation Potential for BSER and Major 

Comments

The methodology for quantifying RE 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 quantifying RE 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, 

 

717 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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deliverability requirements, alternative compliance payments, 

and other policy elements made the regional averaging of statelevel 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 RE generation levels that may 

not be aligned with the opportunity to deploy incremental RE 

resources at reasonable cost. In contrast, commenters argued 

that a methodology similar to the alternative RE approach, which 

is based on economic potential, represents a more technically 

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, merits of total versus 

incremental RE generation as the metric by which building block 

3 generation levels are quantified, types of RE technologies 

that contribute to those 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 
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deploy, and application of a nationally uniform benchmark 

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:

 The 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 
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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 

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 U.S., including demonstrated RE technologies for which 

there is clear evidence of technical feasibility and costeffectiveness (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.
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 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 

quantifying an amount of expanded RE to replace generation 

at affected EGUs.718 Specifically, the generation levels 

under building block 3 include generation from capacity 

that commenced operation subsequent to 2012 (the 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 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), building block 3 

generation levels are quantified for each of the three BSER 

regions – the Eastern Interconnection, Western 

Interconnection, and Texas Interconnection – rather than at 

 

718 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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the state-level. This regionalized approach, as described 

in the NODA, takes into account the opportunity to develop 

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.

 Commenters observed that the cost and performance estimates 

the EPA relied on at proposal from the Energy Information 

Administration’s Annual Energy Outlook 2013 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 Berkeley National Laboratory, the 

Department of Energy (DOE) and Lazard. Each of these 

sources 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 

trends. In performing this task, the EPA revised its data 

for onshore wind and solar technologies to reflect the mid-
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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.719

 The benchmark development rate that constrained costeffective RE deployment under the alternative RE approach 

in the proposal has been removed from the final 

methodology.720 Commenters detailed several issues with 

applying the benchmark development rate, including that it 

does not factor in the total size of the RE resource in a 

given state and is inconsistent with a regional approach to 

quantifying target generation levels. EPA agrees with these 

 

719 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.

720 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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comments and the benchmark 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 3. 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 contains seven steps. Each step is described 

below.721

First, 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 

 

721 For supporting data, documentation, and examples for each 

step of the quantification methodology, refer to the GHG 

Mitigation Measures TSD.
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expected future performance from 2022 through 2030. For this 

purpose the 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 

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 

PV722

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 

 

722 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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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 

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 using 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 
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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.

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; 

system constraints such as interregional transmission limits, 
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partial reserve margin credit for intermittent RE installations, 

minimum turndown constraints for fossil fuel-fired EGUs, and 

short-term capital cost adders to reflect the potential added 

cost due to competition for scarce labor and materials; and 

technology constraints such as construction lead times and 

hourly generation profiles for non-dispatchable resources by 

season.723 Additionally, the EPA assumes in this analysis that 

deployment of variable, non-dispatchable RE resources 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.724 The 30 percent constraint applied to variable, 

non-dispatchable 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.725 For example, the Western Wind and Solar 

Study Phase 2 found cycling costs ranged from $0.14 to $0.67 per 

 

723 Refer to GHG Mitigation Measures TSD for more detail on 

modeling methodology.

724 Regions that have already exceeded these limits are held at 

historical percent of net energy for load.

725 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.726

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 

building block 3 generation levels for each interconnection from 

2022 through 2030.

TABLE 10. Building Block 3 Generation Levels (MWh). 

 

726 Refer to the GHG Mitigation Measures TSD for additional 

information on constraints related to deployment of nondispatchable RE.
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Year Eastern 

Interconnection

Western 

Interconnection

Texas 

Interconnection

2022 166,253,134 56,663,541 18,963,672 

2023 181,542,775 60,956,363 28,177,431 

2024 218,243,050 75,244,721 39,382,162 

2025 254,943,325 89,533,078 50,586,893 

2026 291,643,600 103,821,436 61,791,623 

2027 328,343,875 118,109,793 72,996,354 

2028 365,044,150 132,398,151 84,201,085 

2029 401,744,425 146,686,508 95,405,816 

2030 438,444,700 160,974,866 106,610,547 

Through 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 fiveyear 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 
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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 RE 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. 

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. 
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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 

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 
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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.

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 
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capacity factors higher among projects located in a given wind 

resource regime.727 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.

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 

 

727 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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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.

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 
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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 REwithout new infrastructure. 

First Solar’s Moapa project uses transmission built to deliver 

coal-fired power from Navajo to Los Angeles. NV 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 
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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 

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 RE Generation
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The EPA believes that RE generation at the levels 

represented in building block 3 can be achieved at reasonable 

costs. In the EPA’s modeling of the building block 3 generation 

level, the projected cost of achieving CO2 reductions through 

this expansion of RE generation is $37 per ton on average from 

2022 through 2030.728 There are a number of reasons why the EPA 

believes that the cost of CO2 emission reductions from RE 

generation will be lower than this analysis suggests. First, 

modeling constraints that restrict variable, non-dispatchable RE 

technologies to 30 percent of net energy for load at each of the 

64 U.S. IPM regions is a conservative limit intended to 

eliminate significant grid integration costs at increased levels 

of RE penetration. In fact, many regions have already 

demonstrated levels of RE penetration that exceed the 

constraints, and in practice intermittency can be managed across 

larger regions than the 64. Consequently, the extent to which 

these regions could, in practice, achieve higher levels of RE 

deployment without facing substantial grid integration costs 

would lead to a lower-cost RE outcome than is estimated by this 

analysis. Second, there are multiple RE technologies not 

quantified under building block 3 that affected EGUs may use to 

demonstrate compliance (distributed generation technologies, 

 

728 Refer to the GHG Mitigation Measures TSD for further analysis 

and IPM run results.
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offshore wind, etc.). 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 3.729 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 megawatt-hours of building block 3 

potential is not required to achieve the final CO2 emission 

performance rates in 2030 – and would be accessible to affected 

EGUs for compliance.730 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 

 

729 See Section VIII.K. for a description of qualifying RE 

technologies for compliance.

730 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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quantified building block 3 potential. The EPA believes that 

these factors provide significant opportunities for achievement 

of the building block 3 generation levels at lower costs than 

estimated in this analysis. 

VI. Subcategory-Specific CO2 Emission Performance Rates

A. Overview

In this section, the EPA sets out subcategory-specific CO2

emission performance rates to guide states in development of 

their state plans. The emission performance rates reflect the 

emission rates for two generating subcategories affected by the 

rule (fossil steam generation and gas-fired combustion 

turbines).731 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 subcategories instead of immediately blending them together 

into a single value for all affected EGUs. Commenters noted that 

 

731 The only natural gas fired EGUs currently considered affected 

units under the 111(d) applicability criteria are 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 combustion turbines as 

well as all associated heat recovery steam generating units. The 

remainder of the section will use the term “NGCC” to 

collectively refer to these natural gas fired EGUs.
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the proposed rule established guidelines that were based on the 

aggregation of units, and their reduction potential, in a state 

rather than providing technology-specific guidelines. 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 

previous interpretation of the 111(d) regulatory guidelines by 

not providing technology-specific standards of performance. In 

response to these comments and our further consideration, the 

final rule establishes subcategory-specific emission performance 

rates that are identical across units within a subcategory 

regardless of where a unit is located within the contiguous U.S. 

These subcategory-specific emission performance rates are then 

translated into state-specific 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 subcategory. 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 
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performance rates apply over a 2022-2029 interim period and 

would be achieved on average through 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 technologies as they scale up to their full 

BSER potential by 2030. The performance rates are meant to 

reflect emission performance required across all affected EGUs 

when averaged together and inclusive of lower-emitting BSER 

components. 

The performance rates are expressed in the form of 

adjusted732 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 EGUs within a state. 

 

732 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 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 Mitigation Measures TSD. Specific topics 

addressed in the various TSDs are noted throughout the 

discussion below. 

B. Emission Performance Rate Requirements
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The EPA has developed a single performance rate requirement 

for existing fossil steam units in the contiguous U.S., and a 

single rate for existing gas turbines in the contiguous 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 

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 11

below, followed by a description of the computation methodology. 

Table 11. 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

1,534 1,305

Stationary Combustion 

Turbines

832 771

The emission performance rates are expressed as adjusted 

output-weighted-average emission rates for each subcategory. As 

discussed later in this section, the emission rate computation 

includes an adjustment designed to reflect mass emission 
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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 for the baseline electricity generation and CO2 emissions 

from the higher-emitting affected EGUs. Under the final rule 

approach, regionally identified building block 3 potential 

generation replaces fossil steam and NGCC generation on a prorata basis corresponding to the baseline mix of fossil 

generation in each region.

2. Interim Emission Performance Rates

Some commenters suggested that the interim period starting 

in 2020 provided too little time for implementation of 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).
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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. 

C. Form of the Emission Performance Rates 

1. Rate-based guidelines

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, through application of 

the measures comprising the BSER (or alternative 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 RE 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 rate-based guidelines. First, the EPA sets an 

emission rate requirement for each subcategory by identifying 

the technology-specific reductions available under the building 

blocks. We then give each state the choice to apply the emission 
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performance rates directly to the affected EGUs within the state 

or provides the opportunity to use the statewide rate-based 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 and statewide mass-based goal are alternative metrics for 

realizing the emission performance rates at the aggregate 

affected fleet level for a state. 

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 guidelines that apply 

uniformly to technology subcategories nationwide, and the EPA is 

providing corresponding state emission rate goals and state mass 

goals to further 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 output733 –

 

733 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 
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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. The difference between net and gross generation is 

the electricity used at a plant to operate auxiliary equipment 

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 equipment necessary to collect 

and report hourly net generation.734

c. Output-weighted performance rates for all affected EGUs. 

This final rule provides an expression of the BSER as 

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 

 

requirement for affected EGUs to report hourly net energy 

output.

734 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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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 presenting them in a 

blended fashion at the state level.735 These two emission 

performance rates are the expression of the BSER for the final 

rule for affected EGUs located within the contiguous U.S. 

The modification from a blended emission rate in the 

proposed rule to a subcategory-specific emission performance 

rate for affected EGU categories in the final rule was made in 

response to comments that technology subcategory-specific 

emission rates were more analogous to prior 111(d) efforts and 

more consistent with the statute. The EPA received significant 

comments suggesting a technology subcategory-specific 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 

goals in the next section. 

 

735 However, as discussed 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. The sole exception, as described 

above, is 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 could be computed using 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 

Performance Rate and Goal Computation TSD for CPP Final Rule, 

which includes a numerical example illustrating the full 
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procedure. The quantification of the building blocks used in the 

computation procedure is discussed in Section V above and in the 

Greenhouse Gas Mitigation Measures TSD.

1. Inventory of likely affected EGUs

In order to calculate the subcategory-specific 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 affected 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.736 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 affected units at proposal comprised 

of approximately 3,000 EGUs. The agency took comment on this 

list and has made a number of updates to the inventory in 

response to those comments and in regards to applicability 

criteria changes resulting from comments. However, the inventory 

 

736 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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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.737

Since the final rule’s applicability includes under 

construction units, the EPA also identified units that had not 

yet commenced operation by 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 

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 

 

737 The EPA notes that in some cases, it may not yet be possible 

to determine the status of an EGU as affected or unaffected 

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 

collective changes to the affected fleet inventory will not 

yield a bias in the BSER computation at the regional level.
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data, comments, as well as NEEDS data to identify these under 

construction units.738,739,740 

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.741 

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 

 

738 The NEEDS database was also updated to reflect the latest 

data and commenter input on under construction units.

739 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”. Many of these “under construction” 

units have commenced operation at some point during 2012 or

prior to signature of this final rule.

740 “Commence” and “construction” are defined in 40 CFR 60.2.

741 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 

alternative compliance flexibility.
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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 representative 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 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 particular, the EPA 

issued a NODA on October 30, 2014 (79 FR 64543) in which we

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 
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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 an approach to the

baseline year where we still largely rely 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 commenter concerns with 

2012 data.742 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 

 

742 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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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 

not been in service at some point during the 2010-2011 

period. Likewise, approximately 17 GW of capacity that 

were operable in 2010 and/or 2011 were retired prior to 

2012.743 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 

 

743 EIA Form 860, 2012.
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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 

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 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). 
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4) Due to the region-based approach to quantify building 

blocks and the BSER as subcategory-specific emission 

performance rates, variations in unit-level 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, another 

fossil unit in the same region is generally operating 

more. Therefore, at the regional level, fossil generation 

and emissions do not vary to the same degree that unitlevel data varies. Moreover, the variation at the 

regional level that does exist in 2012 relative to 

previous years is not necessarily unrepresentative 

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.

5) Some commenters suggested the EPA use an earlier baseline 

year as a means of recognizing early action. They noted 
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that an earlier baseline would reflect a higher-emitting 

fleet and therefore when the same level of building block 

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 2 functions based on incremental 

generation potential (incremental generation = potential 

generation – baseline 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 
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considering typical unit-level behavior for allowance 

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 were lower in 2012 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 quantification of the 

BSER, because the building block is based on the emission 

reduction potential of the fleet. That potential (e.g., a 
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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 total 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:

1) Adjustments to state-level data to account for annual 

variation in the hydrologic cycle as it relates to fossil 

generation. 
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Hydropower plays a unique role in a handful of states in 

that 1) it is 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.744

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 state’s power fleet, variation in the 

hydrologic cycle does fundamentally change the generating 

potential of the state’s power fleet in hydro-intensive 

states as they 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 

 

744 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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for Idaho, Maine, Montana, Oregon, South Dakota, and 

Washington to better reflect fossil generation levels when 

hydro generation performed at its average level as observed

over a 1990-2012 timeframe. 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 

subcategory-specific performance rates reflecting BSER. 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 fossil-for-fossil 

substitutions. Unit-level variation does not inherently 

entail region-wide variation.

However, the EPA did receive comment that in limited cases, 

this could have a substantial impact on an individual state 

if it chooses to use a rate-based or mass-based statewide 

goal. Even though the EPA is calculating subcategoryspecific 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 converting 
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to state goals in the next section. The EPA examined units 

nationwide with 2012 outages to determine where an 

individual unit-level outage 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) decreased its output relative to preceding and 

subsequent years by 75 percent or more (signifying an 

outage), and 2) could potentially impact the state’s goal 

as it constituted more than 10 percent of the state’s 

generation was the Sherburne County Unit 3 in Minnesota. 

The EPA therefore adjusted this state’s baseline coal steam 

generation upwards 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 
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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 a more 

representative annual operating level for that type of unit

reflecting its incremental impact 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 project 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 increases the total generation 
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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.

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, 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.745

4. Equations

In this section we describe how we develop the equations 

used to determine the emission performance rates for fossil 

steam and NGCC units that express and implement BSER. More 

 

745 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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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. Here we first 

present the general principles we follow when developing 

equations to express the BSER; then, we summarize the steps 

taken to assemble baseline data to reflect 2012 baseline 

emissions and generation, and apply the building blocks that 

constitute the BSER to derive performance rates 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 in order to allow 

a state (at its discretion) to use a statewide goal as a 

mechanism for demonstrating compliance at the aggregate state 

level in a state plan, as an alternative to applying the 

emission performance rates to its affected EGUs 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 

standard. In the current context, this means recognizing that 
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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 

we issued under section 111(d) for landfill gas, for example, we 

adopted the primary standard based on flaring of any captured 
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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 

determination that pro rata implementation of building block 3

is the best reflection of the potential for RE to displace both 
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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 likely affected EGUs that had commenced operation prior to 

2012.746 The EPA made changes to the historical unit-level data 

 

746 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 

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 
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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 gas-fired 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 hydropower and unit outage concerns 

raised in comments and described above. As 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 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 

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 

 

heat capture) when demonstrating compliance. See the 

applicability criteria described in Section IV.D above. 
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percent capacity factor for under construction fossil steam 

units, which are consistent with the values and methodology the 

EPA proposed for under construction units.747 These values are 

informed by the 2012 capacity factors for other units in these 

technology classes that recently commenced operation.748 Using 

these capacity factors along with the capacity for the units, 

the EPA 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 

 

747 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.

748 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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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 

historical baseline total for each state that was reflective of 

all likely affected 111(d) sources.749

Step two (aggregation to the regional level). The EPA took 

comment on applying building blocks at the regional level, and 

received significant comment supporting such an approach. 

Therefore, whereas the proposal aggregated the baseline data to 

the state level, the final rule further aggregated 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 

 

749 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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building blocks and reflect the interconnected nature of the 

electric grid under a regional structure. The basis for the 

regions is defined and discussed in Section V.A.3.

Step three (identification of source category baseline 

emission rates). As discussed in the beginning of this section, 

the EPA took a technology-specific approach to 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 applied 

the building blocks at the regional level to give a separate 

fossil steam rate and NGCC rate for each region. The starting 

point for calculating the subcategory-specific emission 

performance rates was the baseline regional emission rates for 

both fossil steam and NGCC in the year 2012 with the 

modifications discussed above.

Step four (application of building block 1). The baseline 

CO2 emissions amount for the coal-fired steam EGU fleet 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 was 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 averaged together 
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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 1.750,751

Step five (application of building block 3). 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 3 in 

a manner more analogous to building block 2 treatment, where the 

incremental MWhs identified for the building block replace 

baseline fossil MWhs on a one-to-one basis. The EPA is adopting 

this replacement methodology for building block 3 in the final 

rule consistent with comments noting that such a computational 

procedure better reflects the reduction potential of that 

building block.

Under this methodology, all of building block 2 incremental 

NGCC potential and part of building block 3 incremental RE 

potential were ultimately applied to replace higher-emitting 

 

750 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.

751 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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fossil steam generation and emissions, while the remaining 

building block 3 potential was applied to replace NGCC 

generation and emissions. Commenters noted that under this 

approach building block 3 should be applied first, or the EPA 

would understate the potential of building block 2 by 

subtracting out some NGCC generation after the 75 percent 

utilization level of NGCC had been applied to replace fossil 

steam. The EPA agrees and calculated the building block 3

impacts first in developing the emission performance rates. 

To implement this, first, building block 3 replacement 

potential was identified for each region to arrive at a total 

amount of incremental zero-emitting generation hours available 

to replace fossil generation in the region. 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 to replace generation 

and associated emissions from each of the fossil steam and NGCC 

fleets in the region on a pro-rata basis in the following 

manner.752 The EPA determined the percent of fossil steam 

 

752 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.
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generation and the percent of NGCC generation of total affected 

fossil generation in each region’s baseline. We then assigned 

those percentages of the incremental zero-emitting MWhs to each 

of those technology source categories.753 The incremental zeroemitting generation assigned to each technology replaced the 

same amount of fossil generation from that technology’s baseline 

value. 

Step six (application of building block 2). If the 

remaining generation level for the NGCC fleet in a region, 

taking into account the previous step’s replacement of NGCC 

generation, was less than 75 percent of the fleet’s potential 

summertime generating capacity (the potential capacity factor 

the EPA determined to represent the BSER), then the NGCC 

generation in the region was assumed to increase to levels equal 

to the lesser of 1) its potential at a 75 percent capacity 

factor754 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 was 

 

753 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 in the baseline and 30 percent from NGCC units –

then 70 MWhs of the incremental zero-emitting generation are

applied to baseline fossil steam generation and 30 MWhs are

applied to baseline NGCC generation.

754 In early years, will be less than 75 percent due to building 

block 2 gradual deployment.
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only assumed to reach 75 percent if there was sufficient higheremitting fossil steam generation that it could replace after 

step five. The increase in NGCC generation at this step compared 

to the post-building block 3 level was matched by an equal 

decrease in fossil steam generation reflecting 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 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 and NGCC generation is reflected in the rates. 

Step seven (accounting 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 that will, as discussed 

above, (1) enable the implementation of all three building 
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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, 

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 
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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 

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 
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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 

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.755

Also as discussed above, it is important that the 

compliance equations reflect the BSER pro rata allocation of RE

to fossil steam and NGCC generation. The first approach to 

 

755 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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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 

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 
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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 multiplied the remaining fossil steam 

generation (post-step six) by the fossil steam rate reflecting 

the heat rate improvement from building block 1 (step four). We 

then added in the emissions associated with the incremental NGCC 

generation from step six by multiplying the incremental NGCC 

generation as discussed above (difference between the baseline 

NGCC generation level and post-step six NGCC generation) by the 

baseline NGCC rate for that region.756 This constitutes the 

numerator of the fossil steam emission rate.

For the fossil steam denominator, the EPA added the 

remaining fossil steam generation (post-step six), the 

incremental NGCC generation defined above, and the amount of 

zero emitting building block 3 MWhs apportioned to fossil steam 

generation in the region (step five). Dividing the fossil steam 

 

756 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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numerator described above by this fossil steam denominator 

resulted in a regional adjusted fossil steam rate reflecting the 

three building blocks. 

For the NGCC performance rate, the EPA calculated a 

numerator in a similar manner. First, we took the remaining NGCC 

generation (post step six) and multiplied 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 3 generation assigned to that technology in step 

five. Dividing the emissions by this total generation value 

(inclusive of the RE generation apportioned to NGCC) provided a 

regional adjusted NGCC rate.757 

Step eight (determining the nationwide subcategory-specific 

emission performance rate). 

 

757 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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Following step seven, we evaluated the resulting adjusted 

fossil steam rates and NGCC rates for each region and identified 

the highest (least stringent) emission rate among the three 

regions for each technology category. 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 repeated steps four through eight for each 

year 2022-2030.758 The resulting annual rates vary because the 

amount of building block 2 and 3 potential in each year varies. 

The rates for years 2022-2029 were 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 

 

758 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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specific requirements applicable to individual EGUs, to the EGUs 

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.

VII. State-Specific CO2 Goals

A. Overview

In section VI of this preamble, the EPA provides the 

methodology for computing subcategory-specific CO2 emission 
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performance rates, based on the BSER. The subcategory-specific 

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 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 massbased emission standards are not incented by dint of the massemissions 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 
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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 

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 proposed 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 
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of CO2 per year from affected EGUs), as long as the translated 

goal was equivalent 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: EPA-HQ-OAR2013-0602-22187) to further clarify potential methods for the 

translation to a mass-based 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 EPA’s 

efforts to allow states the maximum possible degree of 

flexibility in developing plans for their affected EGUs, either 

as a mass-based or rate-based CO2 goal. States and other 

stakeholders supported the option to translate rate-based goals 

to mass-based goals for state plans and requested a simple and 

transparent method for determining mass-based statewide CO2 goals 
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that are equivalent to statewide rate-based CO2 goals and thus 

reflective of the BSER. We received substantial 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 others requested flexibility to translate to mass using a 

variety of methodologies and tools. In the context of these 

comments, the EPA has considered the appropriateness of ratebased and mass-based goals as 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 translation methodology from the CO2 emission 

performance rates to yield statewide rate-based and mass-based 

CO2 emission performance goals 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.

CAA section 111(d) requires states to submit a plan that 

establishes standards of performance for affected EGUs that 
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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 

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 
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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 

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 
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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.759 Section VII.B. describes how the 

form of the rate-based state goals minimizes the risk of 

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.760

B. Reconstituting Statewide Rate-based CO2 Emission Performance 

Goals from the Subcategory-Specific Emission Performance 

Rates

 

759 See Chapter 3 of the Regulatory Impact Analysis for more 

information on this analysis, which is available in the docket.

760 The specific mass-based plan requirements are explained in 

detail in section VIII.J.
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In order to provide states flexibility for planning 

purposes, the EPA is providing a state-specific averaging of the 

subcategory-specific emission performance rates to determine a 

statewide goal. While the emission performance rates reflect the 

quantification of performance based on the BSER and embody the 

reductions estimated under building blocks 1, 2, and 3, the 

state goals reflect an equivalent approach through which states 

may choose to adopt and implement those 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 
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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 

then added together for each state. This emission total is 

divided by that state’s baseline generation values from the 

likely affected EGUs in order to develop a state’s rate-based CO2

emission performance goal for 2030. This blended rate reflects 

the collective emission rate a state may expect to achieve when 

its baseline fleet of likely affected EGUs continues to operate 

at baseline levels while meeting its 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 
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calculation of a combined 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 each year from 2022-2029 using 

the emission performance rates calculated for each of those 

years in the previous section. The EPA also repeats this step 

for the interim state goal using the interim subcategory rates. 

The EPA then 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 3- and 2-year increment 

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 potential gradual 

reduction compliance strategy that states may use to reach their 

interim and final stategoals.

As 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 
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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 in Table 12. For state plans choosing to meet a mass-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 
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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 is the emission amounts directly 

represented in the numerator of the statewide rate-based CO2

emission performance goals. Each 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 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 measures are available to maintain 

the necessary ratio of emissions to generation as quantified by 

the subcategory-specific emission performance rates. Due to the 
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nature of the emission performance rate methodology, which 

selects the highest of the three interconnection-based values

for each source category as the CO2 emission performance rate, 

there are cost-effective lower-emitting generation opportunities 

quantified under the building blocks that are not necessary for 

affected EGUs in the Western and Texas interconnections to 

demonstrate compliance at historical generation levels. The EPA 

recognizes that these lower-emitting generation opportunities 

are available to affected EGUs at a national level as a means 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 mass-based goal 

similar compliance flexibility as EGUs subject to a rate-based 

goal, the EPA has quantified the emissions associated with the 

potential realization of these lower-emitting generation 

opportunities and incorporated those additional tons into each 

state’s mass-based goal.761 Because the derivation of these massbased 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-

 

761 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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based state goals offers an equivalent expression of BSER in 

mass form.

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.762

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 

requiring states to address leakage is consistent with the the 

 

762 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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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 

unaffected new EGUs. The form of the rate-based state goals 

provides an equivalent or greater incentive to affected existing 
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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 

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
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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 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 implementation 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. 
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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.763

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 serve 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 

 

763 See Chapter 3 of the Regulatory Impact Analysis for more 

information on this analysis, which is available in the docket.
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rates encompasses a large population size and makes it robust 

against unit-level variation and unit-level inventory 

discrepancies. The EPA does acknowledge that state-level ratebased goals or mass-based goals may be sensitive to

applicability changes within a state’s affected population. In 

the proposal, the EPA used a baseline that aggregated data for 

what 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 units in regards to being affected or unaffected by this 

rulemaking, states can, via state plan submittal or revision, 

adjust their statewide rate or mass goal to reflect this change

of 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 above, the EPA does not believe unit-level variation or 

inclusion/exclusion disparities between baseline inventory and 

affected units will impact the regionally determined emission 
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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 or revising its state plan. 

The EPA will evaluate the appropriateness of such an adjusted 

value based on the state’s demonstration and evaluate the 

approvability of a plan or plan revision accordingly.

Rate-based statewide CO2 emission performance goals are 

listed below in Table 12. Mass-based statewide CO2 emission 

performance goals are found in Table 13. 

Table 12. Statewide764 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 

Arizona* 1,263 1,149 1,074 1,173 1,031 

Arkansas 1,411 1,276 1,185 1,304 1,130 

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 

 

764 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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Georgia 1,290 1,173 1,094 1,198 1,049 

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 

Maryland 1,644 1,476 1,359 1,510 1,287 

Massachusetts 956 885 844 902 824 

Michigan 1,468 1,325 1,228 1,355 1,169 

Minnesota 1,535 1,383 1,277 1,414 1,213 

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 

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 

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 

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 

Utah* 1,483 1,339 1,239 1,368 1,179 

Virginia 1,120 1,026 966 1,047 934 
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Washington 1,192 1,088 1,021 1,111 983 

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 13. Statewide Mass-Based CO2 Emission Performance Goals 

(Adjusted Output-Weighted-Average Tons of CO2 from 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

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 119,380,477 110,754,683 106,736,177 112,984,729 105,094,704 

Georgia 54,257,931 49,855,082 47,534,817 50,926,084 46,346,846 

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 

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 
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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 106,082,757 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 221,613,296 203,728,060 194,351,330 208,090,841 189,588,842 

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. Geographically Isolated States and Territories with Affected 

EGUs

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 RE

costs and performance characteristics needed for building block 
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3 of the BSER. The NREL data for RE that the EPA is relying upon 

for building block 3 does not cover the non-contiguous 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.765 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 

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 

 

765 Hawaii Solar Integration Study, NREL Technical Report 

NREL/TP-5500-57215, June 2013.
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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 

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.”766

 

766 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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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 RE in these jurisdictions. In particular, we

recognize that Hawaii has tremendous opportunities for RE 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 RE sales by 2035, and the territory is 

working hard to meet the requirements of the Mercury and Air 

Toxics Standards, which will reduce emissions from its power 

plants substantially. Guam’s RPS is to achieve 25 percent 

REsales 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 
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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 EGUs767

shall then develop, adopt and submit a state plan under CAA 

section 111(d) that establishes standards of performance for the 

affected EGUs in its jurisdiction in order to implement the 

BSER. Starting 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 

 

767 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 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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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 

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 
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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 

subcategory specific CO2 emission performance rates to their 

affected EGUs, 2) adopting a combination of standards and/or 

other measures that achieve state-specific rate-based goals that 

represent the weighted aggregate of the CO2 emission performance 

rates applied to the affected EGUs in each state, and 3) 

adopting a program to meet mass-based CO2 emission goals that 

represent the equivalent of the rate-based goal for each state. 

These alternatives, as well as the other options we are 

finalizing, ensure that both 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. 

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 
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the portfolio approach. In their plans, states will be able to 

choose 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 be composed, at least in part, 

of measures implemented by the state that are not included as 

federally enforceable components of the plan 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 emission 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.768 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 

levels from the uniform subcategory-specific emission 

 

768 Rate-based and mass-based emission standards may incorporate 

the use of emission trading.
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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, 

during the interim period, the state plan fails to achieve the 

emission reduction trajectory identified in the plan or if, 
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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 CEIP. The final guidelines 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 
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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 

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 
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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 vulnerable 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 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 
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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 

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 
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federal plan for the state.769 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.

This section is organized as follows. First, we discuss the 

timeline for state plan performance and 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 

general considerations for states in developing and implementing 

plans, including consideration of a facility’s “remaining useful 

life” and “other factors” and electric reliability. Seventh, 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 

 

769 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.
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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 

adjust a CO2 rate; and treatment of interstate effects.

B. Timeline for State Plan Performance and 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 CEIP 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 
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performance rates or state CO2 emission goal will be met. The 

final guidelines 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 timing of the interim period and the trajectory of 

compliance by affected EGUs over the interim period 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 

BSER includes implementation of reduction measures over the 

period of 2022 through 2029, with final compliance by affected 
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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. 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 the flexibility to define an alternate trajectory of 

emission performance between 2022 and 2029, provided 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 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 final 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 
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CO2 emission performance rates or interim step state CO2 emission 

goals 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 2030.770

This relatively long period – first for planning, then for 

implementation and achievement of the interim and final CO2

emission performance rates or state CO2 emission goals – provides 

states and utilities with substantial flexibility regarding 

methods and timing of achieving emission reductions 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, 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 

 

770 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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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 necessary.771 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 timelines established in the final rule respond to the 

issues raised in numerous comments regarding the concept of the 

interim 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 plan period at 

2020. Others stated that the investments necessary to meet the 

proposed interim emission performance goals beginning in 2020 

are unachievable in that timeframe or would place too great a 

 

771 Modifications to state plans are addressed more specifically 

in section VIII.E.7 below.
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burden on affected EGUs, states, and ratepayers. Some suggested 

that the 2020 interim goal step should be eliminated in favor of 

later start dates, including 2022, 2025, or other years. Some 

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 

emission performance steps during the interim plan performance 

period and thereby control their own emission reduction 

trajectory or “glide path” 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 this input and our 

final determination of the BSER, the EPA has adjusted 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 emission reduction trajectory 

during the interim period. 

As noted, the EPA has determined that the period for 

mandated reductions should begin in 2022, instead of 2020 as we 
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proposed, because of the substantial amount of comment and data 

we received indicating that states and utilities reasonably 

needed that additional time to 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, 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. 

2. Provisions to encourage early action 

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. 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 

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 
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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 CEIP is designed to incentivize investment in certain 

RE and demand-side 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 
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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 

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 
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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 

2012, 13 GW of utility scale wind were deployed,772 and, in 2014, 

3.4 GW of utility-scale solar773 plus 2-3 GW of distributed solar 

were deployed,774 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 

 

772 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.

773 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.

774 GTM Research/Solar Energy Industries Association: U.S. Solar 

Market Insight Q1 2015.
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enabled by reductions in cost and improvements in performance.

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 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 
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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 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 

pool upon demonstration of quantified and verified MWh of RE 
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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, 2018,775 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 

enables issuance of ERCs or allowances from the state to parties 

effectuating reductions in 2020 and/or 2021 in a manner that 

 

775 This may occur because not all states may elect to include 

requirements for CEIP participation in their state plans. 
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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.776 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 

achieved prior to 2022.777 These and other details will be 

developed in the subsequent action. 

 

776 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. 

777 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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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 is 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 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 final emission guidelines would speed 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 
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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 

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 
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number of states have demand-side EE programs focused on these 

communities,778 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 

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 

 

778 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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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 

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 
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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 

allowances more than once.779

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 

 

779 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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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 

requirements of these guidelines.780

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 

 

780 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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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

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.781 We refer to this as an “emission standards” state 

 

781 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 
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plan type. The second, which we refer to as a “state measures” 

plan type, would allow the state mass CO2 emission goals to be 

achieved by affected EGUs in part, or entirely, through state 

measures782 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 terms of 111(d), which specifically 

require a state to submit standards of performance.

These two types of state plans and their respective 

approaches, either of which could be implemented on a single-

 

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 

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. 

782 “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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state 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. 

Under these two basic plan types, the final emission 

guidelines 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). 

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 
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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.783 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.784

 Establishing federally enforceable, mass-based CO2 emission 

standards for affected EGUs.785 This approach facilitates

interstate emission trading, through either a single-state 

 

783 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.

784 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.

785 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.
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“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 this approach.786

 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.787 In a separate concurrent action, the EPA is 

proposing a model rule for states that could be used in a 

plan implementing this approach.

 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.788 This approach 

provides for interstate emission trading, through a multi-

 

786 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.

787 Rate-based trading-ready plans are addressed in section 

VIII.K.4.

788 This plan approach is addressed in section VIII.C.2.a.
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state plan that meets a single weighted average multi-state 

rate-based CO2 goal.789

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 and 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 

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. This type of state plan, as 

described below, may consist of rate-based emission standards 

 

789 This multi-state plan approach is addressed in section 

VIII.C.5.
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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 for affected EGUs. 

Both rate-based 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.

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, 

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.790

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) 

 

790 The legal basis for authorizing trading in emission standards 

is discussed in section VIII.C.6.
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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 

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 
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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.

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 
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rate-based CO2 goal.791

Under this type of approach, therefore, the state would be

required to include a demonstration,792 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

 

791 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.

792 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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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 

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. 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 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.
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(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 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. The state would include in its state plan an emission 

standard that is the rate 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 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 
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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.

(2) Additional considerations for rate-based approach.

Additional considerations and requirements for rate-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 in rate-based state plans. Section VIII.K.4 
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addresses multi-state coordination among rate-based 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

emissions (see section VIII.J.2.b, Table 14).793

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 

 

793 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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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 

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 
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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 

up to the established emission budget.794 Allowances may be 

distributed to affected emission sources (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 

 

794 An emission allowance represents a limited authorization to 

emit, typically denominated in one short ton or metric ton of 

emissions.
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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 

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 
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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 

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 
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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. 

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 
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affected EGUs. Upon further consideration of the requirements of 

CAA section 111(d), in consideration of the comments we received 

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), EERS, and utility- and state-administered incentive 

programs for the deployment of RE and demand-side EE 

technologies and practices. 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 
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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. 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, implemented, and enforceable 

only under state law, and rely upon such measures795 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 

 

795 “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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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 

measures, 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 

alone or state measures in conjunction 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. 
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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 

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 
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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 state mass-based CO2 goal 

for affected EGUs (or mass-based CO2 goal plus new source 

complement).

The EPA’s evaluation of the approvability of a state 

measures plan 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 
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standards for the affected EGUs that are sufficient to achieve 

the state CO2 emission goal or the CO2 emission performance rates

in the event that state measures do not result in the required

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, 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 
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periods) and the final two-year plan performance periods.796 If a 

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 

 

796 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).
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plan over the 8-year interim performance period (2022-2029) or 

for any 2-year final goal performance period, the state measures 

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.797,798

 

797 States may choose to establish an effective date for backstop 

emission standards that is sooner than 18 months.

798 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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The backstop emission standards must make up for the 

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 for affected EGUs, and then later submit 

appropriate revisions to the backstop emission standards 

adjusting for the shortfall through the state plan revision 

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 shortfall, such that no modification 

of the emission standards is necessary in order to address the 

emission performance shortfall. 

For example, assume a state measures 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 
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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.799 The 

emission standards included as 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 

 

799 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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agree with this latter comment, because both approaches would 

result in adequate and appropriate constraints on CO2 emissions. 

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.

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 
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flexibility to take local circumstances, economics and state 

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).800 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 described 

 

800 Legal considerations with the proposed portfolio approach are 

explored in section VIII.C.6.d.
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above, 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 

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.801

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).802

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 

 

801 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.

802 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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transfer of ERCs or emission allowances.803 This approach 

facilitates interstate emission trading without requiring states 

to submit joint plans.804 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 

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. 

 

803 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.

804 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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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 

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 
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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 

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.
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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).805 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.806

 

805 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. 

806 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. 
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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.807

Such plans could include emission standards in the form of 

a multi-state rate-based or mass-based emission trading 

program.808 Alternatively, states could submit a multi-state plan 

 

Under an emission standards plan, corrective measures would be 

triggered. Under a state measures plan, the federally 

enforceable backstop emission standards would be triggered. See 

section VIII.F.3.

807 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.

808 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.
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using a state measures approach.809 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. States may submit individual plans 

that will meet the CO2 emission performance rates 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.810 For rate-based plans, 

this type of coordinated approach is limited to state plans with 

rate-based emission standards that are equal to the CO2 emission 

performance rates in the emission guidelines.

 

809 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.

810 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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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,811 through either a joint tracking system, 

interoperable tracking systems, or an EPA-administered tracking 

system.812

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.813 However, the EPA 

would also assess linkages with other state plans, to ensure 

 

811 Referred to in different programs as “surrender,” 

“retirement,” or “cancellation.”

812 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.

813 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 section VIII.J.
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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. 

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 

consistent with the CO2 emission performance rates in the 

emission guidelines) 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 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 
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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 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.

6. Legal bases and considerations for state plan types and 

approaches

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 
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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 

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 
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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.

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 SIP does not comply with all CAA

requirements (see sections 110(k)(3) and 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 
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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 considerations 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 

program. Third, we give a similar explanation of the EPA’s 

interpretation of the same phrase in the context of a mass-based 

allowance trading program. 

(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 

emission trading in approvable state plans.

For purposes of this legal discussion, in the case of an 

emission limitation expressed as an emission rate, trading takes 
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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 

Administrator determines has been adequately 

demonstrated.

Both an emission rate that may be met through tradable 

ERCs, and a mass limit requirement that 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 
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requirement,814 which, under the only (or at least a permissible) 

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 

“standard for emissions.”815 In addition, in the 1995 Municipal 

Solid Waste (MSW) Combustor rule the EPA authorized emission 

trading by sources.816

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 

 

814 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 

(1967); see also The American College Dictionary (C.L. Barnhart, 

ed. 1970) (“an authoritative model or measure”). 

815 70 FR 28606, 28616-17 (May 18, 2005).

816 60 FR 65387, 6540/2 (Dec. 19, 1995).
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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, a 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, its emissions 

will not exceed the allowances it will surrender. In this 

respect, a tradable emission rate or mass 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 

mass limit requirement is appropriate for CO2 emissions, the air 

pollutant covered by this rule, because the environmental 

effects of CO2 emissions are not 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 
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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 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, 

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.

However, as described in 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 third-party verifiers of such compliance 
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units.

(3). In our final rule, we are prescribing certain specific 

requirements for trading systems for allowances in a mass-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 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. 

c. 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 

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.”

For states that choose to adopt and submit a state measures 
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plan, such 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 

requires 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. Instead, Congress 

has delegated to the EPA the determination of the appropriate 

effective date of standards of performance submitted under state 

plans to meet the requirements of section 111(d). In other 

words, where the statute is silent, the EPA has authority to 

provide a reasonable interpretation. The EPA’s interpretation is 

that for states that submit state plans establishing standards 

of performance under section 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. A 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 
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affected EGU CO2 emissions are projected to achieve, and do 

achieve, the requisite state goal. 

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 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 
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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 

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 
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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 

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 requisite state CO2 emission 

goal. The state measures plan type is also a variation of the 

proposed state commitment approach 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 
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entities other than affected EGUs in meeting the requirements of 

the emission guidelines and CAA section 111(d). 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 

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 
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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 

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.

The EPA additionally notes that the state measures plan 

type is not precluded by the recent Ninth Circuit Court of 

Appeals’ decision in Committee for a Better Arvin et al. v. US 

EPA et al., Nos. 11-73924 and 12-71332 (May 20, 2015). The court 

held that the EPA violated the CAA by approving a California 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 CAA, which states that 

SIPs “shall include” the emission limitations and other control 

measures on which a state relies to comply with the CAA. The 

court then stated that the EPA’s action was also inconsistent 

with the structure of the CAA. 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 
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state-only standards. In addition, the court stated that the 

EPA’s action 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. Even if section 111(d) 

did impose such requirements, the state measures approach 

satisfies them because the trigger is included in the plan as a 

federally enforceable implementation measure, and the backstop 

included in the plan also contains standards of performance that 

reflect the BSER and 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 

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 
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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.

d. Legal considerations 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. A 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.

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 . . . 

standards of performance” under CAA section 111(d)(1). Although 
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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,817 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 

not imply that the BSER cannot be based on actions by nonaffected sources. As discussed in section V, the BSER may be 

 

817 Such measures include, for example, in this rule, 

requirements for ERCs.
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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 basis for multi-state plans. While nothing in section 

111(d)(1) explicitly authorizes either states to adopt and 

submit multi-state plans, or the EPA to approve them as 

satisfactory, nothing in section 111(d)(1) explicitly prohibits 

it, 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. 

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, 
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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 criteria

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 projected CO2 emission performance by affected EGUs 

must be equivalent to or better than the required CO2 emission 

performance level in the state 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 

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 
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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). 

There is no functional change in the approvability criteria or 

the components of a state plan addressed in the proposal; they 

are simply combined and this change does 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 

might be included in a state plan.818

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 

 

818 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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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 technologies, waste heat recovery, net-metering energy 

savings and state RPS.

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 

instead of the portfolio approach, under which a state can rely 

upon measures that are not federally enforceable as long as the 

plan also includes a backstop of federally enforceable emission 

standards that apply to affected EGUs. As 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 
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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 entities. As 

proposed, we are requiring that state plans include a 

demonstration that plan measures are enforceable, which for 

emission standards plan types is discussed in section 

VIII.D.2.b.3 below and for state measures plan 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 a 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 
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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 

performance levels specified in the plan on schedule. For more 

information on the state measures plan approach, see section 

VIII.C.3 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. As 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
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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 a 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 

emission standards plan type or a state measures plan 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 meets 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 plan 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 type. Section VIII.D.2.c 
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addresses additional components required for submittals under 

the state measures plan type. 

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 

VIII.D.2.b (for the emission standards plan type) or VIII.D.2.c 

(for the state measures plan type) of this section.

(1) Description of the plan approach and geographic scope. 

The description of the plan type must indicate whether the 

state will meet the emission guidelines on an individual state 

basis or jointly through a multi-state plan, and whether the 

state is adopting an emission standards plan type or a state 

measures 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.819

(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 

 

819 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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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.

(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.820 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 

 

820 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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demonstration through 2031 is based are permanent and will 

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.821

(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-

 

821 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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budget822 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 

technically sound methods that are reliable and replicable. A 

 

822 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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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 

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 
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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

 Time period of analysis, which must extend through 2031

 Electricity demand forecast (MWh load and MW peak demand) 
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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

 If applicable, EGU-specific actions in the state plan 

designed to meet the required CO2 emission performance, 

including their timeline for implementation
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 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 

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 multi-
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state 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 

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 
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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 

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 
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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 

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
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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 

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.
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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 

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 
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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 

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 
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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, 

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 
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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 

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 
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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 

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 
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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 

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 
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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 

throughout in the development of the state plan.823 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, 

 

823 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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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 

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 
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change related impacts.824 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 

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, 

 

824 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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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 

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. 
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(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 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 
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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 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 
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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 

is finalizing CO2 emission performance rates for fossil fuelfired steam generating units and for stationary combustion 

turbines. The EPA has translated the source category-specific CO2

emission performance rates into equivalent state-level ratebased and mass-based CO2 goals in order to maximize the range of 

choices that states will have in developing their plans. The 

state may choose 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. 

Each state plan 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 CO2 interim period performance rates or state 

goal (for 2022-2029), interim step performance rates or state 

goals (interim step performance rates or state goal 1 for 2022-

2024; interim step performance rates or state goal 2 for 2025-
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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.

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 2028-2029.825 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 the emission guidelines 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 

 

825 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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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. 

(2) 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 (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: 
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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 2 calendar years. States can choose to set 

shorter compliance periods for the emission standards 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 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 long-lived 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 
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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 plan 

requirements for EM&V and verification that meet the 

requirements in the emission guidelines. EM&V requirements are 

discussed in section VIII.K.3. Rate-based 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. These requirements are discussed in more detail 

in sections VIII.F and VIII.K.

For state plans using a mass-based emission trading program 

approach, 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” 
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with reported CO2 emissions). 

(3) 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 

measured, using technically sound methods, in a manner that can 

be replicated.826

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 

 

826 A CO2 continuous emissions monitoring system (CEMS) is the 

most technically reliable method of emission measurement for 

EGUs. A CEMS provides a measurement method that is performance 

based rather than equipment specific and is verified based on 

NIST traceable standards. A CEMS provides 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.
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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.827 This does not mean that measures used to 

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).

An emission standard is permanent if the emission standard 

must be met for each applicable compliance period. 

 

827 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 

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 standard in another state, where 

states are collaborating in the implementation of their 

individual emission trading programs through interstate transfer 

of ERCs, or participating in a multi-state plan with a ratebased emission trading program. These coordinated multi-state 

approaches are addressed in sections VIII.C.5, VIII.J.3, and 

VIII.K.4.
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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 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 entities 

responsible for compliance and liable for violations can be 

identified; and (4) each compliance activity or measure is 

enforceable as a practical matter in accordance with EPA 

guidance on practical enforceability,828 and the Administrator, 

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), in the case of a state, pursuant to its 

state plan, state law or CAA section 304, as applicable, and in 

the case of third parties, pursuant to CAA section 304.

 

828 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.” 
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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 

enforceability.829 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” TSD830 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 

EGUs for violations of an emission standard included in a state 

plan via civil action as part of the required plan component 

 

829 See prior footnote.

830 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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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, comments received, and the clear 

statutory foundation.

(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. Within 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 

biennial state report is required starting in 2030 and beyond 

covering the two calendar years of each reporting period. This 

final reporting schedule reduces 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 recordkeeping 
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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. For rate-based emission 

trading programs, the report must also include for EPA review 

the state’s review of the administration of their state ratebased emission trading program, as discussed in section 

VIII.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 with the actual CO2 emission 

performance achieved by affected EGUs during the period. In the 

report due to the EPA on July 1, 2030, the state must include a 

comparison of the actual CO2 emission performance achieved by 
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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 biennial state report 

must include a final performance check to demonstrate that the 

affected EGUs continue to meet the final CO2 emission performance 

rates or state rate-based or mass-based CO2 goal. 

For state plans that use the emission standards approach 

and are subject to the corrective measures provisions in the 

emission guidelines, if actual CO2 emission performance (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 the interim step 1 or step 2 reporting 

periods, 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 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 
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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 

step 2 goal for 2025-2027 and interim step 3 goal for 2028-

2029.831 States are free to establish different interim step 

goals than those the EPA has specified in this final rule. If 

 

831 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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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). 

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 
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quantifiable, non-duplicative, permanent verifiable, and 

enforceable. If a state measures plan type includes CO2 emission 

standards that apply to affected EGUs, these emission standards 

must be federally enforceable.

(3) 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 finalized

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 

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 
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backstop are discussed in detail in section VIII.C.3.b.

(4) Identification of state measures. 

A state adopting a state measures plan type 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 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 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 as a matter of 

state law. 

(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 
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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 must 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 

measures approach. 

As discussed in section VIII.F, for states using the state 

measures approach, the EPA is finalizing that at the end of the 

first two interim step periods, 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 
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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 

biennial 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 state CO2

goal.

If, at the time of the state report to the EPA, the state 

has not met the programmatic milestones for the reporting 

period, or the performance check shows that the actual CO2

emission performance of affected EGUs warrants implementation of 

backstop requirements,832 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 

 

832 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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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 state CO2 emission goal. For example, if a 

state report due on July 1, 2025, shows that actual CO2 emission 

performance of affected EGUs is deficient by 10 percent or more 

relative to the specified level of emission performance for 

2022-2024 in the state plan, the backstop federally enforceable 

emission standards for affected EGUs must be effective as of 

January 1, 2027.

(6) 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 measures833 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. 

 

833 “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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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. 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) 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 enforceable834 if: (1) it represents a 

technically accurate limitation or requirement and the time 

period for the limitation or requirement is specified; (2) 

 

834 Under the state measures approach, state measures are 

enforceable only per applicable state law.
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compliance requirements are clearly defined; (3) the affected 

entities responsible for compliance and liable for violations 

can be identified; and (4) each compliance activity or measure 

is practically enforceable in accordance with EPA guidance on 

practical enforceability,835 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 state CO2 emission goal to be 

achieved.

d. Legal basis for the components. 

(1) General legal basis. 

 

835 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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Under section 111(d), state plans must “provide for the 

implementation and enforcement of [the] standards of 

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 
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to give the EPA considerable leeway in interpreting the 

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.836 

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 

 

836 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 

to disapprove a state plan as unsatisfactory simply because it 
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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 

position here is hardly novel. The EPA notes in discussing the 

implementing regulations, nothing in this final rule reopens 
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provisions or issues that were previously decided in the 

original promulgation of the regulations unless otherwise 

explicitly reopened for this rule.

(2) Legal considerations with changes to affected EGUs. 

In the proposed rulemaking, the EPA proposed the 

interpretation 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. 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. 

(3) Legal considerations regarding design, equipment, work 

practice or operational standards. 
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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 

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 
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state’s standards of performance (in other words, either the 

federally enforceable backstop under the state measures approach 

or the emission standards under the emission 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 emission 

standard on the affected EGU.837 

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 

 

837 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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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 

discussion of the term “standard of performance” above in 

VIII.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 
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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 

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 changerelated 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 
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such communities. By requiring states to demonstrate how they 

have meaningfully engaged with vulnerable 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

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
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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 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 

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 
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specifies otherwise.838 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 

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 

 

838 40 CFR 60.23(a)(1).
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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 

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 SIPs, 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.
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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 

such existing programs.839 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 

 

839 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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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 

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 
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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 

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, 2016.840 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 

 

840 40 CFR 60.23(b).
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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.841 See the proposed federal plan rulemaking 

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 

 

841 See 40 CFR 49.1 to 49.11.
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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.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 
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plan by the extended date of September 6, 2018:842

 An identification of final plan approach or approaches 

under consideration, including a description of progress 

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,843 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 

 

842 As stated previously, in the case of a state electing to 

participate in the CEIP, this 2016 submittal must include a nonbinding statement of intent to participate in the program.

843 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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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 

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.844

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 

 

844 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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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

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’ 
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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 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 
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plan, including describing what actions have already been 

taken, what steps remain, and the schedule for completing 

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 
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made by states, and this is further illustrated by the 

clarifications on how states may meet each of the three required 

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 
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identified in the initial submittal do not need to be final 

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

identifying next steps (which may be a natural extension of 
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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 

to reduce CO2, it would be reasonable and appropriate, and in 

keeping with the goals of 111(d) to ensure that any existing CO2
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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 

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 
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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 

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 
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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 

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 
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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.”845

Additionally, this guidance document also encourages those 

writing rules to consider the positive impacts that a rulemaking 

will have on communities).846 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.847 Both of the 

resources discussed above can add to what states may already 

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 

 

845 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.

846 Ibid.

847 Considering Environmental Justice in Permitting. 

http://www.epa.gov/environmentaljustice/planej/permitting.html#actions.
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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 

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 
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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 

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 
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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 

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.
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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.

First, 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 

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. First, states 

participating in a multi-state plan can provide a single 
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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 

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 
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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 

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 
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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.

5. Process for EPA review of state plans

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 

111(d), some additional procedural elements we believe will be 

helpful to states, stakeholders and the EPA moving forward.

Following the September 6, 2016 deadline for state plan 

submittals, the EPA will review plan submittals. For a state 

that submits an initial submittal by September 6, 2016, and 

requests an extension of the deadline for the submission of a 

final state plan submittal, the EPA will determine if the 
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initial submittal meets the minimum requirements for an initial 

submittal. 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. 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 plan 

submittal will be deemed granted, and the final plan submittal 

must be submitted to the EPA by no later than September 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 acting 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 
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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 proposed this timeline for 

review and action on state plans in our proposal, but our 

proposal was specific to the timeline for state plans submitted 

pursuant to this rule rather than for state plans submitted 

under 111(d) generally.848 We are finalizing as part of this rule 

that state plans submitted to meet the requirements of this rule 

will be reviewed and acted upon by the EPA within 12 months of 

submission. Because such timeline would be appropriate to be 

made to 111(d) state plans more generally, we are also proposing 

the appropriate revisions to the implementing regulations as 

part of the federal plan proposal for section 111(d).

In addition, while the 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 under 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 

 

848 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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with the requirements of section 111(d). This is a procedural 

requirement under CAA section 110(k)(1) for SIPs, and the EPA 

believes this requirement is appropriate to establish under 

section 111(d)’s direction to 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 is proposing such 

regulations as part of the federal plan proposal for section 

111(d). The EPA notes that this preamble (in section VIII.D) and 

final rule lay 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 add 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 we further explain in the federal 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 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 
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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 received in response to the 

proposal for these guidelines indicated that the flexibility 

provided by these mechanisms could be useful getting state plans 

in place. The EPA agrees, 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.

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 

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 
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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. 

6. Failure to submit a plan

If a state does 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 1 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.

7. 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 

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 may 
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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 plan 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 

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 
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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 

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 
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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 

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; 
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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

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 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 
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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. 

8. Plan templates and electronic submittal 

The EPA is finalizing the requirement that submissions 

related to this program be submitted electronically. 

Specifically, that 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 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 noneditable 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 
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of the specific plan components in their submittals that are 

designated as federally enforceable, either effective 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. Revisions 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 

that the authorized official can submit and sign a package for 
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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/. States 

who claim that a state plan submittal or supporting 

documentation includes confidential business information (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. 

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. 
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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 

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 
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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 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 mass-based trading framework, a 

rate-based trading framework, multi-state 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 emission 

reductions delivered by RE and EE). The 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 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 them on the need for additional 

tools and guidance to facilitate the development of approvable 

state plans.
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9. Legal basis 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 

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 

concurrently with this final rule. In this section we discuss 

the legal basis for procedures that the EPA is finalizing in 

this action: initial submittals, extensions, and plan revisions. 

First, by 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.” One definition of 

“similar” is “having likeness or resemblance, especially in a 

general way.” The American College Dictionary 1127 (C.L. 

Barnhart, ed. 1970). On the other hand, “same” is defined as 

“alike in kind, degree, quality; that is, identical” or 

“unchanged in character.” Id. at 1073.
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Had Congress intended that the procedures for 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 submittals and extensions. Initial 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 submittals. As explained above, though, 

we are not bound under section 111(d)(1) to follow exactly the 

same procedures. 

With respect to the timing of initial submittals, final 
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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.849 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 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 

 

849 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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section 110(b) provides for extensions of 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 approach of 

initial submittals and extensions of due dates as proposed are 

reasonable procedures that, while not identical to the 

procedures in section 110, are still similar. 

Some commenters argued that the 1-year period for initial 

submittals and, even assuming an extension, the additional 1- to 

2-year period for final submittals were unreasonably 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 for the initial 

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 
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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. Developing attainment 

plans may or may not require states to seek additional 

legislative authority, but certainly 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 modeled 

demonstrations of attainment (which in some instances requires 

photochemical grid modeling). Thus, it is reasonable to have the 
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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). 

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 
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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 stated 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 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 
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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 

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 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 
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compliance periods, monitoring and reporting for affected EGUs; 

plan performance demonstrations; 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 

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 
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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, 

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 specified above, which 

respond to the comments by applying to both rate- and mass-based 

programs, providing compliance periods longer than 1 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. The EPA finalizes that states can choose to set shorter 

compliance periods for their emission standards but none that 

are longer than the compliance periods the EPA is finalizing in 
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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. “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.” However, 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 long-lived 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 general 

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 
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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. 

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 affected 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) on a quarterly basis in accordance with 

40 CFR part 75. Note that this requirement applies for all types 
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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. 

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 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 
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key flexibilities provided in the part 75 regulations, thus 

requiring utilities to maintain separate document collection and 

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 flexibility 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.
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As discussed above in section VII, the agency is 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 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 at the end of the first two interim step 

periods.

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 

measuring actual plan performance against the performance rates 
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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 output850 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 containing 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 period 

(2022-2029) with the interim CO2 emission performance rates or 

state CO2 emission goal. The report is not required to include a 

 

850 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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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. 

This 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.851 This 

approach allows for CO2 allowance banking across plan performance 

periods, including from the interim period to the final period. 

As a result, CO2 emissions by affected EGUs could differ from the 

state mass-based 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 

 

851 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 2-

year plan performance periods.
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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 emission 

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 a biennial 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 
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report is due to the EPA no later than July 1 of the year 

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 

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 
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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 

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 
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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. 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 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. Corrective 

measures apply only to emission standard plans in which full 

compliance by affected EGUs would not necessarily lead to 

achievement of the emission performance rates or CO2 emission 

goals.852 For such plans, corrective measures are triggered if 

actual CO2 emission performance by affected EGUs is deficient by 

 

852 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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10 percent or more relative to the specified level of emission 

performance in the state plan for the step 1 or step 2 interim 

performance periods. Corrective measures also are triggered if 

actual emission performance fails to meet the specified level in 

the plan for the 8-year interim period 2022-2029, 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.853

When 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 shortfall that occurred during a performance period. 

The shortfall must be made up as expeditiously as practicable. 

 

853 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 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 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.3 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, is based on checks that must be included in state reports 

that must be submitted annually during the interim period and 

biennially during the final period. The state must annually 

report on its progress in meeting its programmatic milestones 

during the interim period. In addition, the state must report 
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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 warrants 

implementation of backstop requirements,854 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.855

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. 

 

854 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).

855 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 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 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. We are finalizing a reliability safety valve, which 

includes an initial period of up to 90 days during which a 
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reliability-critical affected EGU or EGUs will not be required 

to meet the emission standard established for it under the state 

plan but rather will 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 will 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. 

Use of the reliability safety valve will not alter or abrogate 

any other obligations under the approved state plan. After the 

initial period of up to 90 days, the reliability-critical 

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 state goals or performance 

rates occurring after the initial period of up to 90 days are 

accounted for and offset. See section VIII.G.2.e of this 

preamble.

Multiple commenters supported the inclusion of strong 

enforcement measures for ensuring the interim and final goals 
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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 trigger that we are finalizing (actual emissions or emission 

rate performance that is 10 percent or more than the specified 

level of emission performance in 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 

and final goal.

The EPA requested comment on whether the agency should 
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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 is proposing these revisions to 

the 111(d) implementing regulations in the 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 

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 
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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 

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 
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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. 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 makes 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 

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 
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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.856 

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 

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 emission standards 

 

856 Similar considerations apply to the requirement under the 

state measures approach to revise the plan to make up the 

shortfall.
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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 “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 
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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 

required under CAA section 111(d) to be maintained or, through 

silence, authorized the EPA to reasonably require maintenance. 

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 must 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 
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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 

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 
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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 

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 
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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 

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. 
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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 

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 
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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.” 

The EPA’s 1975 implementing regulations857 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 

 

857 40 FR 53340 (Nov. 17, 1975).
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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) “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. 
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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 

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 
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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, Kraft pulp 

plants, and municipal solid waste landfills specify emission 

limits for sources.858 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 

 

858 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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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 facilityspecific 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 
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generating units and stationary combustion turbines in 

conjunction with rate-based trading, though, the state would be 

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. 
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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.

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.859

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 

 

859 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 

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 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 

response to the proposed guidelines, some commenters said that 

the proposed state goals were unachievable and therefore too 
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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

 Updating analyses of achievable levels of improvement 

through the building blocks that together represent the 
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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 

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 
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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.

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 
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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 

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.
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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 

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 
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policy priorities of the state. Details are available in a memo 

to the docket.860

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 

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 

 

860 Memorandum to Clean Power Plan Docket titled “Stranded Assets 

Analysis” dated July 2015.
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level achievable by affected EGUs based on regional average 

estimates of the impact of applying the BSER to collective 

groupings of affected EGUs.861 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 

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 

 

861 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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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 

expenditures for heat rate improvements would be much smaller 

than capital expenditures required for example, for purchase and 

installation of scrubbers to remove SO2; a fleet-wide average 

cost for heat rate improvements based primarily on best 

practices at coal-fired generating units would not likely exceed 
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$100/kW, compared with a typical SO2 wet scrubber cost of $500/kW

(costs vary with unit size).862 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 

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 

 

862 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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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 

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 
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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 

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 
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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 

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 
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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 

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 
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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 

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 
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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 

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 
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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.863 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.864 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.865

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 

 

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

Systems: An Overview of the Technology, the Marketplace, and 

Government Regulations, IEEE Press, at 160 (2010).

864 Id.

865 NERC Reliability Standard EOP-001-2.1b — Emergency Operations 

Planning, available at

http://www.nerc.net/standardsreports/standardssummary.aspx.
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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.866 In February of 2015, 

Midcontinent Independent System Operator (MISO), California 

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.867 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. 

 

866 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.

867 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 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 

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 
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enforceable reliability standards.868

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 

 

868For 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 

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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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 

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 
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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 

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 letter869 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.

 

869 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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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 

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 
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that it is a useful element to state plan development.

Fourth, 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 

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. 
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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 

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 

transmission efficiency and infrastructure, and investment in 
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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 

mitigate those risks. The final rule allows states to develop a 

pathway over the interim period that reflects their own 
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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 

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 
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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 

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 
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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 

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 
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development process.870 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. 

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 

 

870 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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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 

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 
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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.871

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 

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 

 

871 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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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 

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 
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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 

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 
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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 

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 
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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 

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.872

Within 7 days of submitting the initial notification, the 

state must submit a second notification providing documentation 

 

872 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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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 

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 
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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. 

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 
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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 

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 
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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 

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 
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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 

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 
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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, 

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.873 The 

 

873 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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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 

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 2015.874 The EPA appreciates 

NERC’s attention to, and interest in, the proposed rule. 

However, we note that like some other studies, NERC assumes 

 

874 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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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 

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.875 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.876 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 

 

875 EIA, Annual Energy Outlook 2015, PRIL 2015.

876 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.
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rule, including MISO, PJM, ERCOT, and SPP.877 For example, MISO 

conducted an analysis of coal units at risk for retirement, 

finding that 14 GW of coal may be at risk.878 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.879 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 

 

877 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 

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 

878 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.

879 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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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 

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.880 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.”881 

 

880 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.

881 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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ERCOT also performed an analysis, modeling numerous 

scenarios.882 ERCOT stated that its modeling identified two 

potential reliability problems – impacts of units retiring and 

increased levels of renewable generation on the ERCOT grid.883 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.884

 

882 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.

883 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.

884 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).885 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.886 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 

unbiased and independent analysis of this issue.”887 WECC 

 

885 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.

886 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.

887 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
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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.888 

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.889 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 

far too late to act” to ensure reliability.890 It stated that 

these assumptions are not consistent with past actions. 

 

bility/140912_EPA-111(d)_PhaseI_TechFinal.pdf&action=default&DefaultItemOpen=1.

888 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.

889 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.

890 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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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 

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 
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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 

other coal basins provides additional pressure.” 891 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 

 

891 http://www.eda.gov/power/.
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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.892 

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 

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 

 

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

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 
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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.893 This approach is consistent with ordinary 

cooperative federalism regimes that federal courts have 

routinely upheld against Tenth Amendment challenges.894 

 

893 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.

894 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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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.895 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 110.896

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 

 

895 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 contexts of nonattainment SIPs and responses to SIP Calls 

made under CAA section 110(k)(5). See 42 U.S.C. § 7509(a). 

896 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 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

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 
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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.

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 
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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 

guidance section serves as a central repository for the final 

emission guidelines, RIA, guidance documents, TSDs and other 
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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. 

I. 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, 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 
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are discussed in section VIII.I.1 below, and include heat rate 

improvements, fuel switching from one fossil fuel to another, 

integration of RE into EGU operations, and combined heat and 

power (CHP) 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.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 
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and tracking of actual energy output.897 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;898 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.899

Heat rate improvements, fuel switching, integrating RE and 

CHP would not require any additional accounting or monitoring 

 

897 Monitoring and reporting requirements for affected EGU CO2 

emissions and useful energy output are addressed in section 

VIII.F.

898 “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. 

899 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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and reporting, because under the emission guidelines affected 

EGUs are already required to monitor and report CO2 emissions at 

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. 

2. Actions with additional accounting and reporting requirements 

Certain actions that may be taken at an affected EGU to 

reduce CO2 emissions, specifically application of CCS and CCU, 

and use of biomass, require additional accounting and reporting.

a. Application of CCS. Affected EGUs may utilize retrofit CCS 

technology to reduce reported stack CO2 emissions from the EGU.900

Affected EGUs that apply CCS under a state plan must meet the 

same monitoring, recordkeeping and reporting requirements for 

sequestered CO2 as new units that implement CCS to meet final 

standards of performance under CAA section 111(b) for new 

EGUs.901 Specifically, the final CAA section 111(b) rule for new 

sources requires that, if a new affected EGU uses CCS to meet 

 

900 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. 

901 Standards of Performance for Greenhouse Gas Emissions from 

New, Modified, and Reconstructed Stationary Sources: Electric 

Utility Generating Units.
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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 (Geologic Sequestration of Carbon Dioxide).902,903 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 found 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 

 

902 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 emission limit must transfer the captured CO2 to a 

facility that reports under 40 CFR part 98 subpart RR.

903 Under final requirements in the CAA 111(b) NSPS, any well 

receiving CO2 captured from an affected EGU, 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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other dispatchable, non-NGCC generating options. 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 may 

be expected to be substantial, and some existing EGUs may have 

space limitations and thus may 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. Because 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 

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 
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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. The EPA received similar public comments on the CAA 111(b) 

proposal for new EGUs. The EPA disagrees with the commenters’ 

assertions and addressed those in the preamble for the final 

standards of performance and in the Response-to-Comments (RTC) 

document for the 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 

element of the BSER, but it is an available compliance measure 
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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. 

Potential alternatives to storing CO2 in geologic formations 

are emerging and 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 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 
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plant and converts the CO2 into other products including sodium 

carbonate and sodium bicarbonate.904 Other companies – including 

Calera905 and New Sky906 – 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 

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 

 

904 http://skyonic.com/technologies/skymine.

905 http://www.calera.com/beneficial-reuse-of-co2/process.html.

906 http://www.newskyenergy.com/index.php/products/carboncycle.
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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.

c. 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 
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emissions from biomass combustion should be counted. As 

discussed in the next section, the revised Framework for 

Assessing Biogenic Carbon Dioxide for Stationary Sources907 and 

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, 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.908 Other 

comments focused on the use of sustainably-derived 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 include qualified

biomass in their plans and include provisions for how qualified

biomass feedstocks or feedstock categories will be determined. 

The EPA will review the appropriateness and basis for

determining qualified biomass feedstocks or feedstock categories 

in its review of the approvability of a state plan. 

 

907 www.epa.gov/climatechange/downloads/Framework-for-AssessingBiogenic-CO2-Emissions.pdf.

908 www.epa.gov/climatechange/ghgemissions/biogenicemissions.html.
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(1) 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 

energy production.909 The revised Framework also found that the 

 

909 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 
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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 feedstocks910 and certain forest-derived industrial 

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 

 

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.

910 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.
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compared with an alternate fate of disposal.

In addition, as detailed in the President’s Climate Action 

Plan,911 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 

more than 13 percent of total U.S. GHG emissions each year.912

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 

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 

 

911 www.whitehouse.gov/sites/default/files/image/ 

president27sclimateactionplan.pdf. 

912 www.epa.gov/climatechange/Downloads/ghgemissions/US-GHGInventory-2015-Chapter-6-Land-Use-Land-Use-Change-andForestry.pdf.
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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 

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 
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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 sustainably-derived 

biomass and sustainable forestry and agriculture programs, such 

as the examples highlighted above, may help them 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.913

The EPA is engaging in a second round of targeted peer 

review on the revised Framework with the SAB in 2015.914 As part 

 

913 As highlighted in a November 2014 memorandum to the EPA’s 

Regional Air Division Directors. 

www.epa.gov/climatechange/ghgemissions/biogenic-emissions.html.

914 www.epa.gov/sab.
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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 

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
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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 

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 
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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, 

the second SAB peer review process, and the state and third 

party programs highlighted in the previous section can assist 

states when considering the role of qualified biomass in state 

plan submittals.

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 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 
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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 

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 
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with the use of qualified biomass.

(3) Biomass co-firing. 

Affected EGUs may use qualified 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. 

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 
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fuels instead of fossil fuels becomes a non-affected EGU.915 An 

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 

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 

 

915 For such an EGU to be considered non-affected, the EGU must

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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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 

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 
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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 

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 
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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 

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 
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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 

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 
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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 

potential emission leakage has been addressed in a mass-based 

state plan:916

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 budget917 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 

 

916 The first two options need not be mutually exclusive; they 

can both be implemented as part of a mass-based plan.

917 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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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 

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 
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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 

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 
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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 

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 Goals918 + 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 

 

918 The state mass CO2 goals can be found in Table 13 in section 

VII.
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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 

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 
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North Carolina

 

692,091 

 

610,623 

 

57,678,116 

 

51,876,856 

North Dakota

 

245,324 

 

216,446 

 

23,878,144 

 

21,099,677 

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 
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States can, in the alternative, provide their own 

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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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, 

in part, on their level of electricity generation in a recent 
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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 

source of generation to satisfy electricity demand. Increased 

demand-side EE will reduce the demand that sources need to meet. 
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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.

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 
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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 

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 
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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 

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 
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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 

plus new source CO2 emission complement),919 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 

 

919 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 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 

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 
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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 

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).920

However, emission budget trading programs, including those 

 

920 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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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 

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 
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requirements specifically with respect to affected EGUs.921 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 

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 

 

921 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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provisions that make additional allowances available at 

specified allowance prices.922

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

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

 

922 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). 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,923 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. 

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.924 

 

923 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.

924 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 
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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, 

enforceable, non-duplicative, and permanent. 

(1) Allowance allocation. A key example is state discretion in 

the CO2 allowance allocation methods included in the program.925

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 

 

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.

925 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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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 

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 
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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 

EPA-administered tracking system.926

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, 

 

926 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. 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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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 

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.927 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 

 

927 The EPA would designate tracking systems that it has 

determined adequately address the integrity elements necessary 

for the issuance and tracking of emission allowances. 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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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-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 
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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 

order to maintain the integrity of the linked programs.928

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 

 

928 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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state’s mass-based CO2 emission goal for affected EGUs (or massbased CO2 goal plus new source CO2 emission complement). The 

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 
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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 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 

state929 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.930

 

929 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.

930 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 

sources.931

 

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).

931 This may apply under both an emission standards plan and a 

state measures plan. Section VIII.J.2.a describes how state plan 
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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.932 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,933 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.

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 

 

submissions must include as requirements, or describe as part of 

supporting documentation, relevant aspects of such emission 

budget trading programs.

932 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).

933 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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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 

the number of net “imported” CO2 allowances.934 Under this 

adjustment, such allowances must be issued by a state with 

 

934 Net “imports” and “exports” of CO2 allowances are defined and 

explained below.
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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 

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 
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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.935 This net transfer 

is determined based on compliance account holdings at the end of 

the plan performance period.936 For example, assume two states, 

State A and State B, with emission budgets of 1,000 tons of CO2. 

 

935 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.

936 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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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. 

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 
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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.

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 
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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 

emission trading program, adjustments may be applied through the 

use of ERCs.937 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 

 

937 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.K.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 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.938 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 are 

based on quantified and verified electricity generation or 

 

938 These requirements are discussed in section VIII.D.
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electricity savings from eligible measures, and in the case of 

an affected EGU’s 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. 

(1) General accounting approach for adjusting a CO2 emission 

rate.

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.K.1.a.(2)-(10) 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
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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.939 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.940 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 

 

939 Requirements for the issuance of ERCs and a further 

discussion of how ERCs are used in compliance with rate-based 

emission limits are addressed in section VIII.K.2.

940 Any ERCs used to adjust a CO2 emission rate must meet 

requirements in the emission guidelines.
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represented in the CO2 emission performance rates in the emission 

guidelines. Specifically, in the calculation of final CO2

emission performance rates, the MWhs of RE are reflected in two 

adjustments of the rate: a reduction of CO2 emissions from 

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.941

When demonstrating achievement of a CO2 emission performance 

rate, the reported CO2 emissions already reflect the actual 

emission reductions from the deployment of qualifying zeroemitting 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 

 

941 For a detailed discussion of this method, see Section VI.C.3. 

Form of the Performance Rates, in the Equation section.
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reductions from qualifying measures, and the denominator 

reflects replaced generation, is consistent with the goalsetting 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 
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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 

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.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. 

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. As a result, the requirements 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.942 These general requirements also address potential 

interactions among rate and mass plans, as discussed more fully 

in section VIII.L. 

As discussed in the sections that follow, the general 

 

942 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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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 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. 

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. Specifically, this means that measures 

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 they produce in 2022 and future years, may be applied 

toward adjusting a CO2 emission rate. 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 measures that are used to adjust a CO2 emission rate 

under a state plan. For example, eligible measures, such as CHP,
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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.

As 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.943 These MWh may be banked from the interim to final 

periods. 

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

 

943 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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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 

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 

provided below.
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First, affected EGUs that have maximized their CO2 emission 

reduction opportunities available through early action will be 

better positioned to meet the BSER CO2 emission performance rates 

or state goal applied to affected EGUs in their 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 its CO2 emission performance rate.

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 rate- or 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 a concern. Furthermore, 
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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.

(b) Demonstration that measures substitute for grid 

generation. 

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. 
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(c) Geographic eligibility. 

All eligible emission reduction measures, including RE 

generation and demand-side EE, may occur in any state, with 

certain limitations, as described below. To the extent these 

measures are tied to a state plan,944 these measures may be used 

to adjust a CO2 emission rate, regardless of whether the 

associated generation or electricity savings occur inside or 

outside the state.945 This approach is generally consistent with 

the approach used in building block 3 of the BSER, which 

reflects regionally available RE. It also recognizes that 

emission reduction measures have impacts on electricity 

generation across the electricity system, both within and beyond 

a state’s borders. A more in-depth discussion of the basis for 

treatment of in-state and out-of-state measures is provided in 

section VIII.L.

State plans must demonstrate that emission standards and 

 

944 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 

standards plan or represents quantified and verified MWh energy 

generation or energy savings achieved by an approved state 

measure in a state measures plan.

945 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. 
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state measures (if applicable) are non-duplicative. Given the 

geographic eligibility approach described here, this includes a 

demonstration that a state plan does not allow 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

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 
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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. 

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. 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 massbased 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 massbased states, including demand-side EE, are restricted from ERC 

issuance in rate-based states.

These criteria are intended to address the fact that 
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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.946 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.947 The result 

 

946 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.

947 As used here, incremental emission reductions refers to 
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would be forgone CO2 emission reductions that would otherwise 

occur across the two states. These dynamics are further 

addressed in section VIII.L.

For RE measures located in a mass-based state to have some 

or all of its generation counted under a rate-based plan in 

another state, it must be demonstrated that the generation was 

delivered to the grid to meet electricity load in a state with a 

rate-based plan.948 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 

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.949 The 

rate-based state must include in its state plan provisions that 

describe a sufficient demonstration of geographic eligibility 

 

emission reductions that are above and beyond what would be 

achieved solely through compliance with the emission standards 

in the mass-based state.

948 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.

949 Requirements for ERC issuance are addressed in section 

VIII.K.2.
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for the RE generation under rate-based emission standards.

Further examples of eligible demonstrations and how they 

should be outlined in state plans are provided in section 

VIII.L.

(ii) Measures that occur in states, including areas of 

Indian country, that do not have affected EGUs. 

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 
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with the ability to contribute to and benefit from CO2 emission 

reductions or CO2 emission rate adjustments. 

For participating states, they must adhere to EM&V 

standards, installation dates, and any other criteria that apply 

to all states. Section VIII.K.3 below identifies and discusses 

the EM&V requirements used to quantify MWh savings from 

generation from zero- or low-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 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.950 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 

 

950 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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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 

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 
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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. RE generation capacity 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 
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been met. 

(3) RE. 

RE measures may be used to adjust a CO2 emission rate, provided 

they meet the general eligibility requirements outlined above 

and the MWh electricity generation is properly quantified and 

verified.951 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. A

capacity uprate at an existing RE facility (i.e., an uprate to 

generating capacity originally installed as of 2012 or earlier) 

is eligible to adjust a CO2 emission rate. The capacity uprate 

must occur after 2012. Such uprates to capacity represent 

incremental capacity added after 2012. 

Quantification and accounting criteria for incremental RE (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 

 

951 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 

RE relied on in a state plan. 
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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.952

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) 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 

 

952 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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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. 

(b) Biomass. 

RE generating capacity installed after 2012 that uses 

qualified biomass as a fuel source is eligible for use in 

adjusting a CO2 emission rate.953 As discussed in section 

VIII.I.2.c., if a state intends 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 qualified biomass feedstocks and 

treatment of biogenic CO2 emissions in its plan, along with 

supporting analysis and quality control measures, and the EPA 

will review the appropriateness and basis for such 

determinations in the course of its review of a state plan.

Where an RE generating unit uses qualified biomass, as 

 

953 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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designated in an approved state plan, MWh generation from the 

unit could be used to adjust the reported CO2 emission rate of an 

affected EGU. Total MWh generation from an RE generating unit 

that uses 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 the plan (i.e., 

the proportion of biogenic CO2 emissions from use of qualified

biomass feedstock that would not be counted)

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.

(c) Waste-to-energy. 

Qualified biomass may include the biogenic portion of MSW 

combusted in a waste-to-energy facility.954 With regard to 

assessing qualified biomass proposed in state plans, the EPA 

 

954 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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generally acknowledges the CO2 emissions and climate policy 

benefits of waste-derived biomass, which includes biogenic MSW 

inputs to waste-to-energy facilities. The process and 

considerations for the use of biomass in state plans are 

discussed in section VIII.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-toenergy facilities or industrial facilities where the waste is 

combusted and energy is recovered.955 Total MSW generation in 

2012 was 251 million tons, but of that total volume generated, 

almost 87 million tons were recycled and composted.956 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 composting and recycling. The EPA and many states have 

recognized the importance of integrated waste materials 

management strategies that emphasize a hierarchy of waste 

 

955 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-

2012. 

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.

html.

956 http://www.epa.gov/osw/nonhaz/municipal/pubs/2012_msw_fs.pdf.
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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.957 For example, Oregon and Vermont have strategies 

that emphasize waste prevention, followed by reuse, then 

recycling and composting materials prior to treatment and 

disposal.958

Information in the revised Framework for Assessing Biogenic 

CO2 Emissions from Stationary Sources and other technical studies 

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.959

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. The EPA 

 

957 http://www.epa.gov/wastes/nonhaz/municipal/hierarchy.htm.

958

http://www.anr.state.vt.us/dec/wastediv/WastePrevention/main.htm

.

959 http://epa.gov/epawaste/conserve/tools/warm/Warm_Form.html, 

https://mswdst.rti.org/.
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will reject as qualified biomass any proposed waste-to-energy 

component of state plans if states do not include information on 

their efforts to strengthen existing or implement 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. 

A state 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. The EPA will evaluate the method as part of its evaluation 

of the approvability of the state plan. Measuring the proportion 

of biogenic to fossil CO2 emissions can be performed through 

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. For an example of the former 

method, if the biogenic fraction of MSW is 50 percent by input 

weight, only the 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, 
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as 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’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. 

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 
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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) DSM.

Avoided MWh that result from DSM may be used to adjust a CO2

emission rate. Eligible DSM actions are those that are zeroemitting and avoid, rather than shift, the use of electricity by 

an electricity end-user.960 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.K.3.

(5) Energy storage. 

Energy storage may not be directly recognized as an 

 

960 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 is also not eligible.
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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.961 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.962 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.963

The EPA received multiple comments regarding the overall 

merits of energy storage. Consistent with the discussion above, 

 

961 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).

962 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. 

963 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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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 (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”964) and T&D measures that 

 

964 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 U.S.

each year. 
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reduce electricity use at the end-user, such as conservation 

voltage reduction (CVR).965 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 criteria under which such measures would be 

permitted in a state plan.

 

965 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 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, per the ANSI C84.1 standards.
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To be eligible, T&D measures must be installed after 2012. 

This general eligibility requirement is discussed above in 

section VIII.K.1.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.K.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 

quantified and verified.966 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, 

 

966 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. 
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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.967 EE measures, for the purposes of this section, may 

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, 

 

967 EE programs may also be implemented by other entities. 

Eligible EE measures that are deployed through EE programs are 

not limited to those EE measures deployed through EE programs 

administered by the types of entities listed here.
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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 

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. 

(8) Nuclear power. 

As is discussed in section V.A.3, upon consideration of 

comments received, the EPA has not included 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 
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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 

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 
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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.

Applicable generation (in MWh) from incremental nuclear 

power is determined in the same manner as that described for 

incremental RE above.

(9) Combined heat and power (CHP) units. 

Electric generation from non-affected CHP units968 may be

used to adjust the CO2 emission rate of an affected EGU, as CHP 

units are low-emitting electric generating resources that can 

replace generation from affected EGUs. Electrical generation 

from non-affected CHP units that meet the eligibility criteria 

 

968 The accounting considerations described in this section are

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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under section VIII.K.1.a can be used 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 

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 is a fossil fuel-fired emission source, as 

well as the fact that the incremental CO2 emissions related to 
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electrical generation from a non-affected CHP unit are typically 

very low. In accordance with these considerations, a nonaffected 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 (a CHP unit’s “incremental 

CO2 emission rate”) compared to a reference CO2 emission rate.

This “incremental CO2 emission rate” related 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 a value between 0 and 1.

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

emissions related to the electrical production from a CHP unit 
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that is used to substitute for electrical generation from 

affected EGUs.

Non-affected CHP units can use qualified biomass fuels. As 

described in section VIII.I.2.c, states must 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 qualified biomass included 

in state plans are discussed in section VIII.I.2.c, while 

accounting requirements for RE using biomass are provided in 

section VIII.K.1.a.(3)(b).

Most comments received on CHP recommended that the EPA 

explicitly describe how CHP can be accounted for in a 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 emission reductions that result from the use of CHP. 

(10) WHP. 

WHP units that meet the eligibility criteria under section 

VIII.K.1 may be used to adjust the CO2 emission rate of an 
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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.969 There are also WHP 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 could be considered zero-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.970 The MWh of electrical output from a WHP unit 

that can be recognized may not exceed the MWh of industrial or 

 

969 In such a configuration, the waste heat stream could also be 

generated from a mechanical process, such as at natural gas 

pipeline compressors.

970 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.
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other thermal load that is being met by the WHP unit, prior to 

the generation of electricity.971 Most commenters that addressed 

WHP noted the benefits of 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 

discussed 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 

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.

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 

 

971 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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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 

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 
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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 

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 
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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 combustion 

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). 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. 

c. Measures that reduce CO2 emissions outside the electric 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 
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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 

measures 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,972 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,973 all emission standards in 

a state plan must be quantifiable, verifiable, enforceable, nonduplicative and permanent.974 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 

 

972 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. 

973 79 FR 34830, 34913.

974 These requirements are described in detail in section 

VIII.D.2.
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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.975 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. 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 

 

975 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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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).976 These specific requirements for a rate-based emission 

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 

 

976 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 

implemented using a rate-based emission trading approach are 

quantifiable, verifiable, enforceable, non-duplicative, and 

permanent.
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rate-based emission standard.977 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. 

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 

 

977 See section VIII.K.1 for a discussion of the accounting 

method used to adjust a CO2 emission rate.
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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.978

ERCs may be used by an affected EGU to adjust its reported 

CO2 emission rate when demonstrating compliance with a rate-based 

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 

 

978 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 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 

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 
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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 

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 
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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:

ERCs979 = reported MWh by affected EGU980 x ((CO2 emission 

rate limit for affected EGUs981 – affected EGU reported CO2

emission rate982)/ 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 

 

979 For all calculations in this section, where the result is a 

negative value, no ERCs would be issued.

980 This term represents the reported MWh by the affected EGU on 

an annual basis.

981 This term represents the “reference rate.”

982 This term represents the annual reported CO2 emission rate of 

the affected EGU.
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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

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:

ERCs983 = reported MWh x ((steam generating unit CO2 emission 

rate limit984 – 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 

 

983 For all calculations in this section, where the result is a 

negative value, no ERCs would be issued.

984 The “reference rate.”
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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 

standard985 – 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 

NGCC unit986 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 

 

985 The “reference rate.”

986 This is the CO2 emission performance rate for affected 

stationary combustion turbines in the emission guidelines.
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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 

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 
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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 

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.987 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 project988 to the 

 

987 Qualifying measures that can be used to adjust the CO2

emission rate of an affected EGU are discussed at section 

VIII.K.1, and include RE, demand-side EE, and other measures, 

such as DSM, CHP and incremental nuclear generation.

988 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 
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administering state regulator (or its agent989). The state 

regulator reviews the application to determine whether, in this 

example, an EE/RE program or project meets eligibility 

requirements for the issuance of ERCs.990 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.991 A 

 

apply for all other eligible qualifying measures discussed in 

section VIII.K.1.

989 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. 

990 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 

industrial EE programs, among others.

991 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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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 

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.992 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 

 

992 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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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 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 
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verifier, such that it can no longer provide verification 

services related to an eligibility application or M&V report for 

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.993 These 

provisions will ensure that actions that are eligible for the 

issuance of ERCs are “non-duplicative.”994 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. 

 

993 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.

994 Emission standards must be “non-duplicative” as described in 

section VIII.D.2. 
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In the second step of the process, following implementation 

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.995 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 

 

995 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.996 The tracking system must 

provide transparent electronic public access to submitted M&V 

reports and regulatory approvals related to such reports.997 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,998 and an accompanying tracking system 

that meets requirements specified in the emission trading 

 

996 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.

997 This must include electronic Internet access to such 

information in the tracking system.

998 “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 standard.
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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 

eligible zero-emission MWh as required in the emission 

guidelines. A variety of situations may result in such improper 
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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.999 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 outputweighted average CO2 emission rates of the interim and final 

state CO2 goals are achieved over the course of a state plan. 

 

999 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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Banking provisions have been used extensively in rate-based 

environmental programs and mass-based emission budget trading 

programs.1000 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.1001 State plans must specify whether the state is allowing 

or restricting the banking of ERCs between compliance periods 

for affected EGUs. State plans must also prohibit borrowing of 

any ERCs from future compliance periods by affected EGUs or 

eligible resources.

 

1000 Banking under mass-based emission budget trading programs, 

and the rationale for banking provisions, is addressed below in 

section VIII.J.2.c.

1001 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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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 

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 
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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 

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, 
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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 

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 
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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 

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 
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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.1002 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 

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.1003

 

1002 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. 

1003 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. 
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As discussed in section VIII.K.1, quantified and verified 

MWh of RE generation, EE savings,1004 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 

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 

 

1004 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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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” 

TSD1005 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 

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.

 

1005 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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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 

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 
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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) 

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 
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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 

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 
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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 

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, 
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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.

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 
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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 

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 
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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 

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.1006

The approaches described in this section are only allowed 

for states that impose rate-based emission limits for affected 

 

1006 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 section VIII.K.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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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.1007 This assures that all the 

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.

 

1007 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 

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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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 

standards were issued by states with an EPA-approved state 

plan.1008

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-approved1009 or EPA-administered 

 

1008 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).

1009 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 section 

VIII.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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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 

revisions.1010

 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 issuance1011 and their issuance of ERCs 

 

1010 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.

1011 This refers to eligibility applications and M&V reports, 

which are required submittals for non-affected 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 
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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 

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.1012

L. Treatment of Interstate 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 

 

they are subject to a rate-based emission standard. Requirements 

for ERC issuance are discussed in section VIII.K.2.

1012 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.L 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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of generation from source to source. The section also discusses 

how the final rule addresses these concerns: 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.1013

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 

 

1013 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. These interactions 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 zero-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 states. 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 measure can affect EGU generation and CO2

emissions across the regional grid. These impacts can change 

across multiple affected EGUs on a minute-to-minute, hour-tohour, and day-to-day basis as electricity demand changes and 

different generating resources are dispatched. These impacts 

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-based) and the individual 

characteristics of the plans that states choose to adopt. 

In the context of this complex environment of federal and 
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state policies and interstate grids, commenters expressed 

concern about the risk of double-counting of measure impacts, 

particularly across state plans. Commenters stated that there is 

potential for distortionary incentives that could undermine 

overall CO2 emission reductions (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.

The EPA acknowledges that some amount of shifts 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 loweremitting 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 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 
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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 

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 
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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 double-counting and the distortionary effects 

that could potentially increase emissions. First, states have 

the option to adopt multi-state plans that reflect 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 an affected EGU’s or state’s CO2 rate that 

inherently acts to minimize state differences. These points are 

further discussed below.

For both rate-based and mass-based approaches, the rule 

provides states with the option of creating either “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. 
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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 

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.
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Under all types of state plans, states must ensure that the 

emission reduction measures counted as part of meeting their 

plan requirements are not duplicative of any measures that are 

counted by another state, 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 have 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
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from affected EGUs, which avoids concerns about counting the 

same mass reductions in two different mass-based states.

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 measures 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 would 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 the 

rule’s accounting approach for adjusting the CO2 emission rate of 

an affected EGU, detailed in section VIII.K.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 measures that were not included in the 

determination of the BSER 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 demandside 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. Double-counting of CO2 emission 

reductions is prevented because the reported emissions 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 to any particular 

MWh of RE or demand-side EE. Because the general accounting 

approach disallows any adjustment to any EGU’s reported 

emissions, it is not possible for the real emission reductions 

prompted by any particular measure to be double-counted. 

Double-counting of MWhs in the denominator can be avoided 

because it is relatively straightforward to quantify the MWhs 
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that the affected EGU is responsible for deploying and add them 

to the denominator, and this method aligns well with the MWhdenominated 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.K, 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 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 
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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 

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 budget, which is met by affected EGUs adjusting 
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their generation. Low- or zero-emitting 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 doublecounting of emission reductions can take place.

Though there is no risk of double-counting emissions, some 

commenters expressed the concern that overall CO2 emissions 

reductions would be foregone in situations where a source in a 

rate-based state counts the MWh from measures in a mass-based 

state, but the generation from that measure acts solely to serve 

load in the mass-based state. In 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 

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 and state CO2

goals. Allowing crediting between rate- and mass-based states, 
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as long as the risk of foregone CO2 emission reduction actions in 

rate-based states are minimized, will assure a supply of 

eligible RE 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 rate-based states 

to count MWhs from RE located in mass-based states, subject to 

the condition that the generation in question was intended to 

meet electricity load in a state with a rate-based plan.1014 This 

may apply to some or all of the generation from an individual RE 

installation. To assure that the RE generation in question meets 

this condition, the EPA is requiring that RE generation from RE 

installations located in a mass-based state can only be counted 

in a rate-based state if the electricity 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, 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 MWhs in 

question. The EPA is providing flexibility to states regarding 

the nature of the required demonstration, though the state must 

 

1014 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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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. 

The following are examples of how requirements for a 

demonstration could be established in state plans and used to 

allow RE in a mass-based state to be counted in a rate-based 

state. For an emission 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 an RE provider 

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 as part of an 

eligibility application a delivery contract or power purchase 

agreement showing that the generation was procured by the 

utility, and was treated as 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 this additional geographic 

eligibility requirement for the amount of generation in 

question. All quantified and verified RE MWhs submitted for ERC 

issuance would need to be associated with that power purchase 
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contract or agreement, and this fact would need to be 

demonstrated in the M&V reports submitted for issuance of ERCs. 

The ability for a rate-based state to count MWhs located in 

a mass-based state under the above conditions is limited to RE.

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 rate-based sources’ access to 

additional resources, 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 standard 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. 

Finally, as stated earlier, commenters also expressed 

concern about the potential for 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 
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sources. These differences could induce increased generation in 

one state over 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 increasing 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. 

Commenters 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 
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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 

finalized in this rule. As explained above regarding the general 

accounting approach and 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 zero-emitting 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 zero-emitting ERCs in a particular 

state based upon the rates that apply to that state.

IX. Community and Environmental Justice Considerations

In this section we provide an overview of the actions that

the agency is taking to help ensure that vulnerable communities 
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are not disproportionately impacted by this rulemaking.1015As 

described in the Executive Summary, climate change is an 

environmental justice issue. Low-income communities and 

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 GHGs, 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). 

 

1015 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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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 

will be achieved through this rule because the electric 

generating units that emit the most GHGs 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.1016 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 

 

1016 Six Common Air Pollutants. 

http://www.epa.gov/oaqps001/urbanair/
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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. 

By reducing millions of tons of CO2 emissions that are 

contributing to global GHG 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 
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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 

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 EE. 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 EE programs such 
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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 engage with these communities, 

including workers and their representatives in these sectors, 

including EE. 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.1017 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 

 

1017 Detailed information on the outreach conducted as part of 

this rulemaking is provided in section I of this preamble.
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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 

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 

The EPA is committed to assisting states and communities to

develop plans that ensure there are no disproportionate, adverse 

impacts on overburdened communities. To provide information 

fundamental to beginning that process, the EPA has conducted a

proximity analysis for this final rulemaking that summarizes 
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demographic data on the communities located near power plants.1018

The EPA understands that, in order to prevent 

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 that 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 U.S. 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 is important

to note that the impacts of power plant emissions are not 

 

1018 The proximity analysis was conducted using the EPA’s 

environmental justice mapping and screening tool, EJSCREEN.
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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 high percentages of lowincome populations and lower percentages of communities of 

color. In urban areas, nearby communities tend to be both lowincome 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 lowincome 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 communities, including indigenous 

communities most often located in rural areas, thatare central 

to our environmental justice and community considerations.
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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 vulnerable

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/.

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 
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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 

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 
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copy of their analysis if they choose to conduct one, with their 

initial and final plan submittals. 

B. Community Engagement in State Plan Development 

In sections VIII.D-E of this preamble, the EPA explains

that states need to engage meaningfully with communities and 

other stakeholders during the initial and final plan submittal 

processes. Meaningful engagement includes 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 

initial submittal and responding to significant comments 

received, including comments from vulnerable communities, 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 

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 
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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 rule requires that states demonstrate how they are 

meaningfully engaging vulnerable communities and other 

interested stakeholders as part of their public participation 

process. The 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 to assist them in engaging meaningfully with 

vulnerable communities.1019 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 

 

1019 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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engagement with vulnerable communities, are outlined in section 

VIII.E of this preamble. Additionally, as outlined in section 

VIII.D, the final plan submitted by states must 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. 

The EPA is committed to supporting states in effectively 

engaging with communities as they develop and implement their 

plans. The EPA will provide training and other resources 

throughout the implementation process that will assist states 

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 reach out to a 

wide variety of community stakeholders, including groups 

representing environmental justice communities, faith-based 

organizations, academic organizations working with vulnerable 

and overburdened communities, affordable housing advocates, 

public health professionals, public health organizations, and 

other community stakeholders.

C. Providing Communities with Access to Additional Resources

In addition to providing resources to states, the EPA 

encourages states to be aware of existing efforts undertaken by 

other states aimed at providing low-income communities access to 
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financial 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 a program targeted at low-income communities 

is the Maryland EmPOWER Low Income Energy Efficiency Program 

(LIEEP).1020 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.).1021 Funding for 

this program is provided by EmPOWER Maryland partners: Baltimore 

Gas and Electric, Southern Maryland Electric Cooperative, 

Delmarva Power, Allegheny Energy and Pepco.1022 This program is 

available to both homeowners and renters.1023 Additionally, the 

 

1020 EmPOWER Maryland Low Income Energy Efficiency Programs 

(LIEEP). 

http://www.mdhousing.org/website/Programs/lieep/Default.aspx.

1021 Ibid.

1022 Ibid.

1023 Ibid. 
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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).1024 Maryland’s Electric Universal Service Program (EUSP) 

helps low-income electric customers with their electric bills.1025

Another example of a program is EmPower New York, which 

provides no-cost energy solutions to low-income populations.1026

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 EE upgrades (plugging leaks, adding insulation, 

replacing inefficient refrigerators and freezers and new energyefficient lighting). Other states, like the State of Colorado’s 

Energy Outreach Colorado program, offer similar resources for 

low-income populations.1027

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 EE loans that were available to all utility 

 

1024 Energy Assistance. 

http://www.dhr.state.md.us/blog/?page_id=4326.

1025 Ibid.

1026 EmPower New York. http://www.nyserda.ny.gov/AllPrograms/Programs/EmPower-New-York

1027 Energy Outreach Colorado. http://www.energyoutreach.org/about
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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 RE, 

EE, and the economic benefits of a cleaner energy economy. 

In the coming months, the EPA will continue to provide 

information and resources for communities and states on existing 

federal, state, local, and other financial assistance programs 

to encourage EE/RE opportunities that are already available to 

communities. For example the EPA will 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 vulnerable communities gain the 

benefits of this rulemaking by encouraging that states use these 

types of tools in their state plans. The use of these RE/EE 

tools can also help low-income households reduce their 

electricity consumption and bills.

The EPA recognizes the potential impacts that this 

rulemaking could have on jobs in communities. Therefore, in 

section VIII.G 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 
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development to realize the opportunities for economic growth and 

jobs that the plans offer. To the extent possible, states should 

try to assure that communities that may 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 delivering EE

measures and installing rooftop solar panels). Additionally, as 

part of the resources that we will be providing to states and 

low-income communities, the EPA will provide information on the 

Administration’s Partnerships for Opportunity and Workforce and 

Economic Revitalization (POWER) Initiative and other programs 

that specifically target economic development assistance to 

communities affected by changes in the coal industry and the 

utility power sector.1028 

D. Federal Programs and Resources Available to Communities

Federal agencies have a history of bringing EE and RE 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 

 

1028

 http://www.eda.gov/power
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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 moderate- income communities. The Administration also 

set a goal to install 300 megawatts (MW) of RE 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 

funding for EE and RE. 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 EE and 

accelerate the deployment of RE 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, 
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High Cost Energy Grant Program, and the Rural Housing Service’s 

Multi-Family Housing Program.

HUD supports EE improvements and the deployment of RE 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 to support RE

development and EE in low-income communities, including the New

Markets Tax Credit Program and the Low-Income Housing Tax 

Credit. The EPA’s RE-Powering America’s Land Initiative promotes 

the reuse of potentially contaminated lands, landfills and mine 

sites – many of which are in low-income communities – for RE

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 EE 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 
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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 

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 
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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 

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.

Air quality in a given area is affected by emissions from 

nearby sources and may be influenced by emissions that travel 
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hundreds of miles and mix with emissions from other sources.1029

In the Cross-State Air Pollution Rule the EPA used its authority 

to reduce emissions that significantly contribute to downwind 

exposures. The RIA for the final Cross-State Air Pollution Rule 

anticipates substantial health benefits for the population 

across a wide region. Similarly, 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.1030

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 may 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 may operate more 

hours during the year and could emit pollutants, including 

pollutants whose environmental effects would be localized and 

regional rather than global as is the case with GHG emissions. 

Changes in utilization already occur in response to energy 

 

1029 76 FR 48348.

1030 76 FR 48347.
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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 gasfired sources likely to be dispatched more frequently have very 

low emissions of primary PM, SO2, and HAP per unit of electrical 

output and that they must continue to comply with other CAA 

requirements that directly address the conventional pollutants, 

including federal emission standards, rules included in SIPs, 

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 

impacts due to HAP emissions from such units are negligible 

based on the results of the study documented in the utility 
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RTC.”1031 Because gas-fired EGUs emit essentially no mercury, 

increased utilization will not increase methyl mercury 

concentrations in water bodies near these affected EGUs. In 

studies done by DOE/NETL comparing cost and performance of coaland NGCC-fired generation, they assumed SO2, NOx, 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.1032 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. 

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 

 

1031 65 FR 79831.

1032 “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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quality in all areas or whether there are localized air quality 

impacts that need to be addressed under other CAA authorities.

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 GHGs 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.1033 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.1034 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 

 

1033 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.

1034 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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communities on resources that they can use to 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. 

G. EPA Continued Engagement 

The EPA is committed to helping ensure that this action 

will not have disproportionate adverse human health or 

environmental effects on vulnerable communities. Throughout the 

implementation phase of this rulemaking, the agency will 

continue to provide trainings and resources to assist 

communities and states as they engage with one another. 

Additionally, we will provide states with recommendations on 

best practices for engaging with vulnerable communities. The 

EPA, through its outreach efforts during implementation, will 
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continue to solicit feedback from communities and states on 

topics for which they would like additional trainings and 

resources.

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 vulnerable communities, as well 

as information on its publicly available environmental justice 

screening and mapping tool, EJ SCREEN. States 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 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 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 
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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.

In summary, the EPA in this final rulemaking has designed 

an integrative approach that helps to ensure that vulnerable 

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.
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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 

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. 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 above the applicable 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 undergoes a change or 

change in the method of operation (modification) that results in 

a significant increase in the emissions of a pollutant other 

than GHGs and results in a GHG emissions increase of 75,000 tons 

per year CO2e as well as a GHG emissions increase on a mass 
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basis. Once it has been determined that a change triggers the 

requirements of the NSR 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 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 emission guidelines. One of these flexibilities 

is the ability of the state to establish emission standards 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 that trigger NSR. To achieve 
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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 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 use demand-side 

measures or increase reliance on RE 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).1035

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 

section 111 standard to regulate GHGs. Specifically, the EPA 

 

1035 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 Title 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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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 

recover the costs of addressing GHGs in permitting. The GHG 

adjustments we are finalizing are based on accounting for the 
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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 

this rulemaking was published, the U.S. 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 
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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 

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.
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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.1036 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 

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 

 

1036 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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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 

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 
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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 

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))
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(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.1037 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 

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 

 

1037 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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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.

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 
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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 

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.
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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 U.S. 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 

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 
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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 

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 
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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.

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 SIPs, with due dates starting in 

October 2018 for infrastructure and interstate transport SIPs, 

attainment plans due 2020-21, and attainment dates of 2020-37. 
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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) emission guidelines. In 

particular, commenters raised issues with a 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) emission 

guidelines proposal, commenters expressed a desire for the EPA 

to coordinate promulgation of the final 111(d) emission 

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 
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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 

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 
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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 

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.1038 These 

 

1038 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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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.

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) emission 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 
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reductions that will result from retirements, fuel switching, 

reduced utilization, or lesser controls at multiple EGUs.

In fact, the EPA already has experience working with states 

to account for these very types of changed circumstances.

1039 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 

 

1039 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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source-by-source limitations reflecting the BSER performance 

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.1040 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 Action1041

A. What are the air impacts?

The EPA anticipates significant emission reductions under 

the final guidelines for the utility power sector. In the final 

 

1040 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.

1041 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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emission guidelines, the EPA has translated the source categoryspecific CO2 emission performance rates into equivalent statelevel 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, which we term the “rate-based”

illustrative plan approach and the “mass-based” illustrative 

plan approach.1042

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 co-

 

1042 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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benefits 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.

Table 15. Summary of CO2 and Other Air Pollutant Emission 

Reductions from the Base Case under Rate-based Illustrative Plan 

Approach

CO2

(millions

short tons)

SO2

(thousand 

short tons)

NOX

(thousand

short tons)

2020 Final Guidelines

Base Case 2,155 1,311 1,333

Final Guidelines 2,085 1,297 1,282

Emissions Reductions 69 14 50

2025 Final Guidelines

Base Case 2,165 1,275 1,302

Final Guidelines 1,933 1,097 1,138

Emissions Reductions 232 178 165

2030 Final Guidelines

Base Case 2,227 1,314 1,293

Final Guidelines 1,812 996 1,011

Emissions Reductions 415 318 282

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
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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 Tables 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.

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.
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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 

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.1043 Indirect effects are those that 

 

1043 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., 
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are “caused by the proposed action and are later in time, but 

still are reasonably certain to occur.” Id. To trigger the

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). The 

EPA recognizes that beneficial effects to listed 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 

 

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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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 

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.1044 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. 

 

1044 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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As 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 about 415 million short tons of CO2 in 

2030 relative to the base case under the rate-based illustrative 

plan approach– see Table 14 above), the EPA evaluated larger 

reductions in assessing this same issue in the context of the 

light duty vehicle GHG emission standards for model years 2012-

2016 and 2017-2025. There the agency projected emission 

reductions over the lifetimes of the model years in question1045

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 

 

1045 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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Economy Standards, Response to Comment Document for Joint 

Rulemaking at 4-102 (Docket EPA-OAR-HQ-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 believes that the 

same conclusion applies to the present rule. 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.1046

 

1046 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 
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With regard to non-GHG air emissions, the EPA also projects 

substantial reductions of SO2 and NOX as a collateral consequence 

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).

Finally, the EPA has also considered other potential 

effects of the rule (beyond reductions in air pollutants) and 

 

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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whether any such effects are “caused by” the rule and 

“reasonably certain to occur” within the meaning of the ESA 

regulatory 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 SIPs).1047 The EPA recognized, for instance, that 

 

1047 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 NAAQS under the CAA– 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 

SIPs. States can choose to impose or avoid the types of impacts 

at issue in the D.C. Circuit case through their planning 
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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 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 regarding 

potential effects of the rule on the Big Bend Power Station 

located in Florida, which discharges effluent that provides a 

warm water refuge for manatees. The Big Bend Power Station and 

another coal-fired facility located in Florida – the Crystal 

 

decisions; thus such impacts were not viewed as having 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 SIP 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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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 

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 
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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.1048 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

rule for ESA purposes. These steps will flow from a series of 

later in time decisions generally made by other entities –

usually states – in their distinct planning processes. These 

later decisions cannot now be required by the rule, 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-

 

1048 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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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.1049 These are precisely the types of 

speculative future activities and effects at issue here.1050 For 

this additional reason, the EPA concludes that the rule does not 

 

1049 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 

administrative discretion remains to be exercised, the less 

there is reasonable certainty the action will proceed).

1050 EPA also notes that some of the future implementing 

activities may 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 RE 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.
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have effects on listed species that trigger the section 7(a)(2) 

consultation requirement.1051

C. What are the energy impacts?

The final guidelines have important energy market 

implications. Table 17 presents a variety of important energy 

 

1051 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 

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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market impacts for 2020, 2025, and 2030 under both the ratebased and mass-based illustrative plan approaches. 

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

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 EE 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 EE 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, 
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transmission system improvements, use of energy storage 

technologies or retrofit CCS, could also mitigate gas price 

and/or electricity price impacts.

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 EE. 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.
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The incremental cost is the projected additional cost of 

complying with the guidelines in the year analyzed and includes 

the amortized cost of capital investment, needed new capacity, 

shifts between or amongst various fuels, deployment of demandside EE programs, and other actions associated with compliance. 

These important dynamics are discussed in more detail in the RIA

in the rulemaking docket. 

The EPA estimates the annual incremental compliance cost 

for the rate-based approach for final emission guidelines to be 

$2.5 billion in 2020, $1.0 billion in 2025 and $8.4 billion in 

2030, including the costs associated with monitoring, reporting, 

and recordkeeping (MR&R).1052 The EPA estimates the annual 

incremental compliance cost for the mass-based approach for 

final emission guidelines to be $1.4 billion in 2020, $3.0 

billion in 2025 and $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? 

The final standards are projected to result in certain 

changes to power system operation as a compliance with the 

 

1052 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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standards. See Table 16 above for a variety of important energy 

market impacts for 2020, 2025, and 2030 under both the ratebased and mass-based illustrative plan approaches.

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. 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 EE levels are expected to increase such that they achieve 

about 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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implementing the guidelines may choose to mitigate impacts to 

some markets outside the utility power sector. Similarly, demand 

for new generation or demand-side EE 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. While the economy continues moving 

toward full-employment, 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, 

the EPA’s employment analysis includes projected employment 
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impacts associated with illustrative plan approaches for these 

guidelines for the electric power industry, coal and natural gas 

production, and demand-side EE 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 electricity, 

coal, and natural gas sectors, the EPA estimates that these 

guidelines could result in a net decrease of approximately 

25,000 job-years in 2025 for the final guidelines under the 

rate-based illustrative plan approach and approximately 26,000 

job-years in 2025 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 mass-based approach.

The agency is also offering an illustrative calculation of 

potential employment effects due to demand-side EE programs. 

Employment impacts from demand-side energy EE programs in 2030 

could range from approximately 52,000 to 83,000 jobs under the 

final guidelines. 

By its nature, demand-side EE 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 
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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, 

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. 
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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 $3.5 to $4.6 billion 

in 2020, $18 to $28 billion in 2025, and $34 to $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 15 through 22 of this preamble.

Table 18. 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 

short tons)

69 232 415

5 percent (average 

SC-CO2)

$0.80 $3.1 $6.4
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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)

$3.3 $12 $20

2.5 percent 

(average SC-CO2)

$4.9 $17 $29

3 percent (95th

percentile SC-CO2)

$9.7 $35 $60

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 19. 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 

Reductions 

(thousands 

of short 

tons)

Monetized 

Health Cobenefits

Monetized 

Health Cobenefits

(3 percent 

discount)

(7 percent 

discount)

Final Guidelines, Rate-based Approach, 2020

PM2.5 precursors b
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SO2 14 $0.44 to 

$0.99

$0.39 to 

$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 Co-benefits $0.70 to 

$1.8

$0.64 to 

$1.7

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$3.5 to $4.6 $3.5 to $4.5

Final Guidelines, Rate-based Approach, 2025 

PM2.5 precursors b

SO2 178 $6.4 to $14 $5.7 to $13

NOX 165 $0.56 to 

$1.3

$0.50 to 

$1.1

Ozone precursor c

NOX (ozone season only) 70 $0.49 to 

$2.1

$0.49 to 

$2.1

Total Monetized Health Co-benefits $7.4 to $18 $6.7 to $16

Total Monetized Health Co-benefits 

combined with Monetized Climate

Benefits d

$18 to $28 $17 to $26

Final Guidelines, Rate-based Approach, 2030

PM2.5 precursors b

SO2 318 $12 to $28 $11 to $25

NOX 282 $1.0 to $2.3

$0.93 to 

$2.1

Ozone precursor c

NOX (ozone season 

only) 118 $0.86 to 

$3.7

$0.86 to 

$3.7

Total Monetized Health Co-benefits $14 to $34 $13 to $31

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$34 to $54 $33 to $51

a All estimates are rounded to two significant figures, so 

estimates may not sum. It is important to note that the 
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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 cobenefits 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.

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 

Monetized 

Health Cobenefits

Monetized 

Health Cobenefits
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(thousands 

of short 

tons)

(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

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
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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 cobenefits 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.
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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 

rulemaking.1053 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., 

 

1053 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 

July 2015). Available at:

http://www.whitehouse.gov/sites/default/files/omb/inforeg/scctsd-final-july-2015.pdf.
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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 

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)1054 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).1055

 

1054 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.

1055 The current version of the TSD is available at: 

https://www.whitehouse.gov/sites/default/files/omb/inforeg/scc-
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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 IWG

continues to recommend the use of the SC-CO2 estimates in 

regulatory impact analysis.1056 With the release of the response 

 

response-to-comments-final-july-2015.pdf, Docket ID EPA-HQ-OAR2013-0495, 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 July 2015).

1056 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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to comments, the IWG announced plans to obtain expert 

independent advice from the National Academies of Sciences, 

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 Academies 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 Academies 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 

the results from the model that was affected by the indexing 

error.
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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: $12, $40, $60, and 

$120 per short ton of CO2 emissions in the year 2020 (2011$).1057

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 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

 

1057 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 

GDP Implicit Price Deflator, http://www.gpo.gov/fdsys/pkg/ECONI2013-02/pdf/ECONI-2013-02-Pg3.pdf.
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percentile of the SC-CO2 from all three models at a 3 percent 

discount rate. It is included to represent higher-than-expected 

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 

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 

IWG plans to seek independent expert advice on technical 
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opportunities to improve the SC-CO2 estimates from the Academies. 

The Academies 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 BenMAP1058 to calculate

average regional benefit-per-ton estimates using the health 

impact assumptions used in the PM NAAQS RIA1059 and Ozone NAAQS 

 

1058 http://www.epa.gov/airquality/benmap/index.html

1059 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 
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RIAs.1060,1061 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.1062 All benefit-per-ton estimates reflect the 

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 

 

document number EPA-452/R-12-003, December). Available at: 

<http://www.epa.gov/pm/2012/finalria.pdf>.

1060 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>.

1061 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>. 

1062 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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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) 1063 and 

Lepeule et al. (2012) 1064. 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 

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 

 

1063 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.

1064 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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on the American Cancer Society cohort study (Krewski et al, 

2009) and one based on the extended Six Cities cohort study

(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

(Roman et al., 2008)1065 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)1066 and the upper end based on a

benefit-per-ton estimate using the function from Levy et al. 

 

1065 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.

1066 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.
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(2005).1067 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,1068 which evaluated the substantial body of 

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 

 

1067 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.

1068 U.S. Environmental Protection Agency. 2009. Integrated 

Science Assessment for Particulate Matter (Final Report). 

Research Triangle Park, NC: National Center for Environmental 

Assessment, RTP Division. (EPA document number EPA-600-R-08-

139F, December). Available at: 

http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546.
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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,1069 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

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, 

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. 

 

1069 In addition, site-specific emission reductions will depend 

upon how states implement the guidelines.
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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 

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 
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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 guidelines. 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 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 cobenefits 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 
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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. 

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 

July 2015) (“current TSD”) to analyze CO2 climate impacts of 
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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 

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 
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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. 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 $2.8 billion for the rate-based approach and 

$3.3 billion for the mass-based approach (3 percent model 

average). For the rate-based approach, the air pollution 

health co-benefits in 2020 are estimated to be $0.7 billion 

to $1.8 billion (2011$) for a 3 percent discount rate and 

$0.64 billion 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 demand-
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side EE program and participant costs and MRR costs in 

2020, are approximately $2.5 billion for the rate-based 

approach and $1.4 billion for the mass-based approach 

(2011$). The quantified net benefits (the difference 

between monetized benefits and compliance costs) in 2020 

are estimated to range from $1.0 billion to $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 $10 

billion for the rate-based approach and $12 billion for the 

mass-based approach (3 percent model average). For the ratebased approach, the air pollution health co-benefits in 2025 are 

estimated to be $7.4 billion to $18 billion (2011$) for a 3 

percent discount rate and $6.7 billion to $16 billion (2011$) 

for a 7 percent discount rate. For the mass-based approach, the 

air pollution health co-benefits 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 EE program and 

participant costs and MRR costs in 2025, are approximately $1.0 

billion for the rate-based approach and $3.0 billion for the 
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mass-based approach (2011$). The quantified net benefits (the 

difference between monetized benefits and compliance costs) in 

2025 are estimated to range from $17 billion to $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 $20 

billion for the rate-based approach and $20 billion for the 

mass-based approach (3 percent model average). For the ratebased approach, the air pollution health co-benefits in 2030 are 

estimated to be $14 billion to $34 billion (2011$) for a 3 

percent discount rate and $13 billion to $31 billion (2011$) for 

a 7 percent discount rate. For the mass-based approach, the air 

pollution health co-benefits 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 EE program and participant costs 

and MRR costs in 2030, are approximately $8.4 billion for the 

rate-based approach and $5.1 billion for the mass-based approach 

(2011$). The quantified net benefits (the difference between 

monetized benefits and compliance costs) in 2030 are estimated 

to range from $26 billion to $45 billion (2011$) for the rate-
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based approach and from $26 billion to $43 billion (2011$) for 

the mass-based approach, using a 3 percent discount rate (model 

average).

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

Rate-Based Approach 

2020 2025 2030

Climate 

Benefitsb

5% discount 

rate

$0.80 $3.1 $6.4 

3% discount 

rate

$2.8 $10 $20 

2.5% 

discount 

rate

$4.1 $15 $29 

95th 

percentile 

at 3% 

discount 

rate

$8.2 $31 $61 

Air Quality Co-benefits Discount Rate
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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

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 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 
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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 EE 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% 

$9.7 $35 $60 
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discount 

rate

Air Quality Co-benefits Discount Rate

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

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 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 

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 
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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 EE 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 

benefits also include climate benefits from reducing emissions 

of non-CO2 GHGs (e.g., nitrous oxide and methane) and co-benefits 

from reducing direct exposure to SO2, NOX and hazardous air 

pollutants (e.g., mercury), as well as from reducing ecosystem 

effects and visibility impairment. Based upon the foregoing 

discussion, it remains clear that the benefits of this final 
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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.

This rule does not directly impose specific requirements on 

EGUs located in states 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 
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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.

This rule does impose specific requirements on state 

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 505,000 to 821,000
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hours at a total annual labor cost of $35.8 to $58.1

million. The lower bound estimate reflects the assumption that 

some states already have EE and RE programs in place. The higher 

bound estimate reflects the overly-conservative assumption that 

no states have EE and RE programs in place. 

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 54,000 hours at a total annual labor cost of $3.00 million. 

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 

the RFA. This action will not impose any requirements on small 

entities. Specifically, emission guidelines established under 
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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 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 SIPs. 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 

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 
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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 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 governments that have affected 

EGUs. Specifically, states are required to develop plans to 

implement the guidelines under CAA section 111(d) for affected 

EGUs. The burden for states 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.
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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 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 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 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 
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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 

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, 
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(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 

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 
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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 

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 
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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 

between states, and other multi-state compliance approaches that 

will further support electric system reliability. The EPA is 

also requiring each state to demonstrate in its final state that 

it has considered electric system reliability issues in 

developing its plan - and is providing the time 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 for 

states to complete the tasks necessary to finalize a state plan, 
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including administrative and potential legislative processes. 

Recognizing this, as well as the urgent need for actions to 

reduce GHG emissions, the EPA is requiring states to make an 

initial submittal by September 6, 2016, and is allowing states 

two additional years to submit a final plan, if justified (to be 

submitted by September 6, 2018).

States commented on state plan development and 

implementation topics that included state plan approaches, early 

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 supported providing incentives for states 

and utilities 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 establishing the CEIP to provide opportunities for 
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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 EGUs. 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 

implement multi-state trading or averaging approaches. 

In their comments, many states identified the need for the 
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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 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 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 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 
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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 

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 
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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 

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 
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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 

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 
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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 

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 
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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 

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 
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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 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.
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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 

children. Accordingly, the agency has evaluated the 

environmental health and welfare effects of climate change on 

children. 

CO2 is a potent GHG that contributes to climate change and 

is emitted in significant quantities by fossil fuel-fired 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 cobenefit, 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.
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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 

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 1 to 

2 percent change in retail electricity prices on average across 

the contiguous U.S. in 2025, and a 22 to 23 percent reduction in 

coal-fired electricity generation as a result of this rule. The 
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EPA projects that utility power sector delivered natural gas 

prices will increase by up to 2.5 percent in 2030. For more 

information on the estimated energy effects, please refer to the 

economic 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 
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when everyone enjoys the same degree of protection from 

environmental and health hazards and equal access to the 

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).1070 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 

 

1070 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases Under Section 202(a) of the Clean Air Act,” 74 FR 66496 

(Dec. 15, 2009) (“Endangerment Finding”).
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the fact that certain groups, including children, the elderly, 

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 U.S.1071 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 jointly by ethnic/racial 

characteristics and geographic location) may be uniquely 

 

1071 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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vulnerable to climate change health impacts in the U.S. 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 U.S.

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 

affected EGUs that reduce generation due to higher adoption of 

EE and RE. These emission reductions will include SO2 and NOx, 

which form ambient PM2.5 and ozone in the atmosphere, and 
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hazardous air pollutants (HAP), such as mercury and hydrochloric 

acid. In the final rule revising the annual PM2.5 NAAQS,1072 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 

susceptibility to PM-related effects.1073 In 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 

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 taken a number of actions to help ensure 

that this action will not have potential disproportionately high 

 

1072 “National Ambient Air Quality Standards for Particulate 

Matter, Final Rule,” 78 FR 3086 (Jan. 15, 2013).

1073 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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and adverse human health or environmental effects on 

overburdened communities. The EPA consulted its May 2015, 

Guidance on Considering Environmental Justice During the 

Development of Regulatory Actions, when determining what actions 

to take.1074 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)

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 

 

1074 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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(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)).
Carbon Pollution 

Emission Guidelines for Existing Stationary Sources: Electric 

Utility Generating Units

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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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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 Which 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 State

plan? 

60.5720 What if I do not submit a plan or my plan is not 

approvable?

60.5725 In lieu of a State plan submittal, are there other 

acceptable option(s) for a State 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 State, 

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-State 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 States to develop a multi-State

plan?

60.5760 What are the timing requirements for submitting my 
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plan? 

60.5765 What must I include in an initial submittal if 

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 State measures may I rely 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 

60.5795 What affected EGUs qualify for generation of ERCs? 

60.5800 What other resources qualify for issuance of ERCs?

60.5805 What is the process for the issuance of ERCs? 

60.5810 What applicable requirements are there for an ERC 

tracking system?

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?

60.5835 What are the requirements for M&V reports for eligible

resources?

Applicability of Plans to Affected EGUs

60.5840 Does this subpart directly affect EGU owners and 

operators in my State?

60.5845 What affected EGUs must I address in my State plan?

60.5850 What EGUs are excluded from being affected EGUs?

60.5855 What are the CO2 emission performance rates for 

affected EGUs?

60.5860 What applicable monitoring, recordkeeping, and 

reporting requirements do I need to include in my plan 

for affected EGUs?

Recordkeeping and Reporting Requirements 

60.5865 What are my recordkeeping requirements?

60.5870 What are my reporting and notification requirements?

60.5875 How do I submit information required by these emission 
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guidelines to the EPA?

Definitions

60.5880 What definitions apply to this subpart? 

Table 1 to Subpart UUUU of Part 60—CO2 Emission Performance Rates

(Pounds of CO2 per Net MWh)

Table 2 to Subpart UUUU of Part 60—Statewide Rate-based CO2

Emission Goals (Pounds of CO2 per Net MWh)

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 State or multi-State plans that establish emission 

standards limiting greenhouse gas (GHG) emissions from an 

affected steam generating unit, integrated gasification 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.
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§60.5705 Which 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) PSD 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.

(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 emissions from facilities regulated in the 
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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 State in the contiguous United 

States with one or more affected EGUs that commenced 

construction on or before January 8, 2014, you must submit a 

State or multi-State plan to the U.S. Environmental Protection 

Agency (EPA) that implements the emission guidelines contained 

in this subpart. If 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 

State, 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 12 months after 
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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 

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 State according to §60.27 except 

that under §60.27(d) the EPA will have one year to promulgate a 

Federal plan for your State from the date EPA finds you failed

to submit a plan or EPA disapproves your plan. 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 State. 

(b) After a Federal plan has been implemented in your 

State, it will be withdrawn when your State submits, and the EPA 

approves, a final plan. 

§60.5725 In lieu of a State plan submittal, are there other 

acceptable option(s) for a State to meet its CAA section 111(d) 

obligations?
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A State may meet its CAA section 111(d) obligations only by 

submitting a final State or multi-State 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 

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 State, 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 State plan.

§60.5735 What authorities will not be delegated to State, 

local, or tribal agencies?

The authorities that will not be delegated to State, local, 

or tribal agencies are specified in paragraphs (a) and (b) of 

this section.

(a) Approval of alternatives, not already approved by this 

subpart, to the CO2 emission performance rates in Table 1 to this 

subpart established under §60.5855.
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(b) Approval of alternatives, not already approved by this 

subpart, to the CO2 emissions goals in Tables 2, 3 and 4 to this 

subpart established under §60.5855.

§60.5736 Will the EPA impose any sanctions?

The EPA will not withhold any existing federal funds from a 

State on account of a State’s failure to submit, implement, or 

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 
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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.

(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. 
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(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 

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.
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State and Multi-State Plan Requirements

§60.5740 What must I include in my federally enforceable State 

or multi State plan?

(a) You must include the components described in paragraphs 

(a)(1) through (5) of this section in your plan submittal. The 

final plan must meet the requirements and include the 

information required under §60.5745.

(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 State that meet the 

applicability criteria in §60.5845. 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, when taken together, achieve the applicable CO2 

emission performance rates or CO2 emission goals described in

§60.5855. Allowance systems are an acceptable form of emission 

standards under this subpart.

(i) Your plan does not need to include corrective measures 

specified in paragraph (a)(2)(ii) of this section if your plan:
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(A) Imposes emission standards on all affected EGUs that, 

assuming full compliance by all affected EGUs, mathematically 

assure achievement of the CO2 emission performance rates in the 

plan for each plan period; 

(B) Imposes emission standards on all affected EGUS that, 

assuming full compliance by all affected EGUs, mathematically 

assure achievement of the CO2 emission goals; 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 the 

requirement for corrective measures to be 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 
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your affected EGUs, as 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.

(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 

performance rate or CO2 emission goal, either on average or 

cumulatively (if applicable).
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(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.

(iii) If your plan relies upon State measures, in addition 

to or in lieu of emission standards on your affected EGUs, then

the final State plan must include the information in paragraph 
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(a)(3) of this section and the submittal must include the 

information listed in §60.5745(a)(6).

(iv) If your plan requires 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 includes emission standards for 

affected EGUs that will be put into place, if there is 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 on the 

affected EGUs as part of the backstop must be able to meet 

either the CO2 emission performance rates or mass-based or ratebased CO2 emission goal for your State during the interim and 

final periods. You must either submit, along with the backstop 

emission standards, provisions to adjust the emission standards 

to make up for the prior emission performance shortfall, 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 
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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 include the requirements in paragraphs 

(a)(3)(i) through (iii).

(i) A trigger for the backstop to go into effect upon:

(A) A failure to meet a programmatic milestone; 

(B) An exceedance of 10 percent or greater of an interim 

step 1 goal or 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 

(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 reduce the stringency of the triggers 

required under paragraph (a)(3)(i) of this section. 

(iii) A schedule for implementation of the backstop once 

triggered, and you must identify all necessary State 
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administrative and technical procedures for implementing the 

backstop.

(4) Identification of applicable monitoring, reporting, and 

recordkeeping requirements for each affected EGU. You 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 §60.5860.

(5) State reporting. You must include in your plan a 

description of the process, contents, and schedule for State

reporting to the EPA about plan implementation and progress 

including information required under §60.5870.

(i) You must include in your plan a requirement for a 

report to be submitted by July 1, 2021, that demonstrates that 

the State has met, or is on track to meet, the programmatic 

milestone steps indicated in the timeline required in §60.5770.

(b) You must follow the requirements of subpart B of this 

part and demonstrate that they were met in your State 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 (13) of this section. 

This information must be submitted to the EPA as part of your 
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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., State or multiState, geographic boundaries related to the plan elements), 

including, if applicable, identification of multi-State plan 

participants.

(2) You must identify CO2 emission performance rates or

equivalent statewide CO2 emission goals that your affected EGUs 

will achieve. If the geographic scope of your plan is a single 

State, then you must identify CO2 emission performance rates or 

emission goals according to §60.5855. If your plan includes 

multiple States and you elect to set CO2 emission performance 

goals, you must identify 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 step, and the final period

(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 §60.5855.
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(4) You must include a demonstration that each affected 

EGU’s emission standard is quantifiable, non-duplicative, 

permanent, verifiable, and enforceable according to §60.5775.

(5) If your plan includes 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 

(v) of this section as applicable.

(i) If 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 1 

of this subpart, then no additional demonstration is required 

beyond inclusion of the emission standards in the plan.

(ii) If a plan applies rate-based emission standards to 

individual affected EGUs at a lbs CO2/MWh rate that differs from 

the CO2 emission performance rates in Table 1 of this subpart or 

the State’s rate-based CO2 emission goal in Table 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 State rate-based 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. 
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This projection must address the interim period and the final 

period. The projection in the plan submittal must include the 

information listed in (a)(5)(v) and in addition the following:

(A) An analysis of the change in generation of affected 

EGUs given the compliance costs and incentives under the 

application of different emission rate standards across affected 

EGUs in a State; 

(B) A projection showing how generation is expected to 

shift between affected EGUs and across affected EGUs and nonaffected 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;

(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;

(E) If a state plan provides for the ability of renewable 

energy resources located in states with mass-based plans to be 

issued ERCs, consideration in the projection that such resources 

must meet geographic eligibility requirements, based on power 

purchase agreements or related documentation; and

(F) Any other applicable assumptions used in the 

projection.
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(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 State mass-based 

CO2 emission goals. This demonstration includes the information 

listed in paragraph (a)(5)(v) and emission budgets for affected 

EGUs during the interim period and final periods that are equal 

to or lower than the applicable State mass-based CO2 goals 

specified in Table 3 of this subpart. 

(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;
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(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.

(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.
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(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.

(6) If your plan relies upon State measures, in addition to 

or in lieu of the emission standards required by paragraph 

§60.5740(a)(2), the final State plan submittal must include the 

information under paragraphs (a)(5)(iv) and (a)(6)(i) through 

(v) of this section.

(i) You must include a description of all the State

measures the State will rely upon to achieve the applicable CO2

emission goals required under §60.5855(e), the projected impacts 

of the State measures over time, the applicable State laws or 

regulations related to such measures, and identification of 

parties or entities implementing such State measures. 

(ii) You must include the schedule and milestones for the 

implementation of the State measures. If the State measures in 

your plan submittal rely upon measures 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 
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verification (EM&V) requirements listed under §60.5795 that 

apply to those programs and projects will be met.

(iii) You must demonstrate that federally enforceable 

emission standards for affected EGUs in conjunction with any

State measures relied upon for your plan, are sufficient to 

achieve the mass-based CO2 emission goal for the interim period,

each interim step in that interim period, the final period, and 

each final reporting period. In addition, you must demonstrate

that each emission 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 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 period and 

the final 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.
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(v) A State must demonstrate that the combined Stateenforceable measures, in conjunction with any federally 

enforceable CO2 emission standards for affected EGUs, if 

included, will result in the achievement by the affected EGUs of

the State’s mass-based CO2 emission goals for the interim period, 

interim step, and final reporting periods. In addition, you must 

demonstrate that each State measure included in your plan 

submittal meets the requirements of §60.5780.

(7) Your plan submittal must include a demonstration that 

the reliability of the electrical grid has been 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) Your 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 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 
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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 State 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).

(12) 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's legal authority to 

carry out each component of its plan, including emissions 

standards or State measures;

(ii) Materials supporting that the CO2 emission performance 

rates or CO2 emission goals will be achieved by affected EGUs

identified under the plan, according to paragraph (a)(3) of this 

section; 

(iii) Materials supporting any calculations for CO2 emission 

goals calculated according to §60.5855, if applicable; and

(iv) Any other materials necessary to support evaluation of 

the plan by the EPA.
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(b) You must submit your final plan to the EPA 

electronically according to §60.5875.

§60.5750 Can I work with other States to develop a multi-State

plan?

A multi-State plan must include all the required elements 

for a plan specified in §60.5740(a). A multi-State plan must

meet the requirements of paragraphs (a) and (b) of this section.

(a) The multi-State plan must demonstrate that all affected 

EGUs in all participating States will meet the CO2 emission 

performance rates listed in Table 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 States electing to demonstrate performance with a

CO2 emission rate-based goal, the CO2 emission goals identified 

in the plan according to §60.5855 will be an adjusted weighted 

(by net energy output) average lbs CO2/MWh emission rate to be 

achieved by all affected EGUs in the multi-State area during the 

plan periods; or

(2) For States electing to demonstrate performance with a

CO2 emission mass-based goal, the CO2 emission goals identified 

in the multi-State plan according to §60.5855 will be total CO2

emissions by all affected EGUs in the multi-State area during 
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the plan periods.

(b) Options for submitting a multi-State plan include the 

following:

(1) States participating in a multi-State plan may submit 

one multi-State plan submittal on behalf of all participating 

States. The joint submittal must be signed electronically, 

according to §60.5875, by authorized officials 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. The joint 

submittal must address plan components that apply jointly for 

all participating States and components that apply for each 

individual State in the multi-State plan, including necessary 

State legal authority to implement the plan, such as State

regulations and statutes.

(2) States participating in a multi-State plan may submit a 

single plan submittal, signed by authorized officials from each 

participating State, which addresses common plan elements. Each 

participating States must, in addition, provide individual plan 

submittals that address State-specific elements of the multiState plan. 

(3) States participating in a multi-State plan may 

separately make individual submittals that address all elements 

of the multi-State plan. The plan submittals must be materially 
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consistent for all common plan elements that apply to all 

participating States, and also must address individual Statespecific aspects of the multi-State plan. Each individual State

plan submittal must address all required plan components in 

§60.5740.

(c) A State may elect to participate in more than one 

multi-State plan. If a State elects to participate in more than 

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 
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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? 

(a) You must submit a final plan with the information 

required under §60.5745 by September 6, 2016, unless you are 

submitting an initial submittal, allowed under §60.5765, in lieu 

of a final State plan submittal, according to paragraphs (b) of 

this section.

(b) For States seeking a two year extension for a final 

plan submittal, you must include the information in §60.5765(a) 

in an initial submittal by September 6, 2016, to receive an 

extension to submit your final State plan submittal by September 

6, 2018.

(c) You must submit all information required under 

paragraphs (a) and (b) of this section according to the 

electronic reporting requirements in §60.5875.

§60.5765 What must I include in an initial submittal if 

requesting an extension for a final plan submittal?

(a) You must sufficiently demonstrate that your State is 

able to undertake steps and processes necessary to timely submit 
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a final plan by the extended date of September 6, 2018, by

addressing the following required components in an initial 

submittal by September 6, 2016, if requesting an extension for a 

final plan submittal:

(1) An identification of final plan approach or approaches 

under consideration and description of progress made to date on 

the final plan components;

(2) An appropriate explanation of why the State requires 

additional time to submit a final plan by September 6, 2018; and

(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 submittal allowed in 

paragraph (a) of this section, information required under 

paragraph (c) of this section (only if a State elects to submit 

an initial submittal to request an extension for a final plan

submittal), and a final State plan submittal according to 

§60.5870. If a State submits an initial submittal, an extension 

for a final State plan submittal is considered granted and a 

final State plan submittal is due according to §60.5760(b) 

unless a State is notified within 90 days of the EPA receiving 

the initial submittal that the EPA finds the initial submittal 
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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 September 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 submittal and a 

list of which final plan components are not complete.

(2) A commitment to a plan approach (e.g., single or multiState, 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 any updates 

to community engagement undertaken and planned.

§60.5770 What schedules, performance periods, and compliance 

periods must I include in my plan? 

(a) The affected EGUs covered by your plan must meet the CO2

emission requirements required under §60.5855 for the interim 

period, interim steps, and the final reporting periods according 

to paragraph (b) of this section. You must also include in your

plan compliance periods for each affected EGU regulated under 

the plan according to paragraphs (c) and (d) of this section.
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(b) Your plan must require your affected EGUs to achieve 

each CO2 emission performance rate or CO2 emission goal, as 

applicable, required under §60.5855 over the periods according 

to paragraphs (b)(1) through (3) of this section.

(1) The interim period.

(2) Each interim step.

(3) Each final reporting period. 

(c) The emission standards for affected EGUs regulated 

under the plan must include the following compliance periods:

(1) For the interim period, affected EGUs must have 

emission standards that have compliance periods that are no 

longer than each interim step and are imposed for the entirety 

of the interim step either alone or in combination.

(2) For the final period, EGUs must have emission standards 

that have compliance periods that are no longer than each 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 specified in this 

regulation, provided the schedules of compliance collectively 

end on the same schedule as each interim step and final 

reporting period.

(d) If your plan relies upon State measures in lieu of or 

in addition to emission standards for affected EGUs regulated 
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under the plan, then the period 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 plan 

must be quantifiable, verifiable, non-duplicative, permanent, 

and enforceable with respect to each affected EGU. The plan must

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. 

(c) An affected EGU’s 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 the 

emission standard.

(d) An affected EGU’s emission standard is non-duplicative 

with respect to a State plan if it is not already incorporated 

as an emission standard in another State plan unless 

incorporated in multi-State 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 
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approved plan revision, or the State demonstrates in an 

approvable plan revision that the emission reductions from the 

emission standard are no longer necessary for the State to meet 

its State 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 are 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 

practical matter; and 

(5) The Administrator, the State, and third parties

maintain the ability to enforce against violations (including if 

an affected EGU does not meet its emission standard based on its 

emissions, its allowances if it is subject to a mass-based 

emission standard, or its ERCs if it is subject to a 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.

§60.5780 What State measures may I rely upon in support of my 

plan?
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You may rely upon State measures in support of your plan 

that are not emission standard(s) on affected EGUs, provided 

those State measures meet the requirements in paragraph (a) of 

this section.

(a) Each State measure is quantifiable, verifiable, nonduplicative, permanent, and enforceable with respect to each 

affected entity (entities other than affected EGUs with no 

federally enforceable obligations under a State plan), and your 

plan supporting materials include the methods by which each 

State measure meets each of the following requirements in 

paragraphs (1) through (5) of this subpart. 

(1) A State measure is quantifiable with respect to an 

affected entity if it can be reliably measured in a manner that 

can be replicated. 

(2) A State measure is verifiable with respect to an 

affected entity if adequate monitoring, recordkeeping and 

reporting requirements are in place to enable the State to 

independently evaluate, measure, and verify compliance with the 

State measure.

(3) 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 unless incorporated in multi-State

plan.
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(4) A State measure is permanent with respect to an 

affected entity if the State measure must be met for at least 

each compliance period, or unless it is replaced by another 

State measure in an approved plan revision, or the State

demonstrates in an approved plan revision that the emission 

reductions from the State measure are no longer necessary for 

the State’s affected EGUs to meet its CO2 emission performance 

rates.

(5) A State measure is enforceable against an affected 

entity if:

(i) A technically accurate limitation or requirement and 

the time period for the limitation or requirement are specified;

(ii) Compliance requirements are clearly defined; 

(iii) The affected entities responsible for compliance and 

liable for violations can be identified; 

(iv) Each compliance activity or measure is enforceable as 

a practical matter; and 

(v) The State maintains the ability to enforce violations 

and secure appropriate corrective actions.

§60.5785 What is the procedure for revising my plan?

(a) Plans can 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 
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this part, including the requirement in §60.5745(a)(3) to 

demonstrate achievement of the CO2 emission performance rates in 

§60.5855. 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 §60.5855, 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:

(1) Addressing the addition of an affected EGU required to 

be included in a plan under §60.5740(a)(1).

(2) Addressing EGUs that become subject to subpart TTTT of 

this part and are no longer considered affected EGUs for 

incorporation in a plan.

(c) If your State is required to submit a notification 

according to section §60.5870(d) indicating a 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 State plan to 

include corrective measures to be implemented. The corrective 

measures must ensure achievement of the CO2 emission performance 

rates or State CO2 emission goal. Additionally, the corrective 
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measures must achieve additional emission reductions to offset 

any emission performance shortfall relative to the overall 

interim period or final period CO2 emission performance rate or 

State CO2 emission goal. The State 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 State must submit the revised plan and explanation

to the EPA within 24 months after submitting the State report

required in section §60.5870(a) indicating the exceedance in 

lieu of the requirements of §60.28(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) If 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 make 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 of emission standards under a 
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State plan for a specified affected EGU or EGUs. The EPA will 

consider the notification in §60.5870(g)(1) to be an approved 

short-term modification to the State plan without needing to go 

through the full State plan revision process if the State

provides a second notification to the EPA within seven days of 

the first notification. The short-term modification under a 

reliability safety valve allows modification to emission 

standards under the State plan for an affected EGU or EGUs for 

an initial period of up to 90 days. During that period of time, 

the EGU or EGUs will need to comply with the modified emission 

standards identified in the 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 exceed their obligations under the approved State plan 

will not be counted against the State’s CO2 emission performance 

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.

(2) Plan revisions submitted pursuant to §60.5870(g)(3) 

must meet the requirements for State plan revisions under 

§60.5785(a).

§60.5790 What must I do to meet my plan obligations?

(a) To meet your plan obligations, 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 statewide CO2 emission goals using 

the procedures in paragraphs (b) through (d) of this section. If 

your plan requires the use of allowances for your affected EGUs 

to comply with their emission standards, you must follow the 

requirements under paragraph (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.
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(b) If you submit a plan that sets a mass-based emission 

trading program for your affected EGUs, the State plan must

include emission standards and requirements that specify the 

allowance 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) Requirements for State allocation of allowances

consistent with §60.5815.

(3) Requirements for tracking of allowances, from issuance 

through submission for compliance, consistent with §60.5820.

(4) The process for affected EGUs to demonstrate compliance 

(allowance “true-up” with reported CO2 emissions) consistent 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 
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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 

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 must follow the requirements in paragraphs (c)(1) 

through (4).

(1) You must require the owner or operator of each affected 

EGU covered by your plan to calculate an adjusted CO2 emission 

rate to demonstrate compliance with its emission standard by 

factoring stack emissions and any ERCs into the following 
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equation: 

CO2emission rate =

∑ MCO2

∑ MWhop + ∑ MWh ERC

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 of pounds (lbs) summed 

over the compliance period for an affected EGU.

MWhop = Total net energy output over the compliance 

period for an affected EGU in units of MWh.

MWhERC = ERC replacement generation for an affected EGU in 

units of MWh (ERCs are denominated in whole 

integers as specified in paragraph (d) of this 

section).

(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.
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(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

(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 
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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 standards plan or 

as a part of the federally enforceable backstop in a State

measures plan) to be able to use ERCs issued pursuant to your 

State measures to demonstrate compliance with its emission 

standard, to meet the requirements of §60.5775, such ERCs must 

meet the requirements of paragraphs (c) of this section.

Emission Rate Credit Requirements 

§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 

the number of ERCs, denominated in MWh, that may be issued to an 
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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 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.

§60.5800 What other resources qualify for issuance of ERCs?

(a) ERCs may only be issued for generation or savings 

produced on or after January 1, 2022, to an eligible resource 
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that meets each of the requirements in paragraphs (a)(1) through 

(4) of this section.

(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.

(3) The resource is located in either:

(i) A State whose affected EGUs are subject to rate-based 

emission standards pursuant to this regulation; or 
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(ii) A State with mass-based emission standards, and the 

resource can demonstrate (e.g., through a power purchase 

agreement or contract for delivery) 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. 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.

(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 
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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 resource that does not meet the requirements of 

this subpart or an approved State plan cannot be issued ERCs for

use by an affected EGU with its compliance demonstration 

required under §60.5790(c).

(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.
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(d) You must include the appropriate requirements in 

paragraphs (d)(1) through (3) for an applicable eligible 

resource in your plan.

(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 

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 
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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 

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:
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(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 

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.
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(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 

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 
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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 

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 
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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.

(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. 
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§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 

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 
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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

§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 
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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 

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
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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 

following:

(1) For the first M&V report submitted, documentation that 

the energy-generating resources, energy-saving measures, or 

practices were installed or implemented consistent with the 

description in the approved eligibility application required in 

§60.5805(a).

(2) Each M&V report submitted must include the following:
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(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 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, and/or demonstration that the 

eligible resource continued to meet the requirements of 

§60.5800.

Applicability of Plans to Affected EGUs

§60.5840 Does this subpart directly affect EGU owners or

operators in my State? 

(a) This subpart does not directly affect EGU owners or

operators in your State. However, affected EGU owners or
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operators must comply with the plan that a State or States 

develop to implement the emission guidelines contained in this 

subpart. 

(b) If a State does not submit, or EPA disapproves, a final 

plan or initial submittal to implement and enforce the emission 

guidelines contained in this subpart by September 6, 2016, the 

EPA will implement and enforce a Federal plan, as provided in 

§60.5720, to ensure that each affected EGU within the State that 

commenced construction on or before January 8, 2014 complies

with all the provisions of this subpart.

§60.5845 What affected EGUs must I address in my State plan?

(a) The EGUs that must be addressed by your plan are any 

affected steam generating unit, IGCC, or stationary combustion 

turbine that commenced construction on or before January 8, 

2014. 

(b) An affected EGU is a steam generating unit, 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 25 MW of 

electricity); 
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(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.

§60.5850 What EGUs are excluded from being affected EGUs? 

(a) EGUs that are excluded from being 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 one-third or less of its 

potential electric output, or 219,000 MWh or less;

(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.
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(4) Stationary combustion turbines not capable of 

combusting natural gas (e.g., not connected to a natural gas 

pipeline) 

(5) EGUs that are combined heat and power units that have 

always historically limited, or are subject to a federally 

enforceable permit currently limiting and always historically 

limiting, 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.

§60.5855 What are the CO2 emission 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 Table 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 in your State will 

collectively meet their CO2 emission performance rate by 

achieving statewide emission goals that are equivalent and no 

less stringent than the CO2 emission performance rates listed in 

Table 1, and provided that your equivalent statewide CO2 emission 

goals take one of the following forms:

(1) Average statewide rate-based CO2 emission goals listed 

in Table 2 of this subpart, except as provided in paragraphs (c) 

and (d); or

(2) Cumulative statewide mass-based CO2 emission goals 

listed in Table 3 of this subpart, except as provided in 

paragraphs (c) and (d). 

(c) If your plan incorporates CO2 emission goals listed in 

paragraphs (b)(1) or (2) of this section you must develop your 

own interim step goals and final reporting period goal for your 

affected EGUs to meet either on average or cumulatively. 
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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’s interim period goal, as 

applicable to a rate-based or mass-based goal. 

(d) Your plan’s interim period and final period CO2 emission 

goals incorporated 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) through (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, you may 

submit a plan or plan revision, allowed in §60.5785, to make 

corrections to them, as a result of changes in the inventory of 

affected EGUs; and

(2) You may address EGUs that become subject to subpart 

TTTT of this part 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 
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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.

§60.5860 What applicable monitoring, recordkeeping, and 

reporting requirements do I need to include in my plan for 

affected EGUs?

(a) Your plan must include monitoring for affected EGUs 

that is no less stringent than what is described in (a)(1) 

through (8) of this section.

(1) The owner or operator of an affected EGU (or group of 

affected EGUs that share a monitored common stack) that is

required to meet rate-based or mass-based emission standards

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
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mass emissions to be monitored and reported according to part 75 

of this chapter.

(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).

(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)(3)(i) through (vi) of this section, 

except as otherwise provided in paragraph (a)(4) 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 
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emitted to the atmosphere and an exhaust gas flow rate 

monitoring system according to §75.10(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

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. 

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 site-specific default moisture 

value.

(ii) For each “valid operating hour” (as defined in 

paragraph (a)(2) of this section), calculate the hourly CO2 mass 
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emission rate (tons/hr), either from Equation F-11 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 

reported electronically under §75.64(a)(6), if required by a 

plan. The owner or operator must 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, the 

monitoring system must meet the applicable certification and 

quality assurance procedures in §75.20 of this chapter and 

Appendices A and B to part 75 of this chapter.

(4) The owner or operator of an affected EGU that 
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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 according 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 

periodic determinations of the gross calorific value (GCV) of 

each fuel combusted. The fuel flow meter(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.

(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 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) 
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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.

(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.

(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 
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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).

(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.
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(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 

corresponding EGU or stack operating time.

Pnet = 

(Pe)ST + (Pe)CT + (Pe)IE − (Pe)A

TDF + [ (Pt)PS + (Pt)HR + (Pt)IE ]

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.
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(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 

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 
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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 

following equation:

(Pt)PS =

Qm × H

CF

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 
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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.

(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 
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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 

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
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(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 

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.

(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 subpart, 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, 
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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).

(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 §60.5775.

(ii) Copies of all reports submitted to the State under 

paragraph (c) of this section.

(iii) Data that are required to be recorded by 40 CFR Part 

75 Subpart F.

(iv) Data with respect to any ERCs generated by the 

affected EGU or used by the affected EGU in its compliance 

demonstration including the information in paragraphs 

(c)(2)(iv)(A) and (B) of this section.

(A) All documents related to any ERCs used in a compliance 

demonstration, including each eligibility application, EM&V 

plan, M&V report, and independent verifier verification report 

associated with the issuance of each specific ERC.

(B) All records and reports relating to the surrender and 

retirement of ERCs for compliance with this regulation, 
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including the date each individual ERC with a unique serial 

identification number was surrendered and/or retired.

(d) Your plan must require the owner or operator of an 

affected EGU covered by your plan to include in a report 

submitted to you at the end 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, 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 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 values and the 

sum of the hourly CO2 mass emissions values, for all of the valid 

operating hours in the compliance period; 

(v) ERC replacement generation (if any), properly justified 

(see paragraph (c)(5) of this section); and
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(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 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:

(A) The cumulative annual CO2 mass emissions (tons) for each 

year of the compliance period, derived from the electronic 
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emissions report for the fourth calendar quarter of that year, 

submitted to EPA under §75.64(a) of this chapter; and

(B) The sum of the cumulative annual CO2 mass emissions 

values from paragraph (c)(3)(v)(A) of this section, if the 

compliance period includes multiple years.

(4) For each affected EGU’s compliance period, the report 

must also include the applicable emission standard 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.

(5) If the owner or operator of an affected EGU is 

complying with an emission standard by using ERCs, they must 

include in the report a list of all unique ERC serial numbers 

that were retired in the compliance period, and, for each ERC,

the date an ERC was surrendered and retired and eligible

resource identification information sufficient to 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 or State measures by using 
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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).

(e) 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.

(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. 
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(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 

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 
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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

§60.5865 What are my recordkeeping requirements?

(a) You 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 each 

interim step and the interim period. After 2029, States must 

keep records of all information relied upon in support of any 

continued demonstration that the final emissions goals are being 

achieved.

(b) You 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 or 

requirements in an approved State plan, consistent with the 

affected EGU requirements listed in §60.5860. 

(c) If your 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 
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requirement of this section and you are not required to keep 

records of information that would be in duplicate of paragraph 

(b) of this section.

(d) You 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, CO2 emission performance

rate or CO2 emissions goal. Each record must be in a form 

suitable and readily available for expeditious review.

§60.5870 What are my 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 (f) of this section.

(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 due no later than July 1, 

2025. The final period reports start with a biennual 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). 
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The report must include the 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) The report must include a comparison of the CO2 emission 

performance rate or CO2 emission goal identified in the State

plan for the applicable interim step period versus the actual

average, cumulative, or adjusted CO2 emission performance (as 

applicable) achieved by all affected EGUs.

(i) For interim step 3, 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 State plan according to §60.5740(a)(5).
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(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 

of the eligibility of verifiers by the State and the conduct of 

verifiers, including the quality of verifier reviews.

(c) If your plan relies upon State measures, in lieu of or 

in addition to emission standards, then 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 period, you must submit biennual 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, 
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2022). The annual and biennual 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 State measures.

(2) You must include information regarding 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 State measures 

included in the State plan submittal. 

(d) If your plan includes the requirement for emission 

standards on your affected EGUs, then you must submit a 

notification in the report required under paragraph (b) of this 

section to the EPA if your affected EGUs trigger corrective 

measures 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 relies 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) of 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 
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the calendar year your State 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 

State 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 you trigger 

the backstop as described in §60.5740(a)(3)(i). This 

notification must detail the steps that will be taken by you to 

implement the backstop so 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 State 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, cumulative 

sum of emissions, or adjusted emissions (as applicable) over the 

interim period and a comparison of those values to 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. 
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(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 

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 
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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 

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 
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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 

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 
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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.

(b) All negative declarations, State plan submittals, 

supporting materials that are part of a State plan submittal, 

any plan revisions, and all 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). SPeCS 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 (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 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 State plan, the EPA must be notified 

via letter from the Governor prior to the September 6, 2016,
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deadline for plan submittal so that they have the ability to 

submit the initial or final plan submittal in the 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. 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.

(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 must provide the EPA 

with an 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 at the State level, 

if any, to the existing approved federally enforceable plan 
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components, using a mechanism such as redline/strikethrough.

These changes are not part of the State plan until formal 

approval by EPA.

(e) You must provide the EPA with non-editable and editable 

copies 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 at the State 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 State plan until formal approval by EPA.

Definitions

§60.5880 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.

Base load rating means the maximum amount of heat input 

(fuel) that an EGU can combust on a steady-state 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 

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 
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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 §60.5855.

Combined cycle unit means an electric generating unit that 

uses a stationary combustion turbine from which the heat from 

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 uses 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 
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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 

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 unit’s 

capacity for planning purposes. 
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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.

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 an eligible 

resource for generating ERCs pursuant to this regulation, 

including the type of resource.

Existing State program, requirement, or measure means, in 

the context of a State plan, a regulation, requirement, program, 

or measure administered by a State, utility, or other entity 

that is currently established. 

Final period means the period that begins on 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 
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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.

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,
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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.

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 
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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 

January 1, 2028, to December 31, 2029.

ISO conditions means 288 Kelvin (15o C), 60 percent relative 

humidity and 101.3 kilopascals pressure.

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 must be converted into MWh by multiplying it by 

745.7 then dividing by 1,000,000.
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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 

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 

State 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 
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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 

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).
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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 

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).

Qualified biomass means a biomass feedstock that is 

demonstrated as a method to control increases of CO2 levels 

in the atmosphere.

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 State, 
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with the legal authority of the State.

State measures means 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.

Stationary combustion turbine means all equipment, 

including but not limited to the turbine engine, the fuel, air, 

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 
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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 

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.
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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 

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.
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Table 1 to Subpart UUUU of Part 60—CO2 Emission Performance Rates 

(Pounds of CO2 per Net MWh)

Affected EGU Interim Rate Final Rate

Steam generating 

unit or integrated 

gasification 

combined cycle 

(IGCC)

1,534 1,305

Stationary 

combustion turbine

832 771

Table 2 to Subpart UUUU of Part 60—Statewide Rate-based CO2

Emission Goals (Pounds of CO2 per Net MWh)

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
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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

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 
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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 

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
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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 

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
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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

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