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6560-50

EO 12866_CPP 2060 AR33 Final_20150529 

ENVIRONMENTAL PROTECTION AGENCY 

40 CFR Part 60 

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

RIN 2060-AR33 

Carbon Pollution Emission Guidelines for Existing Stationary 

Sources: Electric Utility Generating Units 

AGENCY: Environmental Protection Agency (EPA). 

ACTION: Final rule. 

SUMMARY: In this action, the Environmental Protection Agency 

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

territories, and tribes to follow in developing plans to reduce 

greenhouse gas emissions from existing fossil fuel-fired 

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

establishing: 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. This final rule 

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

emissions from the utility power sector. 
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DATES: The final rule is effective on [INSERT THE DATE OF 

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://www.epa.gov/epahome/dockets.htm.

World Wide Web. In addition to being available in the 

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

on the World Wide Web (WWW). Following signature, a copy of this 
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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, a legal memorandum, and the regulatory impact 

analysis, 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: 

ACEEE American Council for an Energy Efficient Economy 

AEO Annual Energy Outlook 

AFL-CIO American Federation of Labor and Congress of 

Industrial Organizations 
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ASTM American Society for Testing of Materials 

BSER Best System of Emission Reduction 

Btu/kWh British Thermal Units per Kilowatt-hour 

CAA Clean Air Act 

CBI Confidential Business Information 

CCS Carbon Capture and Storage (or Sequestration) 

CEMS Continuous Emissions Monitoring System 

CHP Combined Heat and Power 

CO2 Carbon Dioxide 

DOE U.S. Department of Energy 

ECMPS Emissions Collection and Monitoring Plan System 

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 

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 

Commissioners 

NAS National Academy of Sciences 

NGCC Natural Gas Combined Cycle 

NOx Nitrogen Oxides 

NRC National Research Council 

NSPS New Source Performance Standard 

NSR New Source Review 

NTTAA National Technology Transfer and Advancement Act 

OMB Office of Management and Budget 
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PM Particulate Matter 

PM2.5 Fine Particulate Matter 

PRA Paperwork Reduction Act 

PSB Public Service Board 

PUC Public Utilities Commission 

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 Operator 

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. Congress’ Awareness of Climatic Change 

E. International Agreements and Actions 

F. Statutory and Regulatory Requirements 

G. Legislative and Regulatory Background for CAA Section 111 

H. Clean Power Plan Proposal and Supplemental Proposal 

I. Stakeholder Outreach and Consultations 

J. Comments on the Proposal 

III. Rule Requirements and Legal Basis

A. Summary of Rule Requirements 
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B. Summary of Legal Basis 

IV. Authority for this Rulemaking, Definition of Affected 

Sources, and Treatment of Categories

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

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

C. Authority to Regulate EGUs 

D. Definition of Affected Sources 

E. Combined Categories and Codification in the Code of Federal 

Regulations 

V. The Best System of Emission Reduction and Associated Building 

Blocks 

A. The Best System of Emission Reduction (BSER) 

B. Legal Discussion of Certain Aspects of the BSER 

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

 Fired Steam EGUs 

D. Building Block 2—Generation Shifts Among Affected EGUs 

E. Building Block 3—Renewable Generating Capacity 

VI. Source Category-Specific CO2 Emission Performance Rates 

A. Overview 

B. Performance Rate Requirements 

C. Form of the Performance Rates 

VII. Statewide CO2 Goals 

A. Overview 

B. Translating Source Category-Specific Emission Performance 

Rates to Statewide CO2 Emission Performance Goals 

VIII. State Plans 

A. Overview 

B. State Plan Performance Periods 

C. State Plan Approaches 

D. State Plan Components and Approvability Criteria 

E. State Plan Submittal and Approval Process and Timing 

F. State Plan Performance Demonstrations 

G. Considerations for Incorporating CO2 Emission Reduction 

 Measures in State Plans 

H. Additional Considerations for State Plans 

I. Resources for States to Consider in Developing Plans 

IX. Community Considerations 

A. Proximity Analysis 

B. Title VI 

C. Community Engagement in State Plan Development 

D. Co-pollutants 

E. EPA Continued Engagement 

F. Key Changes from Proposal 

X. Interactions with Other EPA Programs and Rules 

A. Implications for the NSR Program 

B. Implications for the Title V Program 
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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 

C. Regulatory Flexibility Act 

D. Unfunded Mandates Reform Act of 1995 

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 

J. Executive Order 12898, Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations 

XIII. Statutory Authority 

I. General Information 

A. Executive Summary 

1. Introduction and Purpose of the Regulatory Action 

Under the authority of Clean Air Act (CAA) section 

111(d), the EPA is establishing CO2 emission guidelines for 

existing fossil fuel-fired electric generating units (EGUs) 

– the Clean Power Plan. As in the proposal, these final 

guidelines, when fully implemented, will achieve 

significant reductions in CO2 emissions by 2030. At the same 
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time, the guidelines offer states and utilities substantial 

flexibility and latitude in achieving these reductions. In 

this final rule, the EPA has established a CO2 emission 

performance rate for each of two subcategories of fossil 

fuel-fired EGUs -- fossil fuel-fired electric steam 

generating units and stationary combustion turbines. The 

performance rates reflect the “best system of emission 

reductions ... adequately demonstrated” (BSER) for CO2

emissions from the EGU source category. The guidelines also 

provide for the development, submittal and implementation 

of state plans that implement the CO2 emission performance 

rates, either directly by means of source-specific 

requirements or through measures that achieve equivalent CO2

reductions from the same group of EGUs.1 States, U.S. 

territories, and tribes2 with one or more affected EGUs will 

 

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

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

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

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

more affected EGUs in its jurisdiction. 

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 performance 

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

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

appropriate, it has the responsibility to establish CAA section 

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

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

sources) is located seeks and obtains authority from the EPA to 
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be required to develop and implement plans to ensure that 

their affected EGUs, individually, in aggregate, or in 

combination with other measures undertaken by the state,3

achieve the equivalent of the final CO2 emission performance 

rates by 2030. State plans must also ensure that emission 

reductions from the affected EGUs begin no later than 2022 

and that, during the period from 2022 to 2029, affected 

EGUs in the state collectively meet the equivalent of the 

interim CO2 emission performance rates. 

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, including application of statewide policy 

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

requirements, that states will have in developing their 

plans. 

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

changes from the proposal, the context for the rulemaking, the 

 

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

40 CFR 49.9

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

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

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

CFR 49.9 as eligible to develop and implement a CAA section 

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

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

used to represent them. 
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major provisions of the final rule, the estimated CO2 emission 

reductions, and the costs and benefits expected to result from 

full implementation of this final action. Greater detail is 

provided in the body of this preamble, the regulatory impacts 

analysis (RIA), the response to comments documents, and various 

technical support documents and memoranda addressing specific 

topics. 

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

CO2 emissions from fossil fuel-fired power plants in the U.S. 

because they are the largest domestic stationary source of 

emissions of carbon dioxide (CO2), the most prevalent of the 

group of air pollutant greenhouse gases (GHG) that the EPA has 

determined endangers public health and welfare through its 

contribution to climate change. This rule establishes for the 

first time emission guidelines for existing power plants that 

will lead to significant reductions in CO2 emissions. At the same 

time, these emission guidelines will result in cleaner 

generation from the existing power plant fleet and will support 

continued investments by the industry in cleaner power 

generation to ensure reliable, affordable electricity now and 

into the future. 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 
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sector. Like past rules under CAA section 111, this rule relies 

on proven technologies and approaches to set achievable 

standards that will lead to cost-effective CO2 reductions at 

power plants across the country. In fact, the emission 

guidelines reflect strategies, technologies and approaches 

already in widespread use by utilities and states. CAA section 

111(d) itself relies on a state-EPA partnership to accomplish 

the required emission reductions. This rulemaking, which will be 

implemented through that partnership, is a significant step that 

will reduce air pollution, in this case GHG emissions, in the 

U.S. 

This final rule is also a significant step forward in 

implementing the President’s Climate Action Plan.4 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) 

 

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

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

climateactionplan.pdf 
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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 rule will achieve CO2

emission reductions from the utility power sector of 

approximately [X] percent from CO2 emission levels in 2005. 

The EPA projects that these reductions along with reductions in 

other air pollutants, to which this rule will lead, will result 

in net climate and health benefits of $[X] billion to $[X] 

billion. At the same time, coal and natural gas will remain the 

two leading sources of electricity generation in the U.S., with 

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

natural gas providing about [X] percent of the projected 

generation. 

2. Key changes from proposal 

The June 2014 proposal featured several important elements: 

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 to maximize the range of 

choices that states and utilities could select in order to 

achieve their emission limitations at low cost while ensuring 
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electric system reliability. The state goals reflected an 

approach to the BSER that was intended to capture both the 

unique interconnected nature of the utility power sector and the 

set of actions, strategies and programs that are already under 

way at the state and utility level that have been resulting in 

CO2 emission reductions. They also reflected the fact that each 

state has its own energy profile and state-specific policies and 

needs relative to the production and use of electricity. The 

final guidelines continue to embrace this basic approach, but 

they also incorporate significant changes that respond directly 

to the comments, requests and concerns of states and other 

stakeholders, while better serving the critical objectives of 

the basic approach of the proposal. 

Together with the proposal, 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 and continuing through December 2014, and resulting in 

millions of comments from stakeholders, which we have carefully 

considered over the past several months. The EPA gained crucial 

insights from the more than 4 million comments that the agency 

received on the proposal and on notices leading to this final 

rulemaking, from stakeholders that include state environmental 

and energy officials, tribal officials, public utility 
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commissioners, system operators, utility and other industry 

representatives, labor leaders, public interest advocates, 

community leaders, and members of the public. As a result, these 

final emission guidelines reflect changes from the proposal that 

are directly responsive to the comments we received from the 

many and diverse stakeholders. These final guidelines bear the 

stamp of the information and input the EPA gleaned from its 

extensive outreach process and from the comment record. The 

guidelines reflect thinking and information 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 and ongoing consultation 

with federal, state and regional energy agencies and 

authorities, to ensure that the actions sources will take to 

reduce GHG emissions will not compromise electric system 

reliability or affordability of the U.S. electricity supply. 

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

that relied both on the distinctive nature of the electricity 

system in which affected EGUs operate and on the actions, 

strategies and policies states and utilities have already been 
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undertaking, and, second, to provide states and utilities with 

broad flexibility and choice in meeting those requirements in 

order to minimize costs to ratepayers and to ensure the 

reliability of electricity supply. Thus, in our thorough 

examination of the comment record and of information received 

during the engagement process, we paid particular attention to 

information and suggestions that addressed ways to ensure that 

this final rule succeeds in fulfilling the dual objectives of 

the proposal. 

The resulting changes in these final guidelines are 

highlighted by: 1) a new start date of 2022 for the interim 

period, 2) 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 “glide path” over that 

period, 3) the BSER being derived from generation options only 

and not from demand-side energy efficiencies, 4) the BSER 

reflecting the realities of electricity operations over the 

three regional Interconnections, as well as up-to-date 

information about the cost and availability of clean generation 

options, including reflecting the fact that new NGCC is also a 

clean generation option, 5) a combination of provisions 

expressly designed to address electric system reliability, 6) 

source-specific CO2 emission performance rates that are uniform 
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across the two fossil fuel-fired source categories covered in 

these guidelines, 7) additional, more flexible options for 

states and utilities to adopt multi-state compliance strategies, 

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

their final compliance plans following submittal of an initial 

plan in 2016 and 9) a variation on the proposal’s “portfolio” 

option for state plans – called the “state measures” approach - 

that offers the same options for states but with a firmer legal 

foundation. 

This suite of changes is the product of compelling 

information and analysis provided to the EPA via the comment 

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

federal agencies, notably the Federal Energy Regulatory 

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

Earlier this year, FERC conducted a series of technical 

conferences comprising one national session and 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 
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time for states, utilities, and grid operators to implement 

strategies to achieve CO2 reductions. They expressed concern 

that, in the proposal, at least some states were 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, ratepayer bills, and stranded 

assets. To many commenters, the proposal’s 2020 start date for 

achieving CO2 reductions, together with the stringency of the 

interim CO2 goal, bore 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 (a glide path 

separated into three steps, 2022-2024, 2025-2027, and 2028-2029, 

and also achievable “on average” over the 8-year interim 

period). In response to the concerns of commenters that the 

proposal’s 10-year interim target failed to afford sufficient 

flexibility, the final guidelines’ approach will provide states 

with realistic options for customizing their emission reduction 

trajectories. Of equal importance, the approach provides more 

time for planning, consultation and decision making in the 

formulation of state plans and in EGUs’ choices of compliance 
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strategies. Both FERC’s May 15, 2015 letter and the comment 

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

providing sufficient time for planning and implementation was 

essential to ensuring electric system reliability. 

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

emission performance rates is the result of the application of 

the measures constituting the BSER in a more gradual way, 

reflecting stakeholder comments and information about the 

appropriate period of time over which those measures can be 

deployed consistent with the BSER factors of cost and 

feasibility. In addition to facilitating reliability assurance, 

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. 

Commenters urged the EPA to confine its BSER determination 

to actions that involve generation. In response, the final 

guidelines’ BSER determination does not take into account 

demand-side energy efficiency (EE), and the emission performance 

rates for each of the two source categories do not reflect 

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 energy efficiency measures 
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are in widespread use across the country and provide energy 

savings that reduce emissions, lower electric bills, and lead to 

positive investments and job creation. We agree, and the final 

guidelines provide ample latitude for states and utilities to 

rely on demand-side EE in meeting emission reduction 

requirements. Since commenters pointed out that the utility 

power sector operates over regional interconnections that are 

not constrained by state borders, the BSER determination and the 

resulting source category-specific emission performance rates 

take into account that reality. The final guidelines’ BSER 

determination takes into account recent reductions in the cost 

of clean energy technology, as well as projections of continuing 

cost reductions. With a revised start date for emission 

reductions of 2022, instead of 2020, as proposed, the guidelines 

reflect that the additional time aligns with the adoption of 

lower-cost clean technology and thus its incorporation in the 

BSER at higher levels. At the same time, the 2022-2029 interim 

period will more easily allow for companies to take advantage of 

improved clean energy technologies as potential least cost 

options. 

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

determination responds to numerous stakeholders’ request that 

the agency not base the final emission guidelines on requiring 
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that utilities produce less generation. After consideration of 

these comments and extensive comments on a range of topics 

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

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

action, the agency has determined that the BSER comprises the 

first three of the four proposed building blocks identified at 

proposal, with certain refinements to the three building blocks. 

Commenters pointed out that the proposal’s approach of 

expressing the BSER in terms of state-specific goals deviated 

from the requirements of CAA section 111 and from all previous 

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

observed, was that the proposal’s de facto emission standards 

for the same sources were not uniform, but varied 

inappropriately from state to state, depending on what each 

state’s goal was. Many commenters also pointed out that the EPA 

must establish the BSER specifically for affected sources, 

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

response to these and similar comments, the final guidelines 

express the BSER by establishing performance-based CO2 emission 

rates that are uniform across each of two source categories – 

fossil fuel-fired electric steam generating units and stationary 

combustion turbines – for the affected EGUs covered by the 

guidelines. We cannot emphasize enough that, while the final 
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guidelines now take a source-specific approach in setting CO2

emission performance rates, this does not change the fact that 

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

in no way alters or curtails the flexibility inherent in the 

proposal’s state-specific goals approach, which the final 

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

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

proposal’s flexibility for states, the guidelines continue to 

define state planning and implementation obligations through 

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

source category-specific CO2 emission performance rates into 

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

For the state plan approaches included at proposal, 

commenters expressed support for the objectives served by the 

“portfolio” option but also raised concerns about its legality, 

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

enforceability requirements. Some of these commenters identified 

a “state commitment approach” with backstop measures as an 

option for state plans that would retain the benefits of the 

“portfolio” approach while resolving legal and enforceability 

concerns. In this final rule, in response to stakeholder 

comments on the portfolio approach and alternative approaches, 

the EPA is finalizing two approaches, a source-based “emission 
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standards” approach, and a “state measures” approach that 

requires the inclusion of backstop measures. As in the proposal, 

in order to comply with these guidelines, states will have to 

ensure that implementation of the emission standards established 

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

in combination with other measures undertaken by the state, 

achieves the equivalent of the source category-specific CO2

emission performance rates. This revision provides consistency 

in the treatment of sources while still tailoring required CO2

reductions to individual states.

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, as we 

proposed, states may use trading or other multi-unit compliance 

approaches and technologies or strategies that are not 

explicitly mentioned in any of the three building blocks as part 

of their overall plans, as long as they achieve the required 

emission reductions from affected fossil fuel-fired EUGs. In 

addition, in response to concerns from states and power 
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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 other multi-unit compliance 

approaches. 

Stakeholders, particularly states, provided compelling 

information that it will take longer than the agency initially 

anticipated for the states to develop and submit their required 

plans. While the approach at proposal reflected the EPA’s 

conclusion that it was essential to the environmental and 

economic purposes of this rulemaking that utilities and states 

establish the path towards emissions reductions as early as 

possible, we fully recognize commenters’ concerns. To strike the 

proper balance, the EPA has developed a revised state plan 

submittal schedule. The EPA is requiring states to submit an 

initial plan 13 months after signature (by August 31, 2016), to 

assure that states begin to address the urgent needs for 

reductions quickly, and is providing until August 31, 2018, for 
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states to submit a final plan, if 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. 

A number of commenters stressed the importance of final 

guidelines that addressed the need to ensure that the program 

would not undermine electric system reliability. As noted above, 

the EPA has consulted extensively with federal, regional and 

state energy agencies, utilities and many others about 

reliability concerns and ways to address them. Many aspects of 

the final rule’s design are intended to support electric system 

reliability. In addition to not requiring reductions before 2022 

and to allowing significant flexibility in how the CO2 emission 

performance rates or the statewide CO2 goals are met, we are 

requiring that states demonstrate that they have considered 

reliability in developing their state plans and have consulted 

with state utility agencies and/or regional planning 

authorities. These final guidelines further provide states with 

the option of proposing amendments to approved plans in the 

event that reliability challenges arise that need to be remedied 

by amending the state plan. The final rule also includes a 

reliability safety valve to address situations where, because of 

an unanticipated catastrophic event, there is a conflict between 
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the requirements imposed on an affected unit and the maintenance 

of reliability. The final rule also retains flexibilities 

presented in the proposal and offers additional opportunities, 

including opportunities for trading within and between states, 

and other multi-state compliance approaches that will further 

support electric system reliability. 

Stakeholders requested that the program not impose undue 

burdens on low-income ratepayers. We share this concern, and the 

final rule ensures that bill-lowering measures such as demandside EE continue to be a major compliance option. In addition, 

to ensure opportunities for communities, particularly citizens 

who could be impacted by decisions, to continue to participate 

in decision making, we are taking steps to ensure that states 

are actively engaging with communities as part of their public 

participation process in the formulation of state plans. We note 

that, given the substantial reductions in a range of air 

pollutants, in addition to GHGs, that will occur along with the 

GHG reductions, this rule will result in significant near-term 

public health benefits in communities in addition to the longer 

term benefits resulting from the reductions in GHGs. 

In their comments, many states identified the need for the 

EPA to maintain regular contact/forums with states throughout 

the implementation process and to provide guidance, including 
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guidance on RE and EE emission measurement and verification 

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

stakeholders, including communities, with an understanding of 

the rule requirements, and to provide efficiencies where 

possible and reduce the cost and administrative burden, the EPA 

will continue outreach throughout the plan development and 

submittal process. Outreach will include opportunities for 

states to participate in briefings, teleconferences, and 

meetings about the final rule. The EPA’s 10 regional offices 

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

territories to raise technical and policy questions. The agency 

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

components of the final rule currently planned for the first two 

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

information from this outreach process to inform the training 

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

and territories that are implementing the final rule, and also 

to inform the training for citizens, including members of 

communities that could be impacted, to support their 

participation in the state plan development process. The EPA 

also expects to issue guidance on specific topics. As guidance 

documents, tools, templates and other resources become 

available, the EPA, in consultation with the U.S. Department of 
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Energy and other federal agencies, will continue to make these 

resources available via a dedicated website. 

3. Context for this rulemaking

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

toward achieving the GHG emission reductions needed to address 

the serious threat of climate change. 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 emissions5 and 31 percent of U.S. GHG emissions.6 The May 

2014 report of the National Climate Assessment7 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 

 

5 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 

6 From Tables ES-4 and 3-5 of “Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, 

United States Environmental Protection Agency, April 15, 2015. 

7 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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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 

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, 

are disproportionately affected by certain climate change 

related impacts — including heat waves, degraded air quality, 

and extreme weather events – which are associated with increased 

deaths, illnesses, and economic challenges. Studies also find 

that climate change poses particular threats to the health, 

wellbeing, and ways of life of indigenous peoples in the United 

States. 

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

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

power plants. 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. To 

accomplish this goal, President Obama issued a Presidential 
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Memorandum8 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. 

Unlike all other industrial sectors, where sources 

effectively operate independently and on a local-site scale, the 

utility power sector comprises a unique system of electricity 

resources that operate in a complex and interconnected grid 

where electricity generally flows freely (e.g., portions of the 

system cannot be easily isolated through the use of switches or 

valves as can be done in a other networked systems like trains 

and pipeline systems). That grid is physically interconnected 

and operated on an integrated basis across large regions. In 

 

8 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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this interconnected system, electricity supply and demand are 

reliably balanced using available generation and demand-side 

resources, including energy efficiency, demand response and a 

wide range of low- and zero-emitting sources which are all 

managed to meet the system needs in a reliable and efficient 

manner. 

The electricity system is largely integrated, with numerous 

entities that have both the capability and the responsibility to 

maintain a reliable electric system. The Federal Energy 

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

(DOE), state public utility commissions, independent system 

operators (ISOs), regional transmission organizations (RTOs), 

other planning authorities, and the North American Electric 

Reliability Corporation (NERC), all contribute to ensuring the 

reliability of the electric system in the U.S. Critical to this 

function are dispatch tools, applied primarily by RTOs, ISOs, 

and balancing authorities, that operate such that actions taken 

or costs incurred at one source directly affect or cause actions 

to occur at other sources. Generation, outages, and transmission 

changes in one part of the synchronous grid can affect the 

entire interconnected grid.9 The interconnection is such that 

 

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

Systems, IEEE Press, at 159 (2d ed. 2010).
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“[i]f a generator is lost in New York City, its effect is felt 

in Georgia, Florida, Minneapolis, St. Louis, and New Orleans.”10

The U.S. Supreme Court has similarly recognized the 

interconnected nature of the electricity grid.11 

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 

 

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

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

11 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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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 that electricity 

production takes place, at least to some extent, interchangeably 

between and among multiple generation facilities and different 

types of generation, as evidenced in the enactment or 

promulgation of pollution reduction programs, such as Title IV 

of the CAA, the NOx SIP Call, the Cross-State Air Pollution Rule 

(CSAPR), and the Regional Greenhouse Gas Initiative (RGGI). As 

these actions show, both Congress and the EPA have consistently 

tailored legislation and regulations affecting the utility power 

sector to its unique characteristics. For example, in Title IV 

of the Clean Air Act Amendments of 1990, Congress established a 

pollution reduction program specifically for fossil fuel-fired 

EGUs and designed the SO2 portion of that program with express 

recognition of the sector’s ability to shift generation among 

various EGUs and to reduce pollution by increasing reliance on 

renewable energy and demand-side energy efficiency. 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 
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express recognition of the sector’s ability to shift generation 

among various EGUs. In this action, we continue that approach. 

Both the source category-specific performance rates, and the 

pathways offered to achieve them, reflect, and are tailored to, 

the unique characteristics of the utility power sector. 

When the EPA evaluated this sector for development of this 

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

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

leadership in creating and implementing policies and programs 

that reduce CO2 emissions from the utility power sector while 

achieving other economic, environmental and energy benefits. 

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

performance standards, directly require CO2 emission reductions 

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

lower and zero CO2 emission alternatives, including both 

renewable generation and demand-side energy efficiency. For 

example, many states have adopted renewable portfolio standards 

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

cases, utilities have chosen to construct renewable generation 

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

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

advantage of cost-effective opportunities for improving the 

efficiency of fossil fuel-fired EGUs and using lower-emitting 
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generation across the electricity system’s interconnecting grid 

to reduce emissions from fossil fuel-fired EGUs. 

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

United States is already changing as a result of advancements in 

innovative power sector technologies and in the availability and 

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

demand-side 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 

addressing aging assets. In 2025, the average age of the coalfired generating fleet is projected to be 49 years old, and 20 

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

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

of additional environmental regulation, states and utilities can 

be expected to be, and already are, making plans for, and 

investing in, the next generation of power production, simply 

because they need to take account of the age of current assets 

and infrastructure. Owners/operators of affected EGUs are 

already pursuing the types of measures contemplated in this 

rule. Out of 417 entities identified as owners or operators of 

affected EGUs, representing ownership of 84 percent of the total 

capacity of the affected EGUs, 191 already own RE generating 
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capacity in addition to fossil fuel fired generating 

capacity. In fact, these entities already own aggregate amounts 

of RE generating capacity equal to 21 percent of the aggregate 

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

utility energy efficiency programs has been growing rapidly, 

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

The 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 
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meaningful CO2 emission reductions while maintaining the 

reliability and affordability of electricity in the U.S. 

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

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

performance” for CO2 emissions from new, modified, and 

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

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

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

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

submit plans regulating existing sources in that source category 

for any air pollutant that is not regulated under the CAA 

section 109 requirements for the NAAQS or regulated under the 

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

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

111(b) requirements that the EPA establishes and which apply 

directly to new, modified, or reconstructed sources, under CAA 

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

in which the state establishes emission standards for the 

affected sources. 

Under CAA section 111(d),12 states must establish, in their 

state plans, emission standards that reflect the degree of 

emission limitation achievable through the application of the 

 

12 See also 40 CFR 60.22(b)(5). 
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“best system of emission reduction” that, taking into account 

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

health and environmental impacts and energy requirements, the 

Administrator determines has been adequately demonstrated 

(BSER).13 Consistent with CAA section 111(d), the EPA is 

establishing CO2 emission performance rates for two categories of 

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

limitation that each of the two categories can achieve through 

the application of the BSER. This calculation reflects the 

degree of emission limitation that the state plan must achieve 

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

determined has been adequately demonstrated and that, in turn, 

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

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

units and stationary combustion turbines. 

 

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

determine the BSER and to calculate the amount of emission 

reduction achievable through applying the BSER. The state is 

authorized to identify the standard or standards of performance 

that reflects that amount of emission reduction. In addition, 

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

of performance and measures to implement and enforce those 

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

EPA must approve the plan if the standards of performance and 

implementing and enforcing measures are satisfactory. This is 

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

this preamble, as well as in the Legal Memorandum. 
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To determine the BSER for reducing CO2 emissions at 

affected EGUs, the EPA considered numerous measures that 

are already being implemented and can be implemented more 

broadly to improve emission rates and to reduce overall CO2

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

based on a range of measures that fall into three main 

categories, which comprise improving operations at EGUs, 

shifting generation to lower-emitting affected EGUs, and 

shifting generation to renewable energy generation. These 

measures have been amply demonstrated via their current 

widespread use by utilities and states. Consistent with CAA 

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

emission guidelines for states to follow in formulating 

their plans to establish and implement standards of 

performance to achieve CO2 emission reductions from fossil 

fuel-fired EGUs that are consistent with the BSER. 

The final guidelines are structured so that states are 

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

the EPA determines constitute the BSER or to apply any one 

of those measures to the same extent that the EPA 

determines is achievable at reasonable cost on a national 

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

have the flexibility to select the measure or combination 
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of measures it prefers in order to achieve the CO2 emission 

performance rates for its affected EGUs or meet the 

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

state could choose to achieve more reductions from one 

measure encompassed by the BSER and less from another, or 

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

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

as detailed in Section VIII of this preamble. Expressing 

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

can be met in aggregate, including through the adoption of 

CO2 emission reduction measures that are not identical to 

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

rather than exclusively through source-specific emission 

performance rates, is entirely permissible precisely 

because the approach mirrors the foundation of the BSER 

approach itself, namely the interconnected nature of the 

electricity system in which affected EGUs operate. 

We expect that affected EGUs in each state will be 

able to meet the CO2 emission performance rates because the 

emission performance rates represent the application of the 

BSER specific to the two categories of affected EGUs. 

4. Summary of the major provisions 

a. Overview. Though there are notable revisions – many of which 
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have been identified above – from the emission guidelines we 

proposed in June 2014, the proposed guidelines serve as the 

foundation of this final rule. First, these final guidelines 

build on the progress already underway to reduce the carbon 

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

Second, these guidelines reflect the unique interconnected 

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

in these guidelines, incorporates a range of CO2-reducing 

actions. Equally important, these guidelines offer states and 

owners and operators of EGUs broad flexibility and latitude in 

complying with their obligations. Because affordability and 

electricity system reliability are of paramount importance, the 

rule continues to provide states and utilities with time for 

planning and investment, which is instrumental to ensuring both 

manageable costs and system reliability and to facilitating 

clean energy innovation. The final rule continues to express the 

CO2 emission reduction requirements in terms of a state-level 

goal that reflects the particular mix of power generation in 

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

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

to achieve the CO2 reductions, which numerous commenters, 

including most sources, states and energy agencies, indicated 

was a reasonable timeframe. 
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b. Opportunities for states. Because, as stated above, the final 

guidelines are designed to build on and reinforce progress by 

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

sustainable strategies to reduce power sector CO2 emissions, 

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

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

address the power sector. Those states committed to Integrated 

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

reduction plans within that framework, while states with a more 

deregulated power sector system will be able to develop CO2

reduction plans within that specific framework. Each state will 

have the opportunity to take advantage of a wide variety of 

strategies for reducing CO2 emissions from affected EGUs. The EPA 

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

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

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

committed to sharing expertise with interested states as they 

develop and implement their plans. 

States will be able to address the economic interests of 

their utilities and ratepayers by using the flexibilities in 

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

stranded assets, and spur private investments in renewable 

energy and energy efficiency technologies and businesses; and 2) 
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if they choose, work with other states on multi-state approaches 

that reflect the regional structure of electricity operating 

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

to ensuring a reliable supply of affordable energy. The final 

rule gives states the flexibility to implement a broad range of 

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

diverse range of companies of various sizes that own and operate 

fossil fuel-fired EGUs, including vertically integrated 

companies in regulated markets, independent power producers, 

rural cooperatives and municipally-owned utilities, some of 

which are likely to have more direct access than others to 

certain types of GHG emission reduction opportunities, but all 

of which have a wide range of opportunities to achieve 

reductions or acquire clean generation. 

c. Main elements. This final rule has two main elements: 1) 

tailored state-level CO2 goals that are translated from the 

numerical source category-specific CO2 emission performance rates 

resulting from application of the BSER to the source categories 

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

submittal and implementation of state plans that implement those 

standards either directly or through measures that achieve the 
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equivalent in aggregate of those rates.14 

In this final action, the EPA is setting performance 

rates for two categories of affected fossil fuel-fired EGUs 

– fossil fuel-fired electric utility steam-generating units 

and stationary combustion turbines. These rates, applied to 

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

the state’s carbon intensity goal for 2030(and interim 

rates for the period 2022-2029). Each state will determine 

whether to apply these to each affected EGUs or to take an 

alternative approach and meet either an equivalent 

statewide rate-based goal or statewide mass-based goal. The 

EPA does not prescribe how a state must meet the emission 

guidelines, but these final guidelines do identify the 

methods which a state can or must use to demonstrate that 

the combination of measures and standards that the state 

does adopt meet its state-level CO2 goals. CAA section 

111(d) creates a partnership between the EPA and the states 

under which the EPA establishes emission guidelines and the 

states take the lead on meeting them by creating plans that 

are consistent with the EPA emission guidelines. The EPA 

 

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

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

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

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

more affected EGUs in its jurisdiction. 
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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. 

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 
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guidelines, and the options they have in the timing of 

submittal of their plans. This final rule also gives states 

considerable flexibility with respect to the timeframes for 

plan development and implementation, as well as the choice 

of emission reduction measures. The final rule provides up 

to fifteen years for full implementation of all emission 

reduction measures, with incremental steps for planning and 

then for demonstration of CO2 reductions that will ensure 

that progress is being made in achieving CO2 emission 

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

of emission reduction measures, including measures that are 

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

VIII.G of this preamble. 

d. Determination of the BSER. In issuing this final 

rulemaking, the EPA is implementing statutory provisions 

that have been in place since Congress first enacted the 

CAA in 1970 and that have been implemented pursuant to 

regulations promulgated in 1975 and followed in numerous 

subsequent CAA section 111 rulemakings. These requirements 

call on the EPA to develop emission guidelines that reflect 

the EPA’s determination of the BSER for states to follow in 

formulating plans to implement standards of performance to 

achieve emission reductions consistent with the BSER. In 
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following the provisions, the EPA is finalizing a BSER 

based on strategies currently being used by states and 

companies to reduce CO2 emissions from EGUs.

In this final action, the agency has determined that the 

BSER comprises the first three of the four proposed building 

blocks, with certain refinements to the three building blocks. 

The widely demonstrated availability of the trading of emission 

rate credits or mass allowances as a mechanism to facilitate 

achievement by any individual EGU or group of EGUs of the 

emission reductions available from each of the building blocks, 

as well as to reduce costs, supports this approach. Any affected 

EGU can achieve the equivalent of dispatch of NGCC units, per 

building block 2, or of RE generation, per building block 3, by 

using the acquisition of a credit or allowance as the medium for 

investment in lower-emitting generation provided by NGCC units 

or RE facilities. 

The CAA, as interpreted by the courts, identifies several 

factors for the EPA to consider in a BSER determination. These 

include technical feasibility, costs, size of emission 

reductions and technology (e.g., whether the system promotes the 

implementation and further development of technology). In 

determining the BSER for this industrial sector, the EPA 

considered the reductions achievable through measures that 
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reduce CO2 emissions from existing fossil fuel-fired EGUs either 

by (1) reducing the CO2 emission rate at those units or (2) 

reducing the units’ CO2 emission total to the extent that 

generation can be shifted from higher-emitting fossil fuel-fired 

EGUs to lower- or zero-emitting options. 

As the EPA has done in making BSER determinations in 

previous CAA section 111(d) rulemakings, the agency considered 

the types of strategies that states and owners and operators of 

EGUs are already employing to reduce the covered pollutant (in 

this case, CO2) from affected sources (in this case, fossil fuelfired EGUs).15 

To determine the BSER for reducing CO2 emissions at 

affected EGUs and to establish the emission guidelines that 

reflect the BSER, the EPA considered numerous measures that 

can and are being implemented to improve emission rates and 

to reduce or limit mass CO2 emissions from fossil fuel-fired 

EGUs. These measures encompass two basic approaches: 1) 

 

15 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 r) are one example, as they allow either of two 

approaches for controlling landfill gas – by recovering the gas as 

a fuel, for sale, and removing from the premises, or by 

destroying the organic content of the gas on the premises using 

a control device. Recovering the gas as a fuel source was a 

practice already being used by some affected sources prior to 

promulgation of the rulemaking.
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reducing the carbon intensity of certain affected EGUs by 

improving the efficiency of their operations, and 2) 

addressing affected EGUs’ mass emissions by varying their 

utilization levels. For the second approach, we relied on 

the standard statutory and regulatory considerations that 

provide the basis for any BSER determination in examining, 

in this case, the extent to which that generation can be 

shifted from higher-emitting fossil fuel-fired EGUs to 

lower- or zero-emitting options. From these two approaches, 

we identified measures that fit into three main categories, 

or “building blocks.” The building blocks are: 

1. Reducing the carbon intensity of generation at 

individual affected coal-fired steam EGUs through heat 

rate improvements. 

2. Substituting increased generation from loweremitting existing natural gas combined cycle units for 

reduced generation from higher-emitting affected steam 

generating units. 

3. Substituting increased generation from new low- and 

zero-emitting generating units, including renewable 

energy and new natural gas combined cycle (NGCC) 

units, for reduced generation from affected fossil 

fuel-fired generating units. 
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The building blocks are described in detail in Section 

V of this preamble. As explained in that section, the EPA 

evaluated each of the building blocks individually against 

the BSER factors. The EPA found that each of the building 

blocks independently merits consideration as part of the 

BSER because, at the identified level of stringency, it is 

achievable by individual sources and by the source 

category, it will result in meaningful emission reductions 

at reasonable cost, and it satisfies the other BSER 

factors. This includes considering the use of some 

increment of new NGCC generation as part of building block 

3, since replacing higher-emitting existing steam 

generation with cleaner new NGCC generation has been 

occurring to some degree. (For reasons discussed in Section 

V.A.3 of this preamble, the EPA determined not to finalize 

the inclusion of demand-side EE, which was discussed as a 

fourth potential building block in the proposal, as a 

component of the BSER.) 

The EPA also evaluated combinations of the three 

building blocks against the BSER factors in making its 

determination. The EPA determined that the combination of 

all three building blocks is the BSER, taking into account 

the fact that the widely demonstrated availability of the 
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trading of emission rate credits or mass allowances can 

enable any given EGU to achieve its emission reduction 

obligations (i.e., if an EGU should choose not to meet its 

obligations simply by limiting its own operations, it could 

rely on the interconnected function of the electricity 

system to effectuate replacement generation from new clean 

generation or from the re-dispatch of existing NGCC units). 

This combination best represents the BSER because, compared 

to combinations including fewer than all three building 

blocks, it achieves greater emission reductions at a lower 

cost, takes better advantage of the wide range of measures 

that states, cities, towns and utilities are already using 

to reduce CO2 from EGUs, and reflects the integrated nature 

of the electricity system and the diversity of electricity 

generation technology. 

For the final rule, in response to stakeholder comments, 

the EPA has made refinements to the building blocks, and these 

are reflected in the final BSER. These include adoption of a 

modified approach to quantification of the renewable energy 

component, exclusion of the proposed nuclear generation 

components, and adoption of a consistent regionalized approach 

to quantification of all three building blocks. The BSER also 

includes an increment of emission reductions at affected EGUs 
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that corresponds to the increment of generation at new NGCC 

units projected to be built in the future that can replace 

generation at affected EGUs (e.g., generation from new NGCC 

units beyond what is needed to meet load growth and that is, 

therefore, available to displace existing, higher-emitting 

generation). The agency also recognizes the important functional 

relationship between the period of time over which measures are 

deployed and the stringency of emission limitations those 

measures can achieve in a practical and reasonable cost way. 

Therefore, the final BSER also reflects adjustments to the 

stringency of the building blocks, after consideration of more 

and less stringent levels, and refinements to the timeframe over 

which reductions must be achieved. Sections V.C through V.E 

provide further information on the refinements made to the 

building blocks and the rationale for doing so. 

As part of the BSER determination, the EPA considered 

the impacts that implementation of the emission reductions 

based on the combination of the blocks will have on the 

cost of electricity and electricity system reliability. As 

detailed in Section V of this preamble, the EPA believes 

that, both with respect to the overall BSER and with 

respect to the individual building blocks, the associated 

costs are reasonable. In summary, the EPA determined that 
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the BSER for purposes of CAA section 111(d), as applied to 

existing fossil fuel-fired EGUs, is based on a combination 

of measures that reduce CO2 emissions and CO2 emission rates 

and encompasses three building blocks, together with 

emissions trading.16 

In determining the BSER, we considered the ranges of 

reductions that can be achieved at reasonable cost by 

application of each building block, considering both 

stringency and time, and we have calculated CO2 emission 

performance rates for the categories of fossil fuel-fired 

electric utility steam generating units and stationary 

combustion turbines. Rather than the maximum possible 

degree of application, we have finalized what we believe 

reflects a reasonable degree of application of each 

building block consistent with the BSER criteria. Relying 

on the three building blocks to characterize the 

combination of measures that reduce CO2 emissions and CO2

emission rates at affected EGUs as the basis for the BSER 

is consistent with strategies, actions and measures that 

 

16 The EPA notes that under the BSER, some building blocks will 

apply to some, but not all, affected sources. Specifically, 

building block 1 will apply to affected coal-fired steam EGUs, 

building block 2 will apply to all affected steam EGUs (both 

coal-fired and oil/gas-fired), and building block 3 will apply 

to all affected EGUs. 
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companies and states are already undertaking to reduce GHG 

emissions and with current trends in the utility power 

sector, driven by efforts to reduce GHGs as well as by 

other factors, such as advancements in technology. Reliance 

on all three building blocks in this way also supports the 

goals of achieving significant and technically feasible 

reductions of CO2 at a reasonable cost, while also promoting 

technology and approaches that are important for achieving 

further reductions. Finally, the EPA believes that the 

diverse range of measures encompassed in the three building 

blocks, and the availability of emissions trading, allows 

states and sources to take full advantage of the inherent 

flexibility of the current regionally interconnected and 

integrated electricity system so as to achieve the CO2 goals 

while continuing to meet the demand for electricity 

services in a reliable and affordable manner. 

The EPA recognizes that states differ in important 

ways, including in their mix of existing EGUs, policy 

priorities, and regional resource development 

opportunities. Consequently, opportunities for reducing 

emissions, as reflected in each of the building blocks, 

vary across states. Each state will be able to design a 

program that uses the measures it selects, and these may 
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include the combination of building blocks most relevant to 

its specific circumstances and policy preferences. States 

may also use technologies or strategies that are not 

explicitly mentioned in any of the three building blocks 

and may use those technologies or strategies as part of 

their overall plans (e.g., market-based trading programs; 

demand-side energy efficiency programs). Explanation of 

other technologies or strategies that a state may 

incorporate in its plan is provided in Section VIII of this 

preamble. Additionally, the EPA’s approach allows multistate strategies, ranging from the formal types of 

interstate arrangements (joint plans) to flexibility for 

sources in “trading ready” states to interact with one 

another through trading. These issues are discussed in 

greater detail in Section VIII. 

e. CO2 source category-specific emission performance rates and 

state-level goals. 

(1) Final CO2 emission performance rates and goals. In this 

action, the EPA is establishing CO2 emission performance rates 

for two subcategories of affected EGUs-- fossil fuel-fired 

electric utility steam generating units and stationary 

combustion turbines -- that state plans must be designed to 

meet. For fossil fuel-fired steam generating units, we are 
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finalizing an emission performance rate of 1,290 lb/MWh of CO2. 

For stationary combustion turbines, we are finalizing an 

emission performance rate of 780 lb/MWh of CO2. 

To continue to provide the flexibility inherent in the 

proposal’s state-specific goals approach, in this final 

rule, the EPA has translated the source category-specific 

CO2 emission performance rates into equivalent statewide 

rate-based and mass-based CO2 goals and is providing those 

in Section VII of this preamble. 

Affected EGUs, individually, in aggregate, or in 

combination with other measures undertaken by the state, 

must achieve the equivalent of the CO2 emission performance 

rates by 2030. Importantly, by expressing the application 

of the final BSER as source category-specific CO2 emission 

performance rates, and by providing a translation of those 

performance rates to statewide rate- and mass-based CO2

goals, the rule allows states the flexibility to determine 

how to achieve the CO2 reductions (i.e., greater reductions 

from one building block and less from another, as well as 

the adoption of other measures that lower carbon 

intensity), and to adjust the timing in which reductions 

are achieved, in order to address key issues such as cost 
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to consumers, electricity system reliability and the 

remaining useful life of existing generation assets. 

(2) Interim CO2 emission performance rates and state-level 

goals. The EPA recognizes that, with many measures, states can 

achieve CO2 emission reductions in the short-term, in certain 

circumstances, such as those for which instrumental 

infrastructure and/or programs are already in place. For other 

measures, such as the addition of renewable energy (RE) 

generating capacity, the full effects of implementation can take 

longer. We recognize that, under the Clean Air Act, the 

determination of the BSER includes not only the types of 

measures that constitute the best system, but also the timeframe 

within which those measures can reasonably be implemented. In 

the proposal, we included an interim period – 2020 through 2029 

– reflecting that reductions could reasonably be achieved on a 

glide path toward meeting the final goals in 2030. For the final 

emission guidelines, in response to concerns that required CO2

emission reductions could not be achieved as early as 2020 – and 

to reflect the period of time required through the process of 

state plan development and submission to the EPA, the EPA review 

and approval and state and EGU implementation of approved plans 

- the EPA is establishing an eight-year interim period over 

which to achieve the full required reductions to meet the CO2
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performance rates, and this begins in 2022, more than six years 

from [INSERT THE DATE OF PUBLICATION IN THE FEDERAL REGISTER], 

the date of this rulemaking. This eight-year interim period from 

2022 through 2029 is separated into three steps, 2022-2024, 

2025-2027, and 2028-2029, each associated with its own interim 

CO2 emission performance rates. These steps respond to many 

comments we received requesting a more graduated trajectory, but 

the rule also retains a state’s ability to adapt these steps as 

appropriate to accommodate the timing of expected reductions, as 

long as the interim goal is met over the eight year period. A 

state can take advantage of this timing in the design of its 

program by using relevant combinations of building blocks, as 

well as averaging over the interim period, to achieve required 

CO2 reductions in a manner and on a schedule that provides for 

electricity system reliability, avoids the creation of stranded 

assets and bears a reasonable cost. In short, to use the 

parlance of numerous state and stakeholder discussions, states 

can determine their own respective emission reduction 

trajectories or “glide paths”.

We believe that this approach for achieving CO2

reductions over time responds both to the needs of an 

effectively implemented program and to the persuasive 

arguments presented by stakeholders regarding balancing the 
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simultaneous need for both flexibility and certainty about 

what will constitute an approvable state plan. We likewise 

believe that this approach also represents a reasonable 

balance between two competing objectives grounded in CAA 

section 111(d) - a need for rigor and consistency in 

calculating emission reductions reflecting the BSER and a 

need to provide the states with flexibility in establishing 

and implementing the emission standards or measures that 

reflect those emission reductions. The importance of this 

balance is heightened by the fact that the operations of 

the electricity system itself rely on the flexibility made 

available and achieved through shifting generation between 

and among multiple interconnected EGUs, demand management 

and demand-side energy efficiency. This approach recognizes 

that state plans for emission reductions can, and must, be 

consistent with a vibrant and growing economy and the ample 

supply of reliable, affordable electricity needed to 

support that economy. It further reflects the growing 

trend, as exemplified by many state and local clean energy 

policies and programs, to shift energy production away from 

carbon-intensive fuels to a modern, more sustainable system 

that puts greater reliance on renewable energy, energy 

efficiency and other low-carbon energy options. 
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f. State plans.17 In this action, the EPA is also 

establishing final guidelines for states to follow in 

developing their plans. In developing plans, states will 

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

will also need to include required plan components in their 

plan submittals, meet plan submittal deadlines, achieve the 

required CO2 emission reductions over time, and provide for 

monitoring and periodic reporting of progress. 

(1) Plan approaches. To comply with these emission 

guidelines, in its plan, each state will have to ensure that the 

emission standards it establishes for its sources individually, 

in aggregate, or in combination with other measures undertaken 

by the state, represent the equivalent of the source categoryspecific emission performance rates. This final rule includes 

several types of flexibilities for state plans, as discussed in 

the proposal and in many of the comments we received. 

 

17

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

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

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

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

more affected EGUs in its jurisdiction. The District of Columbia 

does not have any affected EGUs and, therefore, will not be 

required to submit a plan. 
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First, under the final rule, states may adopt either a 

rate-based or mass-based goal. For this purpose, the EPA is 

providing statewide rate-based goals and mass-based goals 

equivalent to the emission performance rates that the EPA is 

establishing for the two subcategories of fossil fuel-fired 

EGUs. In developing its plan, each state, U.S. territory, and 

eligible tribe will need to choose whether it will include CO2

emission performance rates, statewide rate-based goals, or 

statewide mass-based goals. 

The second major flexibility provided in the final rule 

relates to the types of measures included in the state plans. A 

state will be able to choose to place all of the requirements 

directly on its affected EGUs, which we refer to as the 

“emission standards approach.” Alternatively, a state can adopt 

a “state measures approach,” which would include stateenforceable measures that may apply to affected EGUs and other 

entities, with some or no federally enforceable emission 

standards for affected EGUs. With a state measures approach, the 

plan must also include a backstop of federally enforceable 

standards on affected EGUs that fully meet the emission 

guidelines and that would be triggered if the plan failed to 

achieve on schedule the required emission reductions. A state 

would have the option of basing its backstop emission standards 
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on the federal plan, using the federal plan regulations as a 

model rule. 

The plan must also include a process for reporting on plan 

implementation, progress toward achieving CO2 emission 

reductions, and implementation of corrective actions, if 

applicable. Beginning January 1, 2025, and then January 1, 2027, 

followed by January 1, 2029, and then every two calendar years, 

the state will be required to compare emission levels achieved 

by affected EGUs in the state with the emission levels projected 

in the state plan and report the results of that comparison to 

the EPA by July 1 of those calendar years. 

Plans for states with existing programs, such as those 

being implemented in California and the RGGI states, will 

be approvable provided that, when plans are submitted, they 

demonstrate that when the plans are fully implemented, 

affected EGUs achieve all of the emission reductions 

required in these guidelines for those states’ sources that 

are affected per these guidelines. The plan guidelines 

provide the states with the ability to achieve the full 

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

reduction strategies, using state-specific or multi-state 

approaches that can be achieved on either a rate or mass 

basis. They also address several key policy considerations 
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that states can be expected to contemplate in developing 

their plans. 

State plan approaches and plan guidelines are explained 

further in Section VIII of this preamble. 

(2) State plan components and approvability criteria. The 

EPA’s implementing regulations provide certain basic elements 

required for state plans submitted pursuant to CAA section 

111(d). 40 CFR 60.23. In the proposal, the EPA identified 

certain additional elements that should be contained in state 

plans. In this final action, in response to comments, the EPA is 

making several revisions to the components required in a state 

plan submittal and is also incorporating the approvability 

criteria into the list of components required in a state plan 

submittal. In addition, we have revised the state plan 

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

submittals; 2) additional components required for the emission 

standards approach; and 3) additional components required for 

the state measures approach. 

All state plans must include the following components: 

 Description of the plan 

 Identification of state CO2 interim period goal (for 

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

2022-2024; interim step goal 2 for 2025-2027; interim 

step goal 3 for 2028-2029) and final CO2 emission goal 

of 2030 and beyond 

 Demonstration that the plan submittal is projected to 

achieve the state’s CO2 emission goal 
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 State recordkeeping and reporting requirements 

 Certification of hearing on state plan 

 Supporting documentation 

 

Also, in submitting state plans, states must provide 

documentation demonstrating that they have considered 

reliability in developing their plans. 

Further, because certain communities, including low-income 

communities and some communities of color, are 

disproportionately affected by climate change related impacts, 

the EPA is seeking to ensure that states are actively engaging 

with communities and is, therefore, requiring states to provide, 

in their initial plan submittal, a summary of how they have been 

engaging with community stakeholders and how they intend to 

meaningfully engage with community stakeholders during the 

additional time (if an extension is granted) for development of 

the final plan. For the final plan submittal, states must have 

meaningful engagement with all members of the public, including 

affected communities, during the final plan development process, 

pursuant to the public participation requirements of the 

implementing regulations. This could include topics such as 

potential localized impacts and potential changes to electricity 

rates, among others.

State plan submittals using the emission standards approach 

must also include: 
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 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. Commenters 

have provided compelling information that it will take longer 

than the agency initially anticipated to adjust investments and 

achieve interim CO2 reductions. The EPA agrees with these 

comments, which we believe support extending the start date of 

the compliance period from 2020 to 2022 and retaining the 
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requirement that initial plans be submitted without additional 

delay. Specifically, the final rule requires each state to 

submit a plan by August 31, 2016. Since some states may need 

more than one year to complete all of the actions needed for 

their final state plans, including technical work, state 

legislative and rulemaking activities, a robust public 

participation process, coordination with third parties, and 

coordination among states involved in multi-state plans, as well 

as consultation with reliability entities, the EPA is allowing 

an optional two-phased submittal process for state plans. Each 

state will be required to submit a plan by August 31, 2016, that 

contains certain required components. If a state needs 

additional time to submit a final plan, then the state may 

submit an initial plan by August 31, 2016, that documents the 

reasons the state needs more time and includes commitments to 

concrete steps that will ensure that the state will submit a 

final plan by August 31, 2018. To be approvable, the EPA is 

finalizing that the initial plan submittal must address all 

components of a final plan submittal, including identifying 

which components are not complete. The initial plan must include 

specific components, including a justification for seeking an 

extension, a description of the plan approach, a commitment to 

maintain existing measures that limit CO2 emissions, progress to 
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date in developing a final plan, a comprehensive roadmap of the 

path to completion including specific steps the state, sources 

or other entities will be implementing in order to meet the 

initial compliance requirements beginning in 2022, and 

demonstration of opportunity for public comment on the submittal 

and a summary of the state’s response to any significant public 

comment on the approvability of the initial plan, as described 

in Section VIII.E of this preamble. 

If the initial submittal includes those components and if 

the EPA does not notify the state that the initial submittal 

does not contain the required components, the extension of time 

to submit a final plan will be deemed granted and a state will 

have until August 31, 2018, to submit a final plan. Further, 

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

joint plan on behalf of all of the participating states. States, 

U.S. territories, and tribes that do not have affected EGUs in 

their jurisdictional boundaries may participate in emission 

trading programs (e.g., as providers of emission rate credits, 

to adjust CO2 emission rates for affected EGUs). 

Following submission of final plans, the EPA will 

review plan submittals for approvability. Given the diverse 

approaches states may take to meet the CO2 emission 

performance rates or equivalent statewide goals in the 
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emission guidelines, the EPA is extending the period for 

EPA review and approval or disapproval of plans from the 

four-month period provided in the EPA implementing 

regulations to a twelve-month period. 

(4) Timing for meeting the CO2 emission guidelines. The EPA 

recognizes that the measures states and utilities have been and 

will be taking to reduce CO2 emissions from existing EGUs can 

take time to implement. Based on a careful review of the 

comments and other material in the record, the EPA is 

determining in this final rule that affected EGUs will be 

required to begin to make reductions by 2022, instead of 2020, 

as proposed, and meet the final CO2 performance rates or 

equivalent statewide goals by no later than 2030. The EPA is 

establishing an eight-year interim period that begins in 2022 

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

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

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

period step 1, 2, and 3 CO2 performance rates, or must meet the 

equivalent statewide interim period goals, on average, that a 

state may establish over the 8-year period from 2022-2029, which 

the state must reflect in its CAA section 111(d) plan. Affected 

EGUs must also achieve the final CO2 performance rates or the 

equivalent statewide goal by 2030 and maintain that level 
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subsequently. This approach reflects adjustments to the 

timeframe over which reductions must be achieved that mirror the 

determination of the final BSER. The agency believes that this 

approach for timing is reasonable and appropriate, is consistent 

with many of the comments we received, and will best support the 

optimization of overall CO2 reductions. 

Measures that a state takes prior to 2022, or programs 

already in place by 2022, that result in CO2 emission reductions 

during the 2022-2029 period will contribute toward meeting both 

the interim and final CO2 emission performance rates. Thus, 

states with currently existing programs and policies, and states 

that put in place new programs and policies early, will be 

better positioned to achieve the goals. RE generating capacity 

and demand-side EE measures that are installed after 2012 will 

be eligible for use in adjusting a CO2 emission performance rate. 

Further discussion of timing is presented in Section VIII.G of 

this preamble. 

(5) Electric system reliability. These guidelines reflect 

the paramount importance of ensuring electric system 

reliability, in no small part thanks to the comments we 

received and our extensive consultation with key agencies 

responsible for reliability, including FERC and DOE, among 

others. We are addressing these concerns in large part by moving 
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the start date of the program from 2020 to 2022 and 

significantly adjusting the interim goals so that they provide a 

less abrupt initial reduction expectation. These changes will 

provide more time for planning, consultation and decision making 

in the formulation of state plans and in EGUs’ choice of 

compliance strategies, all within the existing extensive 

structure of energy planning at the state and regional levels. 

In addition, the various forms of flexibility retained and 

enhanced in this final rule, including opportunities for trading 

within and between states, and other multi-state compliance 

approaches, will further support electric system reliability. In 

addition, we are including in the final rule a requirement that 

each state demonstrate in its state plan submittal that it has 

considered reliability issues in developing its plan, which it 

can do, for example, by consulting with state utility agencies 

and/or regional planning authorities. 

We recognize that issues may arise during the 

implementation of the guidelines that may warrant adjustments to 

a state’s plan in order to maintain electric system reliability. 

The final guidelines further provide states with the option of 

proposing amendments to approved plans in the event that 

unanticipated and significant reliability challenges arise. 

And, as a final element of reliability assurance, the rule also 
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provides for a reliability safety valve for individual sources 

where there is a conflict between the requirements the state 

plan imposes on a specific affected EGU and the maintenance of 

electric system reliability due to an extraordinary event. In 

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

efforts to help ensure continued reliable electricity generation 

and transmission during the implementation of the final 

rule. The three agencies have set out a memorandum that reflects 

their joint understanding of how they will work together to 

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. 

(6) Outreach and resources for stakeholders. To provide 

states, U.S. territories, tribes, utilities, communities, and 

other interested stakeholders with understanding about the rule 

requirements, and to provide efficiencies where possible and 

reduce the cost and administrative burden, the EPA will continue 

to work with states, tribes, and stakeholders to provide 
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information and address questions about the final rule. Outreach 

will include opportunities for states and tribes to participate 

in briefings, teleconferences, and meetings about the final 

rule. The EPA’s 10 regional offices will continue to be the 

entry point for states, tribes and territories to ask technical 

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

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

various components of the final rule; these webinars are planned 

for the first two months after the final rule is issued. The EPA 

will also offer consultations with tribal officials. The EPA 

will continue outreach throughout the plan development and 

submittal process. The EPA will use information from this 

outreach process to inform the training and other tools will be 

of most use to the state, tribes, and territories that are 

implementing the final rule. 

The EPA has worked with communities, states, tribes and 

relevant associations to develop an extensive training plan that 

will continue in the months after the Clean Power Plan is 

finalized. The EPA has assembled resources from a variety of 

sources to create a comprehensive training curriculum for those 

implementing the Clean Power Plan. Recorded presentations from 

the EPA, DOE and other federal entities will be available for 

communities, states, and others involved in composing and 
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participating in the development of state plans. This curriculum 

is available online at EPA’s Air Pollution Training Institute. 

The EPA also expects to issue guidance on specific topics. 

As guidance documents, tools, templates and other resources 

become available, the EPA, in consultation with the U.S. 

Department of Energy and other federal agencies, will continue 

to make these resources available via a dedicated website.18 

We intend to continue to work actively with states, U.S. 

territories and tribes to provide information and technical 

support that will be helpful to them in developing and 

implementing their plans. 

Additional detail on aspects of the final rule is 

included in several technical support documents (TSDs) and 

memoranda that are available in the rulemaking docket. 

5. Projected national-level emission reductions 

Under the final guidelines, the EPA projects annual CO2

reductions of [X} percent below 2005 levels in 2020, [X} 

percent below 2005 levels in 2025, and [X] percent below 

2005 levels in 2030. These guidelines will also result in 

important reductions in emissions of criteria air 

pollutants, including sulfur dioxide (SO2), nitrogen oxides 

(NOX), and directly emitted fine particulate matter (PM2.5). 

 

18 www.epa.gov/cleanpowerplantoolbox. 
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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. 

6. 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 energy 

efficiency. 

The EPA estimates that, in 2020, the final guidelines will 

yield monetized climate benefits of approximately $[X] billion 

(2011$) using a 3 percent discount rate (model average) relative 

to the 2020 base case (Table 1).19 The air pollution health co-

 

19 The EPA has used social cost of carbon (SCC) estimates — i.e., 

the monetary value of impacts associated with a marginal change 
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benefits associated with reducing exposure to ambient PM2.5 and 

ozone through emission reductions of precursor pollutants in 

2025 relative to the 2020 base case are estimated to be $[X] 

billion to $[X] billion using a 3 percent discount rate and $[X] 

billion to $[X] billion (2011$) using a 7 percent discount rate. 

In 2025, the final guidelines will yield monetized climate 

benefits of approximately $[X] billion (2011$) using a 3 percent 

discount rate (model average) relative to the 2025 base case 

(Table 1). The air pollution health co-benefits in 2025 relative 

to the 2025 base case are estimated to be $[X] billion to $[X] 

billion using a 3 percent discount rate and $[X] billion to $[X] 

billion (2011$) using a 7 percent discount rate. 

In 2030, the EPA estimates the final guidelines will yield 

monetized climate benefits of approximately $[X] billion (2011$) 

using a 3 percent discount rate (model average) relative to the 

2030. The air pollution health co-benefits in 2030 relative to 

the 2030 base case are estimated to be $[X] billion to $[X] 

 

in CO2 emissions in a given year — to analyze the benefits from 

changes in CO2 emissions expected from this rulemaking. The four 

SCC estimates are associated with different discount rates 

(model average at 2.5 percent discount rate, 3 percent, and 5 

percent; 95th percentile at 3 percent), and each increases over 

time. In this summary, the EPA provides the estimate of climate 

benefits associated with the SCC value deemed to be central: the 

model average at 3 percent discount rate. 
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billion using a 3 percent discount rate and $[X] billion to $[X] 

billion (2011$) using a 7 percent discount rate. 

The annual compliance costs are estimated using the 

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

efficiency program and participant costs as well as monitoring, 

reporting and recordkeeping costs. In 2020, total compliance 

costs of the final guidelines are approximately $[X] billion 

(2011$). In 2025, total compliance costs of the final guidelines 

are approximately $[X] billion (2011$). In 2030, total 

compliance costs of the final guidelines are approximately $[X] 

billion (2011$). 

The quantified net benefits (the difference between 

monetized benefits and compliance costs) in 2020 are estimated 

to range from $[X] billion to $[X] billion (2011$) using a 3 

percent discount rate (model average). In 2025, the quantified 

net benefits (the difference between monetized benefits and 

compliance costs) in 2025 are estimated to range from $[X] 

billion to $[X] billion (2011$) using a 3 percent discount rate 

(model average). In 2030, the quantified net benefits (the 

difference between monetized benefits and compliance costs) in 

2030 are estimated to range from $[X] billion to $[X] billion 

(2011$) using a 3 percent discount rate (model average). 
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Table 1. Summary of the Monetized Benefits, Compliance Costs, 

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

2030a [Billions of 2011$] 

Final Guidelines, 2020 

 3% Discount Rate 7% Discount rate 

Climate benefits b $[X] 

Air pollution health 

co-benefits c $[X] to $[X] $[X] to $[X] 

Total Compliance 

Costs d $[X] $[X] 

Net Monetized 

Benefits e $[X] to $[X] $[X] to $[X] 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and 

SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

Final Guidelines, 2025 

 3% Discount rate 7% Discount rate 

Climate benefits b $[X] 

Air pollution health 

co-benefits c $[X] to $[X] $[X] to $[X] 

Total Compliance 

Costs d $[X] $[X] 

Net Monetized 

Benefits e $[X] to $[X] $[X] to $[X] 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and 

SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 
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Final Guidelines, 2030 

Climate benefits b $[X] 

Air pollution health 

co-benefits c $[X] to $[X] $[X] to $[X] 

Total Compliance 

Costs d $[X] $[X] 

Net Monetized 

Benefits e $[X] to $[X] $[X] to $[X] 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 

and SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

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% 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 
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final guidelines and a discount rate of approximately 5%. This 

estimate includes monitoring, recordkeeping, and reporting costs 

and demand side energy efficiency program and participant costs. 

e The estimates of net benefits in this summary table are 

calculated using the global SC-CO2 at a 3 percent discount rate 

(model average). The RIA includes combined climate and health 

estimates based on additional discount rates. 

There are additional important benefits that the EPA 

could not monetize. Due to current data and modeling 

limitations, our estimates of the benefits from reducing CO2

emissions do not include important impacts like ocean 

acidification or potential tipping points in natural or 

managed ecosystems. The unquantified benefits also include 

climate benefits from reducing emissions of non-CO2

greenhouse gases (e.g., nitrous oxide and methane)20 and cobenefits from reducing direct exposure to SO2, NOX, and 

hazardous air pollutants (e.g., mercury and hydrogen 

chloride), as well as from reducing ecosystem effects and 

visibility impairment. 

We project employment gains and losses relative to 

base case for different types of labor, including 

 

20 Although CO2 is the predominant greenhouse gas released by the 

power sector, electricity generating units also emit small 

amounts of nitrous oxide and methane. For more detail about 

power sector emissions, see RIA Chapter 2 and the U.S. 

Greenhouse Gas Reporting Program’s power sector summary, 

http://www.epa.gov/ghgreporting/ghgdata/reported/powerplants.htm

l.
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construction, plant operation and maintenance, coal and 

natural gas production, and demand side energy efficiency. 

In [X], we project a net change of [X] job-years21 for 

construction, plant operation and maintenance, and coal and 

natural gas and [X] jobs in the demand-side energy 

efficiency sector. 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, 

and the number and extent of comments received. In Section III 

 

21 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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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 four 

building blocks for setting state goals and our key 

considerations in doing so. Section VI provides the source 

category-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 XII. 

We note that this rulemaking is being promulgated 

concurrently with a related rulemaking, the final new source 

performance standards (NSPS) for CO2 emissions from newly 

constructed, modified, and reconstructed EGUs [INSERT THE 

FEDERAL REGISTER REFERENCE FOR THE FINAL GHG NEW SOURCE RULE], 
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which is being promulgated under CAA section 111(b). This 

rulemaking has its own rulemaking docket. 

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, explain the uniqueness of the utility power sector and 

describe recent and continuing trends and transitions in this 

sector. In addition, we briefly provide highlights of 

Congressional awareness of climate change and international 

agreements and actions, and summarize the statutory and 

regulatory requirements relevant to this rulemaking. In 

addition, we provide background information on the EPA’s June 

18, 2014 Clean Power Plan proposal, the November 4, 2014 

supplemental proposal, and other actions associated with this 

rulemaking,22 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 

 

22 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.”23 

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).24 In the 

Endangerment Finding, the Administrator found that the current, 

elevated concentrations of GHGs in the atmosphere—already at 

levels unprecedented in human history—may reasonably be 

anticipated to endanger public health and welfare of current and 

future generations in the United States. We summarize these 

adverse effects on public health and welfare briefly here. 

 

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

24 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases Under Section 202(a) of the Clean Air Act,” 74 Fed. Reg. 

66,496 (Dec. 15, 2009) (“Endangerment Finding”).
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1. Public health impacts detailed in the 2009 Endangerment 

Finding 

Climate change caused by human emissions of GHGs threatens 

the health of Americans in multiple ways. By raising average 

temperatures, climate change increases the likelihood of heat 

waves, which are associated with increased deaths and illnesses. 

While climate change also increases the likelihood of reductions 

in cold-related mortality, evidence indicates that the increases 

in heat mortality will be larger than the decreases in cold 

mortality in the United States. Compared to a future without 

climate change, climate change is expected to increase ozone 

pollution over broad areas of the U.S., including 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 
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Climate change impacts touch nearly every aspect of public 

welfare. Among the multiple threats caused by human emissions of 

GHGs, climate changes are expected to place large areas of the 

country at serious risk of reduced water supplies, increased 

water pollution, and increased occurrence of extreme events such 

as floods and droughts. Coastal areas are expected to face a 

multitude of increased risks, particularly from rising sea level 

and increases in the severity of storms. These communities face 

storm and flooding damage to property, or even loss of land due 

to inundation, erosion, wetland submergence and habitat loss. 

Impacts of climate change on public welfare also include 

threats to social and ecosystem services. Climate change is 

expected to result in an increase in peak electricity demand. 

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 
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rise. These impacts are global and may exacerbate problems 

outside the U.S. that raise humanitarian, trade, and national 

security issues for the U.S. 

3. New scientific assessments and observations 

Since the administrative record concerning the Endangerment 

Finding closed following the EPA’s 2010 Reconsideration Denial, 

the climate has continued to change, with new records being set 

for a number of climate indicators such as global average 

surface temperatures, Arctic sea ice retreat, CO2 concentrations, 

and sea level rise. Additionally, a number of major scientific 

assessments have been released that improve understanding of the 

climate system and strengthen the case that GHGs endanger public 

health and welfare both for current and future generations. 

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 
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Targets: Emissions, Concentrations, and Impacts over Decades to 

Millennia (Climate Stabilization Targets), 2011 National 

Security Implications for U.S. Naval Forces (National Security 

Implications), 2011 Understanding Earth’s Deep Past: Lessons for 

Our Climate Future (Understanding Earth’s Deep Past), 2012 Sea 

Level Rise for the Coasts of California, Oregon, and Washington: 

Past, Present, and Future, 2012 Climate and Social Stress: 

Implications for Security Analysis (Climate and Social Stress), 

and 2013 Abrupt Impacts of Climate Change (Abrupt Impacts) 

assessments. 

The EPA has carefully reviewed these recent assessments in 

keeping with the same approach outlined in Section VIII.A of the 

2009 Endangerment Finding, which was to rely primarily upon the 

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. 
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The findings of the recent scientific assessments confirm 

and strengthen the conclusion that GHGs endanger public health, 

now and in the future. The NCA3 indicates that human health in 

the United States will be impacted by “increased extreme weather 

events, wildfire, decreased air quality, threats to mental 

health, and illnesses transmitted by food, water, and diseasecarriers such as mosquitoes and ticks.” The most recent 

assessments now have greater confidence that climate change will 

influence production of pollen that exacerbates asthma and other 

allergic respiratory diseases such as allergic rhinitis, as well 

as effects on conjunctivitis and dermatitis. Both the NCA3 and 

the IPCC AR5 found that increasing temperature has lengthened 

the allergenic pollen season for ragweed, and that increased CO2

by itself can elevate production of plant-based allergens. 

The NCA3 also finds that climate change, in addition to 

chronic stresses such as extreme poverty, is negatively 

affecting indigenous peoples’ health in the United States 

through impacts such as reduced access to traditional foods, 

decreased water quality, and increasing exposure to health and 

safety hazards. The IPCC AR5 finds that climate change-induced 

warming in the Arctic and resultant changes in environment 

(e.g., permafrost thaw, effects on traditional food sources) 

have significant impacts, observed now and projected, on the 
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health and well-being of Arctic residents, especially indigenous 

peoples. Small, remote, predominantly-indigenous communities are 

especially vulnerable given their “strong dependence on the 

environment for food, culture, and way of life; their political 

and economic marginalization; existing social, health, and 

poverty disparities; as well as their frequent close proximity 

to exposed locations along ocean, lake, or river shorelines.”25 

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 

 

25 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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floods. The IPCC finds that additional health concerns may arise 

in low income households, especially those with children, if 

climate change reduces food availability and increases prices, 

leading to food insecurity within households. 

Both the NCA3 and IPCC AR5 conclude that climate change 

will increase health risks facing the elderly. Older people are 

at much higher risk of mortality during extreme heat events. 

Pre-existing health conditions also make older adults 

susceptible to cardiac and respiratory impacts of air pollution 

and to more severe consequences from infectious and waterborne 

diseases. Limited mobility among older adults can also increase 

health risks associated with extreme weather and floods. 

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.26 In fact, that assessment stated that 

 

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

1.
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“the magnitude and rate of the present greenhouse gas increase 

place the climate system in what could be one of the most severe 

increases in radiative forcing of the global climate system in 

Earth history.”27 Because of these unprecedented changes, several 

assessments state that we may be approaching critical, poorly 

understood thresholds: as stated in the NRC assessment 

Understanding Earth’s Deep Past, “As Earth continues to warm, it 

may be approaching a critical climate threshold beyond which 

rapid and potentially permanent—at least on a human timescale—

changes not anticipated by climate models tuned to modern 

conditions may occur.” 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, 

 

27 Id., p.138.
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according to the NCA3, significant reductions in emissions would 

lead to noticeably less future warming beyond mid-century, and 

therefore less impact to public health and welfare. 

While rainfall may only see small globally and annually 

averaged changes, there are expected to be substantial shifts in 

where and when that precipitation falls. According to the NCA3, 

regions closer to the poles will see more precipitation, while 

the dry subtropics are expected to expand (colloquially, this 

has been summarized as wet areas getting wetter and dry regions 

getting drier). In particular, the NCA3 notes that the western 

U.S., and especially the Southwest, is expected to become drier. 

This projection is consistent with the recent observed drought 

trend in the West. At the time of publication of the NCA, even 

before the last 2 years of extreme drought in California, tree 

ring data was already indicating that the region might be 

experiencing its driest period in 800 years. Similarly, the NCA3 

projects that heavy downpours are expected to increase in many 

regions, with precipitation events in general becoming less 

frequent but more intense. This trend has already been observed 

in regions such as the Midwest, Northeast, and upper Great 

Plains. Meanwhile, the NRC Climate Stabilization Targets 

assessment found that the area burned by wildfire is expected to 

grow by 2 to 4 times for 1 °C (1.8 °F) of warming. For 3 °C of 
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warming, the assessment found that 9 out of 10 summers would be 

warmer than all but the 5 percent of warmest summers today, 

leading to increased frequency, duration, and intensity of heat 

waves. Extrapolations by the NCA also indicate that Arctic sea 

ice in summer may essentially disappear by mid-century. 

Retreating snow and ice, and emissions of carbon dioxide and 

methane released from thawing permafrost, will also amplify 

future warming. 

Since the 2009 Endangerment Finding, the USGCRP NCA3, and 

multiple NRC assessments have projected future rates of sea 

level rise that are 40 percent larger to more than twice as 

large as the previous estimates from the 2007 IPCC 4th Assessment 

Report due in part to improved understanding of the future rate 

of melt of the Antarctic and Greenland Ice sheets. The NRC Sea 

Level Rise assessment projects a global sea level rise of 0.5 to 

1.4 meters (1.6 to 4.6 feet) by 2100, the NRC National Security 

Implications assessment suggests that “the Department of the 

Navy should expect roughly 0.4 to 2 meters [1.3 to 6.6 feet] 

global average sea-level rise by 2100,”28 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 

 

28 NRC, 2011: National Security Implications of Climate Change 

for U.S. Naval Forces. The National Academies Press, p. 28. 
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feet) by 2100. These assessments continue to recognize that 

there is uncertainty inherent in accounting for ice sheet 

processes. Additionally, local sea level rise can differ from 

the global total depending on various factors: the east coast of 

the U.S. in particular is expected to see higher rates of sea 

level rise than the global average. For comparison, the NCA3 

states that “five million Americans and hundreds of billions of 

dollars of property are located in areas that are less than four 

feet above the local high-tide level,” and the NCA3 finds that 

“[c]oastal infrastructure, including roads, rail lines, energy 

infrastructure, airports, port facilities, and military bases, 

are increasingly at risk from sea level rise and damaging storm 

surges.”29 Also, because of the inertia of the oceans, sea level 

rise will continue for centuries after greenhouse gas 

concentrations have stabilized (though more slowly than it would 

have otherwise). Additionally, there is a threshold temperature 

above which the Greenland ice sheet will be committed to 

inevitable melting: according to the NCA, some recent research 

has suggested that even present day carbon dioxide levels could 

be sufficient to exceed that threshold. 

 

29 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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In general, climate change impacts are expected to be 

unevenly distributed across different regions of the United 

States and have a greater impact on certain populations, such as 

indigenous peoples and the poor. The NCA3 finds climate change 

impacts such as the rapid pace of temperature rise, coastal 

erosion and inundation related to sea level rise and storms, ice 

and snow melt, and permafrost thaw are affecting indigenous 

people in the United States. Particularly in Alaska, critical 

infrastructure and traditional livelihoods are threatened by 

climate change and, “[i]n parts of Alaska, Louisiana, the 

Pacific Islands, and other coastal locations, climate change 

impacts (through erosion and inundation) are so severe that some 

communities are already relocating from historical homelands to 

which their traditions and cultural identities are tied.”30 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 

 

30 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 

Eds., 2014: Climate Change Impacts in the United States: The 

Third National Climate Assessment. U.S. Global Change Research 

Program, p. 17. 
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destruction of homes and indirectly through, for example, 

increased food prices and food insecurity.”31 

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% 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. 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 

 

31 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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to have occurred for at least the past hundreds of thousands of 

years.”32 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.”33 

Events outside the United States, as also pointed out in 

the 2009 Endangerment Finding, will also have relevant 

consequences. The NRC Climate and Social Stress assessment 

concluded that it is prudent to expect that some climate events 

“will produce consequences that exceed the capacity of the 

affected societies or global systems to manage and that have 

global security implications serious enough to compel 

international response.” The NRC National Security Implications 

assessment recommends preparing for increased needs for 

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 

 

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

the Challenges of a Changing Ocean. The National Academies 

Press, p. 5. 

33 Ibid. 
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happening now and it is happening in the United States. 

According to the IPCC AR5 and the NCA3, there are a number of 

climate-related changes that have been observed recently, and 

these changes are projected to accelerate in the future. The 

planet warmed about 0.85 °C (1.5 °F) from 1880 to 2012. It is 

extremely likely (>95% probability) that human influence was the 

dominant cause of the observed warming since the mid-20th

century, and likely (>66% 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 
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decade, and Northern Hemisphere snow cover extent has decreased 

at about 1.6 percent per decade for March and 11.7 percent per 

decade for June. Permafrost temperatures have increased in most 

regions since the 1980s, by up to 3 °C (5.4 °F) in parts of 

Northern Alaska. Winter storm frequency and intensity have both 

increased in the Northern Hemisphere. The NCA3 states that the 

increases in the severity or frequency of some types of extreme 

weather and climate events in recent decades can affect energy 

production and delivery, causing supply disruptions, and 

compromise other essential infrastructure such as water and 

transportation systems. 

In addition to the changes documented in the assessment 

literature, there have been other climate milestones of note. In 

2009, the year of the Endangerment Finding, the average 

concentration of CO2 as measured on top of Mauna Loa was 387 

parts per million, far above preindustrial concentrations of 

about 280 parts per million.34 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 

 

34ftp://aftp.cmdl.noaa.gov/products/trends/co2/co2_annmean_mlo.tx

t
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400 parts per million since record keeping began at Mauna Loa in 

1958, and for at least the past 800,000 years.35 Arctic sea ice 

has continued to decline, with September of 2012 marking a new 

record low in terms of Arctic sea ice extent, 40 percent below 

the 1979-2000 median. Sea level has continued to rise at a rate 

of 3.2 mm per year (1.3 inches/decade) since satellite 

observations started in 1993, more than twice the average rate 

of rise in the 20th century prior to 1993.36 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 2002.37 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 

 

35 http://www.esrl.noaa.gov/gmd/ccgg/trends/

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

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

37 http://www.ncdc.noaa.gov/sotc/global/2014/13 
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begin the process of substantially reducing emissions.”38 For 

example: 

 The faster emissions are reduced, the lower the risks 

posed by climate change. Delays in reducing emissions 

could commit the planet to a wide range of adverse 

impacts, especially if the sensitivity of the climate to 

greenhouse gases is on the higher end of the estimated 

range. 

 Waiting for unacceptable impacts to occur before taking 

action is imprudent because the effects of greenhouse gas 

emissions do not fully manifest themselves for decades 

and, once manifest, many of these changes will persist 

for hundreds or even thousands of years. 

 In the committee’s judgment, the risks associated with 

doing business as usual are a much greater concern than 

the risks associated with engaging in strong response 

efforts. 

4. Observed and Projected U.S. Regional Changes 

The NCA3 assessed the climate impacts in 8 regions of the 

United States, noting that changes in physical climate 

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, 

 

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

Press. 
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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%), 

and sea level rise of about a foot has led to an increase in 

coastal flooding. The 70% increase in the amount of rainfall 

falling in the 1% of the most intense events is a larger 

increase in extreme precipitation than experienced in any other 

US 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 
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after climate-related heavy precipitation events, and 1.6 

million people living within the 100-year coastal flood zone who 

are expected to experience more frequent floods due to sea level 

rise and tropical-storm induced storm-surge. The NCA also 

highlighted infrastructure vulnerable to inundation in coastal 

metropolitan areas, potential agricultural impacts from 

increased rain in the spring delaying planting or damaging crops 

or increased heat in the summer leading to decreased yields and 

increased water demand, and shifts in ecosystems leading to 

declines in iconic species in some regions, such as cod and 

lobster south of Cape Cod. 

In the Southeast, average annual temperature during the 

last century cycled between warm and cool periods. A warm peak 

occurred during the 1930s and 1940s followed by a cool period 

and temperatures then increased again from 1970 to the present 

by an average of 2°F. There have been increasing numbers of days 

above 95°F and nights above 75°F, and decreasing numbers of 

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. 
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The Southeast is exceptionally vulnerable to sea level 

rise, extreme heat events, hurricanes, and decreased water 

availability. Major consequences of further warming include 

significant increases in the number of hot days (95°F or above) 

and decreases in freezing events, as well as exacerbated groundlevel ozone in urban areas. Although projected warming for some 

parts of the region by the year 2100 are generally smaller than 

for other regions of the United States, projected warming for 

interior states of the region are larger than coastal regions by 

1°F to 2°F. Projections further suggest that globally there will 

be fewer tropical storms, but that they will be more intense, 

with more Category 4 and 5 storms. The NCA identified New 

Orleans, Miami, Tampa, Charleston, and Virginia Beach as being 

specific cities that are at risk due to sea level rise, with 

homes and infrastructure increasingly prone to flooding. 

Additional impacts of sea level rise are expected for coastal 

highways, wetlands, fresh water supplies, and energy 

infrastructure. 

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 
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across parts of the region. Snowpack in the Northwest is an 

important freshwater source for the region. More precipitation 

falling as rain instead of snow has reduced the snowpack, and 

warmer springs have corresponded to earlier snowpack melting and 

reduced streamflows during summer months. Drier conditions have 

increased the extent of wildfires in the region.

Average annual temperatures are projected to increase by 

3.3oF to 9.7oF by the end of the century (depending on future 

global greenhouse gas emissions), with the greatest warming is 

expected during the summer. Continued increases in global 

greenhouse gas emissions are projected to result in up to a 30% 

decrease in summer precipitation. Earlier snowpack melt and 

lower summer stream flows are expected by the end of the century 

and will affect drinking water supplies, agriculture, 

ecosystems, and hydropower production. Warmer waters are 

expected to increase disease and mortality in important fish 

species, including Chinook and sockeye salmon. Ocean 

acidification also threatens species such as oysters, with the 

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 
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conditions. Low lying coastal areas, including the cities of 

Seattle and Olympia, will experience heightened risks of sea 

level rise, erosion, seawater inundation and damage to 

infrastructure and coastal ecosystems. 

In Alaska, temperatures have changed faster than anywhere

else in the United States. Annual temperatures increased by 

about 3 °F in the past 60 years. Warming in the winter has been 

even greater, rising by an average of 6 °F. Arctic sea ice is 

thinning and shrinking in area, with the summer minimum ice 

extent now covering only half the area it did when satellite 

records began in 1979. Glaciers in Alaska are melting at some of 

the fastest rates on Earth. Permafrost soils are also warming 

and beginning to thaw. Drier conditions have contributed to more 

large wildfires in the last 10 years than in any previous decade 

since the 1940s, when recordkeeping began. Climate change 

impacts are harming the health, safety and livelihoods of Native 

Alaskan communities. 

By the end of this century, continued increases in 

greenhouse gas emissions are expected to increase temperatures 

by 10 to 12 °F in the northernmost parts of Alaska, by 8 to 10

°F in the interior, and by 6 to 8 °F across the rest of the 

state. These increases will exacerbate ongoing arctic sea ice 

loss, glacial melt, permafrost thaw and increased wildfire, and 
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threaten humans, ecosystems, and infrastructure. Precipitation 

is expected to increase to varying degrees across the state, 

however warmer air temperatures and a longer growing season are 

expected to result in drier conditions. Native Alaskans are 

expected to experience declines in economically, nutritionally, 

and culturally important wildlife and plant species. Health 

threats will also increase, including loss of clean water, 

saltwater intrusion, sewage contamination from thawing 

permafrost, and northward extension of diseases. Wildfires will 

increasingly pose threats to human health as a result of smoke 

and direct contact. Areas underlain by ice-rich permafrost 

across the state are likely to experience ground subsidence and 

extensive damage to infrastructure as the permafrost thaws. 

Important ecosystems will continue to be affected. Surface 

waters and wetlands that are drying provide breeding habitat for 

millions of waterfowl and shorebirds that winter in the lower 48 

states. Warmer ocean temperatures, acidification, and declining 

sea ice will contribute to changes in the location and 

availability if 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 
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is evidence that climate-change induced warming on top of recent 

drought has influenced tree mortality, wildfire frequency and 

area, and forest insect outbreaks. Sea levels have risen about 7 

or 8 inches in this region, contributing to inundation of 

Highway 101 and backup of seawater into sewage systems in the 

San Francisco area. 

Projections indicate that the Southwest will warm an 

additional 5.5 to 9.5 °F over the next century if emissions 

continue to increase. Winter snowpack in the Southwest is 

projected to decline (consistent with the record lows from this 

past winter), reducing the reliability of surface water supplies 

for cities, agriculture, cooling for power plants, and 

ecosystems. Sea level rise along the California coast will 

worsen coastal erosion, increase flooding risk for coastal 

highways, bridges, and low-lying airports, pose a threat to 

groundwater supplies in coastal cities such as Los Angeles, and 

increase vulnerability to floods for hundreds of thousands of 

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 
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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 

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 
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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 

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 
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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 

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 
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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% since the 

pre-industrial era and is projected to further increase by 37% 

to 50% 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 EGUs 

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 
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these amounts in the context of the U.S. Inventory of Greenhouse 

Gas Emissions and Sinks39 (the U.S. GHG Inventory). 

The EPA implements a separate program under 40 CFR Part 98 

called the Greenhouse Gas Reporting Program40 (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 information in Table 2 below, which presents total U.S. 

anthropogenic emissions and sinks41 of GHGs, including CO2

emissions, for the years 1990, 2005 and 2013. 

 

39 “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

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

http://www.epa.gov/ghgreporting/ghgdata/reportingdatasets.html

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

forests or underground or deep sea reservoirs of carbon dioxide.
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Table 2. U.S. GHG Emissions and Sinks by Sector (million metric 

tons carbon dioxide equivalent (MMT CO2 Eq.))42

SECTOR 1990 2005 2013 

Energy43 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

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.44 In 2013, fossil fuel combustion by the 

 

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

and Sinks: 1990 – 2013”, Report EPA 430-R-15-004, United States 

Environmental Protection Agency, April 15, 2015. 

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

43 The energy sector includes all greenhouse gases resulting from 

stationary and mobile energy activities, including fuel 

combustion and fugitive fuel emissions. 

44 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. 
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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.45 Table 3 

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

for years 1990, 2005 and 2013. 

Table 3. U.S. GHG Emissions from Generation of Electricity from 

Combustion of Fossil Fuels (MMT CO2)46

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

present comprehensive total U.S. greenhouse gas emissions and 

comply with commitments under the UNFCCC, the EPA collects 

detailed GHG emissions data from the largest emitting facilities 

 

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

. 

45 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 

46 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 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 4 below presents total GHG emissions in 2013 for 

the largest emitting industrial sectors as reported to the 

GHGRP. As shown in Table 3 and Table 4, 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 4. Direct GHG Emissions Reported to GHGRP by Largest 

Emitting Industrial Sectors (MMT CO2e)47

C. The Utility Power Sector 

1. A brief history 

 

47 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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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,48

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.49 During the early 1900s, smaller systems 

consolidated, allowing generation resources to be shared over 

larger areas. Interconnecting systems have reduced generation 

investment costs and improved reliability.50 Local and state 

governments initially regulated these growing electricity 

 

48 Regulatory Assistance Project (RAP), Electricity Regulation in 

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

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

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

Systems, IEEE Press, at 2-4 (2d ed. 2010). 

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

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

electric generation is extremely capital intensive, with 

generation potentially accounting for 65 percent of customer 

costs. If these costs can be spread to more customers, then 

this can reduce the amount that each individual customer pays. 

Federal Energy Regulatory Commission, Energy Primer: A Handbook 

of Energy Market Basics, at 38 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf. 
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systems with federal regulation coming later in response to 

public concerns about rising electricity costs.51 

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.52 During this time period, the U.S. 

Supreme Court found that state authority to regulate public 

utilities is limited, holding that the Commerce Clause does not 

allow state regulation to directly burden interstate commerce.53

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.54 The Supreme Court 

found that Rhode Island’s regulation was impermissible because 

 

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

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

52 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. 

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

5 (2002) (citation omitted).

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

Elec. Co., 273 U.S. 83 (1927).
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it imposed a "direct burden upon interstate commerce."55 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."56

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

rates for jurisdictional services are just, reasonable, and not 

unduly discriminatory or preferential.57 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.58 In 1938, Congress passed 

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

transmission or sale of natural gas in interstate commerce.59 The 

 

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

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

56 16 U.S.C. § 824(b)(1). 

57 16 U.S.C. § 824d. 

58 16 U.S.C. § 824e. 

59 Energy Information Administration, Natural Gas Act of 1938, 

available at 
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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.”60 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.61 These regulated 

monopolies are referred to as vertically-integrated utilities. 

As utilities built larger and larger electric generation 

plants, the cost per unit to generate electricity decreased.62 

However, these larger plants were extremely capital intensive 

for any one company to fund.63 Some neighboring utilities solved 

this issue by agreeing to share electricity reserves when 

 

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

ajorleg/ngact1938.html. 

60 Energy Information Administration, Natural Gas Act of 1938, 

available at 

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

ajorleg/ngact1938.html. 

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

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

62 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. 

63 Federal Energy Regulatory Commission, Energy Primer: A 

Handbook of Energy Market Basics, at 38 (2012), available at 

http://www.ferc.gov/market-oversight/guide/energy-primer.pdf.
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needed.64 These utilities began building larger transmission 

lines to deliver power in times when large generators 

experienced outages.65 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.66 Some power 

pools evolved into today’s regional transmission organizations 

(RTOs) and independent system operators (ISOs). 

In the past, electric utilities generally operated as state 

regulated monopolies, supplying end-use customers with 

generation, distribution, and transmission service.67 However, 

the ability of electric utilities to operate as natural 

monopolies came with consumer protection safeguards.68 “In 

 

64 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.

65 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.

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

Business, Enerdynamics, at 94 (2012). 

67 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). 

68 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. 
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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.”69 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.70 In the early 1990s, some states began to consider 

allowing competition to enter retail electric service.71 Federal 

and state efforts to allow competition in the electric utility 

industry have resulted in independent power producers (IPPs)72

 

69 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. 

70 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). 

71 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). 

72 These entities are also referred to as merchant generators. 
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producing approximately 37 percent of net generation in 2013.73

Electric utilities in some states remain vertically integrated 

without retail competition from IPPs. Today, there are over 

3,000 public, private, and cooperative utilities in the United 

States.74 These utilities include both investor-owned utilities75

and consumer-owned utilities.76 

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.77 These larger transmission 

 

73 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. 

74 Regulatory Assistance Project (RAP), Electricity Regulation in 

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

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

75 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. 

76 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. 

77 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 
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lines are able to access generation that is located more 

remotely, with transmission lines crossing many miles, including 

state borders.78 Closer to end users, electricity is transformed 

into a lower voltage that is transported across localized 

transmission lines to homes and businesses.79 Localized 

transmission lines make up the distribution system. These three 

components of the electricity system - generation, transmission, 

 

– in immediate synchronization with all other producers.” Id. at 

34. “At an early date, those providing electric power recognized 

that peak use for one system often occurred at a different time 

from peak use in other systems. They also recognized that 

equipment failures occurred at different times in various 

systems. Analyses showed significant economic benefits from 

interconnecting systems to provide mutual assistance; the 

investment required for generating capacity could be reduced and 

reliability could be improved. This lead [sic] to the 

development of local, then regional, and subsequently three 

transmission grids that covered the United States and parts of 

Canada.” Casazza, J. and Delea, F., Understanding Electric Power 

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

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

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

low cost of converting voltages in an alternating current (AC) 

system from one level to another, the bulk power system is 

predominantly an AC system rather than a direct current (DC) 

system. In an AC system, electricity cannot be controlled like a 

gas or liquid by utilizing a valve in a pipe. Instead, absent 

the presence of expensive control devices, electricity flows 

freely along all available paths, according to the laws of 

physics. U.S.-Canada Power System Outage Task Force, Final 

Report on the August 14, 2003 Blackout in the United States and 

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

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

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

the Competitive Era, Public Utility Reports, Inc., at 5 (1997). 
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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.80 Electricity from a diverse set of 

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

renewables is distributed over high-voltage transmission lines 

divided across the continental United States into three 

synchronous interconnections – the Eastern Interconnection, 

Western Interconnection, and the Texas Interconnection.81 These 

 

80 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. 

81 Regulatory Assistance Project (RAP), Electricity Regulation in 

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

http://www.raponline.org/document/download/id/645. 
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three synchronous systems each act like a single machine.82

Diverse resources generate electricity that is transmitted and 

distributed through a complex system of interconnected 

components to industrial, business, and residential consumers. 

Unlike other industries where sources make operational decisions 

independently, the utility power sector is unique in that 

electricity system resources operate in a complex, 

interconnected grid system that is physically interconnected and 

operated on an integrated basis across large regions. 

Additionally, a federal, state, and local regulatory network 

oversees policies and practices that are applied to how the 

system is designed and operates. In this interconnected system, 

system operators must ensure that the amount of electricity 

available is precisely matched with the amount needed in real 

time. System operators have a number of resources potentially 

available to meet electricity demand, including electricity 

generated by electric generation units such as coal, nuclear, 

renewables, and natural gas, as well as demand-side resources83, 

 

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

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

83 “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 
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such as energy efficiency84 and demand response.85 Generation, 

outages, and transmission changes in one part of the synchronous 

grid can affect the entire interconnected grid.86 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.”87 The U.S. Supreme Court has 

similarly recognized the interconnected nature of the 

electricity grid.88 

 

Use of Demand-Side Resources, at 9 (2013), available at

www.raponline.org. 

84 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. 

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

demand-side resources from their normal consumption patterns in 

response to changes in the price of electricity over time, or to 

incentive payments designed to induce lower electricity use at 

times of high wholesale market prices or when system reliability 

is jeopardized.” Federal Energy Regulatory Commission, Reports 

on Demand Response & Advanced Metering, (Dec. 23, 2014), 

available at http://www.ferc.gov/industries/electric/indusact/demand-response/dem-res-adv-metering.asp. 

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

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

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

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

88

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 
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Today, federal, state, and local entities regulate 

electricity providers.89 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.”90 

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 

 

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)). 

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

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

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

Systems, IEEE Press, at 213 (2d ed. 2010).
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electricity are privately owned.91 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.92 “The role of the 

regulator now includes support for the development of open and 

fair wholesale electric markets, ensuring equal access to the 

transmission system and more hands-on oversight and control of 

the planning and operating rules for the industry.”93 

2. Electric system dispatch 

System operators typically dispatch the electric system 

through a process known as economic dispatch. Economic dispatch 

has been defined 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.”94 Electricity demand varies across 

geography and time in response to numerous conditions, such that 

electric generators are constantly responding to changes in the 

 

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

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

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

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

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

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

94 Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594 

(2005), section 1234(b). 
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most reliable and cost-effective manner possible. The cost of 

operating electric generation varies based on a number of 

factors, such as fuel and generator efficiency. 

 The decision to dispatch any particular electric generator 

depends upon the relative operating cost, or marginal cost, of 

generating electricity to meet the last increment of electric 

demand. Fuel is one common variable cost – especially for 

fossil-fueled generators. Coal plants will often have 

considerable variable costs associated with running pollution 

controls.95 Renewables, hydroelectric, and nuclear have little to 

no variable costs. In an economic dispatch system, units with 

higher variable costs, such as fossil fuel-fired generators, 

generally are the first generation to be displaced by lower 

variable cost generation, like RE. 

 In states with cost-of-service regulation of verticallyintegrated utilities, the utilities themselves form the 

balancing authorities who determine dispatch based upon the 

lowest marginal cost. These utilities sometimes arrange to buy 

and sell electricity with other balancing authorities. RTOs and 

ISOs are generally responsible for dispatch in non-vertically 

integrated states. They coordinate, control, and monitor 

 

95 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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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.96 In 1965, the northeastern U.S. and southeastern 

Ontario, Canada experienced the largest power blackout to date, 

impacting 30 million people.97 In response to the 1965 blackout 

and a Federal Power Commission recommendation,98 industry 

developed the National Electric Reliability Council (NERC) and 

nine reliability councils. The organization later became known 

 

96 North American Electric Reliability Corporation, History of 

NERC, at 1 (2013), available at

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

97 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. 

98 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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as the North American Electric Reliability Council to recognize 

Canada’s participation.99 

In August 2003, North America experienced its worst 

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

and Ontario, Canada.100 This blackout was massive in scale 

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

megawatts of electric load.101 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.102

 

99 North American Electric Reliability Corporation, History of 

NERC, at 2 (2013), available at

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

. The North American Electric Reliability Council became the 

North American Electric Reliability Corporation in 2007. Id. at 

4. 

100 North American Electric Reliability Corporation, History of 

NERC, at 3 (2013), available at

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

101 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. 

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

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

Causes and Recommendations, at 2 (Apr. 2004), available at
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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.103 In 2006, the Federal Energy Regulatory 

Commission (FERC) certified NERC as the ERO.104 “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.”105

 

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

103 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)). 

104 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). 

105 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 United States, Canada, and part of Mexico are divided 

up into eight reliability regional entities.106 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).107 Regional entity 

members come from all segments of the electric industry.108 NERC 

delegates authority, with FERC approval, to these regional 

entities to enforce reliability standards, both national and 

regional reliability standards, and engage in other standardsrelated duties delegated to them by NERC.109 NERC ensures that 

 

106 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. 

107 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. 

108 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. 

109 North American Electric Reliability Corporation, Frequently 

Asked Questions, at 5 (2013), available at 

http://www.nerc.com/AboutNERC/Documents/NERC%20FAQs%20AUG13.pdf. 
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there is a consistency of application of delegated functions 

with appropriate regional flexibility.110 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/RTOs111, and other planning 

 

For example, a regional entity may propose reliability 

standards, including regional variances or regional reliability 

standards required to maintain and enhance electric service 

reliability, adequacy, and security in the region. See, e.g.,

Amended and Restated Delegation Agreement Between North American 

Reliability Corporation and Midwest Reliability Organization, 

Bylaws of the Midwest Reliability Organization, Inc., Section 

2.2 (2012), available at

http://www.nerc.com/FilingsOrders/us/Regional%20Delegation%20Agr

eements%20DL/MRO_RDA_Effective_20130612.pdf. 

110 North American Electric Reliability Corporation, Frequently 

Asked Questions, at 5 (2013), available at 

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

111 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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authorities also consider the reliability of the electric 

system. There are numerous remedies that can be utilized to 

solve a potential reliability problem, including long-term 

planning, transmission system upgrades, installation of new 

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., with smaller amounts provided by other 

types of generation including nuclear, and renewables such as 

wind, solar, and hydroelectric power. Coal provided the largest 

percentage of the fossil fuel generation.112 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.113 In 2013, fossil fuels supplied 67 percent of U.S. 

 

112 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). 

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

Electricity Net Generation: Electric Power Sector” data from 

Monthly Energy Review May 2015, release data April 25, 2014, 

available at
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electricity,114 but the amount of renewable generation capacity 

continued to grow.115 From 2007 to 2014, use of lower- and zerocarbon energy sources such as wind and solar grew, while other 

major energy sources such as coal and petroleum generally 

experienced declines.116 Renewable electricity generation, 

including from large hydro-electric projects, grew from 8 

percent to 13 percent over that time period.117 Between 2000 and 

2013, approximately 90 percent of new power generation capacity 

 

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

visited May 26, 2015). 

114 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). 

115 Based on Table 6.3 (New Utility Scale Generating Units by 

Operating Company, Plant, Month, and Year) of the U.S. Energy 

Information Administration (EIA) Electric Power Monthly, data 

for December 2013, for the following renewable energy sources: 

solar, wind, hydro, geothermal, landfill gas, and biomass. 

Available at: http:// 

www.eia.gov/electricity/monthly/epm_table_grapher.cfm?t=epmt_6_0

3. 

116 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).

117 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). 
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built in the U.S. came in the form of natural gas or renewable 

energy facilities.118 In 2015, the U.S. Energy Information 

Administration (EIA) projected the need for 28.4 GW of 

additional base load or intermediate load generation capacity 

through 2020.119 The vast majority of this new electric capacity 

(20.4 GW) is already under development (under construction or in 

advanced planning), with approximately 0.7 GW of new coal-fired 

capacity, 5.5 GW of new nuclear capacity, and 14.2 GW of new 

NGCC capacity already in development. 

While the change in the resource mix has accelerated in 

recent years, wind, solar, other renewables, and energy 

efficiency resources have been reliably participating in the 

electric sector for a number of years. This rapid development of 

non-fossil fuel resources is occurring as much of the existing 

power generation fleet in the U.S. is aging and in need of 

modernization and replacement. For example, the average age of 

U.S. coal steam units in 2015 is 45.120 In its 2013 Report Card 

 

118 Energy Information Administration, Electricity: Form EIA-860 

detailed data (Feb. 17, 2015), available at

http://www.eia.gov/electricity/data/eia860/. 

119 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.

120 We calculated the average age of coal steam units based on 

the NEEDS inventory (a “snapshot” of the sector in 2016), and 
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for America’s Infrastructure, the American Society for Civil 

Engineers noted that “America relies on an aging electrical grid 

and pipeline distribution systems, some of which originated in 

the 1880s.”121 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.”122 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 

 

adding back units with actual/planned retirements in 2012-2016. 

See http://www.epa.gov/airmarkets/documents/ipm/needs_v514.xlsx. 

121 American Society for Civil Engineers, 2013 Report Card for 

America’s Infrastructure (2013), available at

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

122 American Society for Civil Engineers, 2013 Report Card for 

America’s Infrastructure (2013), available at

http://www.infrastructurereportcard.org/energy/. 
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net generation increased by approximately 32 percent between 

2005 and 2014.123 In 2014, natural gas accounted for 

approximately 27 percent of net generation.124 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 2040.125 

Renewable sources of electric generation also have a 

history of meeting electricity demand in the United States and 

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

of energy crises provided the impetus for renewable energy 

development in the early 1970s. The OPEC oil embargo in 1973 and 

oil crisis of 1979 caused oil price spikes, more frequent energy 

shortages, and significantly affected the national and global 

 

123 U.S. Energy Information Administration (EIA), Electric Power 

Monthly: Table 1.1 Net Generation by Energy Source: Total (All 

Sectors), 2005-February 2015 (2015), available at

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

pmt_1_1 (last visited May 26, 2015). 

124 Id. 

125 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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economy. In 1978, partly in response to fuel security concerns, 

Congress passed the Public Utilities Regulatory Policies Act 

(PURPA) which required local electric utilities to buy power 

from qualifying facilities (QFs).126 QFs were either cogeneration 

facilities127 or small generation resources that use renewables 

such as wind, solar, biomass, geothermal, or hydroelectric power 

as their primary fuels.128 Through PURPA, Congress supported the 

development of more renewable energy generation in the U.S. 

States have also taken a significant lead in requiring the 

development of renewable resources. In particular, a number of 

states have adopted renewable portfolio standards (RPS). As of 

2013, 29 states and the District of Columbia have enforceable 

RPS or similar laws.129 

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. 

 

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

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

127 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). 

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

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

129 U.S. Energy Information Administration (EIA), Annual Energy 

Outlook 2014 with Projections to 2040, at LR-5 (2014), available 

at http://www.eia.gov/forecasts/aeo/pdf/0383(2014).pdf (last 

visited May 26, 2015). 
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electricity.130 Total non-hydro RE capacity was approximately 

13,000 megawatts (MW) in 1998. In 2013, total capacity was over 

five times higher with 80,000 MW of non-hydro RE capacity.131 In 

particular, there has been substantial growth in the wind and 

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

energy has tripled and solar capacity has grown twenty-fold.132 

 The market for RE is projected to grow to $460 billion per 

year by 2030. RE growth is further encouraged by the significant 

amount of existing natural resources that can support RE 

production (solar, water, wind, and geothermal) in the United 

States. 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.133 In the 

reference case, RE generation increases by more than 70 percent 

from 2013 to 2040 and accounts for over one-third of new 

 

130 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at ES-6 (2014). 

131 Barbose, G., Renewables Portfolio Standards in the United 

States: A Status Update, Presentation at State-Federal RPS 

Collaborative National Summit on RPS (2013), available at

http://emp.lbl.gov/sites/all/files/rps_summit_nov_2013.pdf (last 

visited May 27, 2015). 

132 Energy Information Administration, Monthly Energy Review, May 

2015, Table 7.2b, available at

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

133

 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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generation capacity.134 Rapid growth in RE generation is 

projected to continue as costs of RE generation fall relative to 

the costs of other generation technologies. 

Price pressures caused by oil embargoes in the 1970s also 

brought the issues of conservation and energy efficiency to the 

forefront of U.S. energy policy.135 This trend continued in the 

early 1990s. Energy efficiency has been utilized to meet energy 

demand to varying levels since that time. As of April 2014, 25 

states136 have “enacted long-term (3+ years), binding energy 

 

134 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).

135 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. 

136 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 
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savings targets, or energy efficiency resource standards 

(EERS).”137 Funding for energy efficiency programs has grown 

rapidly in recent years, with budgets for electric efficiency 

programs totaling $5.9 billion in 2012.138 

 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. 

D. Congress’ Awareness of Climatic Change139 

 As early as 1970, Congress learned that ongoing pollution, 

including from manmade carbon dioxide, could “threaten 

irreversible atmospheric and climatic changes.”140 Likewise, 

 

pending), Florida (programs funded at levels far below what is 

necessary to meet targets), Utah, or Virginia (voluntary 

standards) in its calculation. 

137 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. 

138 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. 

139 The following discussion is not meant to be exhaustive; 

indeed, there are many other instances, including outside the 

context of the CAA, where Congress discussed climate change. 

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

Legis. Hist. at 349.
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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.”141 In fact, the CEQ’s First Annual Report, which 

was transmitted to Congress, devoted an entire chapter to “Man’s 

Inadvertent Modification of Weather and Climate.”142 Moreover, 

Charles Johnson, Jr., Administrator of the Consumer Protection 

and Environmental Health Service even 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.”143 Administrator Johnson explained that 

the Nixon Administration was “concerned ... that neither of these 

 

141 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.”). 

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

the Council on Environmental Quality,” p. 93-104 (Aug. 1970) 

143 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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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.”144 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.”145

Climatic effects continued to gain Congressional attention 

by the 1977 CAA Amendments. However, scientific studies remained 

inconclusive as to warming or cooling trends.146 In deference to 

 

144 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. 

145 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. 

146 For instance, while scientists, such as Stephen Schneider of 

the National Center for Atmospheric Research, testified that 

“manmade pollutants will affect the climate,” they believed that 

we would “see a general cooling of the Earth’s atmosphere.” Rep. 

Scheuer, H. Debates on H.R. 10498 (Sept. 15, 1976), 1977 CAA 

Legis. Hist. at 6477. Additionally, the Department of 

Transportation’s climatic impact assessment program and the 

Climatic Impact Committee of the National Research Council, 

National Academies of Science and Engineering both reported that 

“warming or cooling” could occur. Id. at 6476. See also Sen. 

Bumpers, Sen. Debates on S. 3219 (August 3, 1976), 1977 CAA 

Legis. Hist. at 5368 (inserting “Summary of Statements Received 

[in the Subcommittee on the Environment and the Atmosphere] from 

Professional Societies for the Hearings on Effects of Chronic 

Pollution” into the record, which noted that “there is near 
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that uncertainty, and as part of the 1977 CAA Amendments, 

Congress ordered the National Oceanic and Atmospheric 

Administration to research and monitor the stratosphere “for the 

purpose of early detection of changes in the stratosphere and 

climatic effects of such changes.”147 

Finally, in the 1990 CAA Amendments, Congress specifically 

required the EPA to collect data on carbon dioxide emissions 

from all sources subject to the newly enacted operating permit 

program.148 The provision recognizes that “[s]cientists have 

disagreed about the scope and magnitude of global climate change 

from manmade air pollution, and much of that disagreement stems 

from lack of necessary data to assess the impact these emissions 

may have on the Earth’s climate.”149 Accordingly, the provision 

“helps fill this information gap.”150 It was designed to “give us 

a head start if and when we need to take steps to reduce our 

carbon dioxide emissions.”151

 

unamity [sic] that carbon dioxide concentrations in the 

atmosphere are increasing rapidly.”). 

147 “Clean Air Act Amendments of 1977,” § 125, 91 Stat. at 728. 

148 “Clean Air Act Amendments of 1990,” § 820, 104 Stat. at 2699. 

149 Rep. Moorhead, H. Debate on H.R. 3030 (May 21, 1990), 1990 

CAA Legis. Hist. at 2612. 

150 Rep. Moorhead, H. Debate on H.R. 3030 (May 21, 1990), 1990 

CAA Legis. Hist. at 2612. 

151 Rep. Moorhead, H. Debate on H.R. 3030 (May 21, 1990), 1990 

CAA Legis. Hist. at 2613. 
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Congress also recognized that certain tools were 

particularly helpful in addressing climate change. For instance, 

the Senate report discussing Title IV noted that “[e]nergy 

efficiency is a crucial tool for controlling the emissions of 

carbon dioxide, the gas chiefly responsible for the 

intensification of the atmospheric ‘greenhouse effect.’”152

Similarly, “renewables not only significantly curtail sulfur 

dioxide emissions, but they emit little or no nitrogen oxides 

and carbon dioxide”.153

E. International Agreements and Actions 

In this final rule, the United States is taking action to 

limit GHGs from one of its largest emission sources. Climate 

change is a global problem, and the United States is not alone 

in taking action to address it. The United Nations Framework 

Convention on Climate Change (UNFCCC)154 is the international 

treaty under which countries (called “Parties”) cooperatively 

consider what can be done to limit anthropogenic climate 

change155 and adapt to climate change impacts. Currently, there 

 

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

Legis. Hist. at 8662. 

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

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

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

155 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 
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Page 148 of 1275

are 195 Parties to the UNFCCC, including the United States. The 

Conference of the Parties (COP) meets annually and is currently 

considering commitments countries can make to limit emissions 

after 2020. The 2015 COP will be in Paris, and countries will 

announce their post-2020 commitments there or beforehand. In 

April 2015, the United States announced its commitment to reduce 

GHG emissions 26-28% below 2005 levels by 2025.156

 As Parties to both the UNFCCC and the Kyoto Protocol157, the 

European Union (EU) and member countries have taken aggressive 

action to reduce GHG emissions.158 EU initiatives to reduce 

greenhouse gas emissions include the EU Emissions Trading 

System, legislation to increase the adoption of renewable energy 

sources, strengthened energy efficiency targets, vehicle 

 

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 

156 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

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

158 http://ec.europa.eu/clima/policies/brief/eu/index_en.htm 
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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% reduction in GHG emissions from 1990 levels by 

2020, an increase of 20% in the share of energy consumption 

produced by renewable resources, and a 20% improvement in energy 

efficiency. In March 2015, the EU announced its commitment to 

reduce domestic GHG emissions by at least 40% from 1990 levels 

by 2030.

 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% of its 

emissions of greenhouse gases and short lived climate pollutants 

(below business as usual) for the year 2030. This commitment 

implies a 22 percent reduction of GHG emissions and a 51 percent 

reduction of black carbon emissions. 

Brazil has reduced its net CO2 emissions more than any other 

country through a historic effort to slow forest loss. The 
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deforestation rate in Brazil in 2014 was roughly 75% below the 

average for 1996 to 2005.159   

This final rule demonstrates to other countries that the 

United States is taking action to limit GHG emissions from its 

largest emission sources, in line with our international 

commitments. The impact of GHGs is global, and U.S. action to 

reduce GHG emissions complements and encourages ongoing programs 

and efforts in other countries.

F. 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 

public health or welfare.”160 The EPA has listed more than 60 

stationary source categories under this provision.161 Once the 

EPA lists a source category, the EPA must, under CAA section 

111(b)(1)(B), establish “standards of performance” for emissions 

 

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

160 CAA §111(b)(1)(A). 

161 See 40 CFR 60 subparts Cb – OOOO. 
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of air pollutants from new sources in the source categories.162

These standards are known as new source performance standards 

(NSPS), and they are national requirements that apply directly 

to the sources subject to them. 

When the EPA establishes NSPS for new sources in a 

particular source category, the EPA is also required, under CAA 

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

plans regulating existing sources in that source category for 

any air pollutant that, in general, is not regulated under the 

CAA section 109 requirements for the NAAQS or regulated under 

the CAA section 112 requirements for hazardous air pollutants 

(HAP). CAA section 111(d)’s mechanism for regulating existing 

sources differs from the one that CAA section 111(b) provides 

for new sources because CAA section 111(d) contemplates states 

submitting plans that establish “standards of performance” for 

the affected sources and that contain other measures to 

implement and enforce those standards. 

“Standards of performance” are defined under CAA section 

111(a)(1) as standards for emissions that reflect the emission 

limitation achievable from the “best system of emission 

reduction,” considering costs and other factors, that 

“the Administrator determines has been adequately demonstrated.” 

 

162 CAA §111(b)(1)(B), 111(a)(1). 
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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.”163 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.164 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, 

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 

 

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

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

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 
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in its area of Indian country165 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. 

Although the EPA believes the current emission guidelines 

are sufficiently inclusive, the EPA is amending the 

applicability provision of the emission guidelines slightly to 

avoid any doubt that the guidelines apply to U.S. territories 

 

165 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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with affected EGUs and to any Indian tribe that has been 

approved by the EPA as eligible to develop and implement a plan. 

In these final emission guidelines, the term “state” 

encompasses the 50 states and the District of Columbia, U.S. 

territories, and any Indian tribe that has been approved by the 

EPA pursuant to 40 CFR 49.9 as to develop and implement a CAA 

section 111(d) plan. 

The EPA issued regulations implementing CAA section 111(d) 

in 1975,166 and has revised them in the years since.167 (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.168 The implementing regulations also establish 

timetables for state and EPA action: states must submit state 

 

166 “State Plans for the Control of Certain Pollutants from 

Existing Facilities,” 40 FR 53,340 (Nov. 17, 1975). 

167 The most recent amendment was in 77 Fed. Reg. 9304 (Feb. 16, 

2012). 

168 40 CFR 60.22. In the 1975 rulemaking, the EPA explained that 

it used the term “emissions guidelines” – instead of emissions 

limitations – to make clear that guidelines would not be binding 

requirements applicable to the sources, but instead are 

“criteria for judging the adequacy of State plans.” 40 Fed. Reg. 

at 53,343. 
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plans within 9 months of the EPA’s issuance of the guidelines,169

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

months of the due date for those plans,170 although the EPA has 

authority to extend those deadlines.171 In this rulemaking, the 

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)).172 In addition, the agency has 

regulated additional pollutants under CAA section 111(d) in 

 

169 40 CFR 60.23(a)(1). 

170 40 CFR 60.27(b). 

171 See 40 CFR 60.27(a). 

172 See “Phosphate Fertilizer Plants; Final Guideline Document 

Availability,” 42 Fed. Reg. 12,022 (Mar. 1, 1977); “Standards of 

Performance for New Stationary Sources; Emission Guideline for 

Sulfuric Acid Mist,” 42 Fed. Reg. 55,796 (Oct. 18, 1977); “Kraft 

Pulp Mills, Notice of Availability of Final Guideline Document,” 

44 Fed. Reg. 29,828 (May 22, 1979); “Primary Aluminum Plants; 

Availability of Final Guideline Document,” 45 Fed. Reg. 26,294 

(Apr. 17, 1980); “Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing Sources: 

Municipal Solid Waste Landfills, Final Rule,” 61 Fed. Reg. 9905 

(Mar. 12, 1996). 
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conjunction with CAA section 129.173 The agency has not 

previously regulated CO2 or any other greenhouse gas under CAA 

section 111(d). 

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

necessarily geared toward the pollutants and industries 

regulated. Similarly, in this rulemaking, in defining CAA 

section 111(d) emission guidelines for the states and 

determining the BSER, the EPA believes that taking into account 

the particular characteristics of carbon pollution, the 

interconnected nature of the power sector and the manner in 

which EGUs are currently operated is warranted. Specifically, 

the operators themselves treat increments of generation as 

interchangeable between and among sources in a way that creates 

options for relying on varying utilization levels, lowering 

carbon generation, and reducing demand as components of the 

overall method for reducing CO2 emissions. Doing so results in a 

broader, forward-thinking approach to the design of programs to 

yield critical CO2 reductions that improve the overall power 

system by lowering the carbon intensity of power generation, 

while offering continued reliability and cost-effectiveness. 

 

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

Sources and Emission Guidelines for Existing Sources: Sewage 

Sludge Incineration Units, Final Rule,” 76 Fed. Reg. 15,372 

(Mar. 21, 2011). 
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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.174

In this action, the EPA is promulgating emission guidelines 

for states, U.S. territories, and tribes to follow in developing 

their CAA section 111(d) plans to reduce emissions of CO2 from 

the utility power sector. 

G. 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.”175 The Air Quality Act—which expanded 

federal air pollution control efforts after the enactment of the 

Clean Air Act of 1963—prioritized the adoption of ambient air 

standards but failed to target stationary sources of air 

 

174 See “Phosphate Fertilizer Plants; Final Guideline Document 

Availability,” 42 Fed. Reg. 12,022 (Mar. 1, 1977); “Standards of 

Performance for New Stationary Sources; Emission Guideline for 

Sulfuric Acid Mist,” 42 Fed. Reg. 55,796 (Oct. 18, 1977); “Kraft 

Pulp Mills, Notice of Availability of Final Guideline Document,” 

44 Fed. Reg. 29,828 (May 22, 1979); “Primary Aluminum Plants; 

Availability of Final Guideline Document,” 45 Fed. Reg. 26,294 

(Apr. 17, 1980); “Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing Sources: 

Municipal Solid Waste Landfills, Final Rule,” 61 Fed. Reg. 9905 

(Mar. 12, 1996). 

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

Legis. Hist. at 224. 
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pollution. As a result, “[c]ities up and down the east coast 

were living under clouds of smoke and daily air pollution 

alerts.”176 In fact, “[o]ver 200 million tons of contaminants ... 

spilled into the air” each year.177 The 1970 CAA Amendments were 

designed to face this crisis “with urgency and in candor.”178 

For the most part, Congress gave EPA and the states 

flexible tools to implement the CAA. This is best exhibited by 

the newly enacted programs regulating stationary sources. For 

these sources, Congress crafted a three-legged regime upon which 

the regulation of stationary sources was intended to sit. 

The first prong—CAA sections 107-110—addressed what are 

commonly referred to as criteria pollutants, “the presence of 

which in the ambient air results from numerous or diverse mobile 

or stationary sources” and are determined to have “an adverse 

effect on public health or welfare”.179 Under these provisions, 

 

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

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

177 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. 

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

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

179 “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 
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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.180

The second prong—CAA section 111—addressed pollutants on a 

source category-wide basis. For new sources in a listed source 

category, CAA section 111(b) established “standards of 

performance” for pollutants which “cause[] or contribute to the 

endangerment of public health or welfare.”181 For existing 

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

procedures for the establishment of federally enforceable 

“emission standards” of any pollutant not otherwise controlled 

under the CAA’s SIP provisions or CAA section 112. 

Lastly, the third prong—CAA section 112—addressed hazardous 

air pollutants through the establishment of national “emission 

standards” at a level which “provides an ample margin of safety 

 

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). 180 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1680. 181 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1684. 
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to protect the public health”.182 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.183

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 112.184 That said, states, including Texas and New 

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

moving rapidly enough.185 Accordingly, the 1977 CAA Amendments 

were designed to “provide a greater role for the [s]tates in 

standards setting under the [CAA],” “protect [s]tates from 

‘environmental blackmail’ as they attempt to regulate mobile and 

competitive industries,” and lastly “provide a check on the 

Administrator’s inaction or failure to control emissions 

adequately.”186

At bottom, CAA section 111 rests on the definition of a 

standard of performance under CAA section 111(a)(1), which reads 

 

182 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1685. 183 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1685. 184 H.R. Rep. No. 95-294, at 194 (May 12, 1977). 185 H.R. Rep. No. 95-294, at 194 (May 12, 1977). 186 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 
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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.187

Despite significant changes to this definition in 1977, Congress 

reversed course in 1990 and largely reinstated the original 

definition.188 As presently defined, the term applies to the 

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

and (d).189 

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 

 

187 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1683. 188 “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). 

189 As CAA section 111(d) was originally adopted, state plans 

would have established “emission standards” instead of 

“standards of performance.” This distinction was later abandoned 

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

and (d). 
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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 non-hazardous 

pollutants] to the fullest extent compatible with the available 

technology and economic feasibility”.190 The House also proposed 

to prohibit the construction or operation of new sources of 

“extremely hazardous” pollutants.191 The Senate bill, on the 

other hand, authorized “Federal standards of performance,” which 

would “reflect the greatest degree of emission control which the 

Secretary [later, the Administrator] determines to be achievable 

through application of the latest available control technology, 

processes, operating methods, or other alternatives.”192 The 

 

190 H.R. 17255, 91st Cong. § 5 (1970). 191 H.R. 17255, 91st Cong. § 5 (1970). 192 S. 4358, 91st Cong. § 6 (1970) (emphasis added). The breadth 

of the Senate bill is further emphasized in the conference 

report, which explains that a standard of performance “refers to 

the degree of emission control which can be achieved through 

process changes, operation changes, direct emission control, or 

other methods” and also includes “other means of preventing or 

controlling air pollution.” S. Rep. No. 91-1196, at 15-16 (Sept. 

17, 1970). 
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Senate also would have authorized “national emission standards” 

for hazardous air pollution and other “selected air pollution 

agents.”193

After conference, CAA section 111 emerged as one of the 

CAA’s three programs for regulating stationary sources. In 

defining the newly formed “standards of performance,” Congress 

merged the various “means of preventing and controlling air 

pollution” under the Senate bill with the consideration of costs 

that was central to the House bill into the BSER. At the time, 

however, this definition only applied to new sources under CAA 

section 111(b). 

To regulate existing sources, Congress collapsed section 

114 of the Senate bill into CAA section 111(d).194 Section 114 of 

the Senate bill established emission standards for “selected air 

pollution agents,” and was intended to bridge the gap between 

criteria pollutants and hazardous air pollutants. As proposed, 

the Senate identified fourteen substances for regulation under 

section 114 and only four substances for regulation under Senate 

bill 4358, section 115, the predecessor of CAA section 112.195 

 

193 S. 4358, 91st Cong. § 6 (1970). 194 The House bill did not provide for the direct regulation of 

existing sources. 

195 See S. Rep. No. 91-1196, at 18 and 20 (Sept. 17, 1970). 
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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.”196 

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 112.197 That said, under the 

newly enacted “ambient air quality and emission standards” 

sections, Congress directed the EPA to provide states with 

information “on air pollution control techniques,” including 

data on “available technology and alternative methods of 

prevention and control of air pollution” and on “alternative 

fuels, processes, and operating methods which will result in 

elimination or significant reduction of emissions.”198 Similarly, 

the Administrator would “issue information on pollution control 

 

196 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). 

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

1706. 

198 “Clean Air Act Amendments of 1970,” § 4, 84 Stat. at 1679. 
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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 1971.199 The first category listed was 

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

and finalized standards for particulate matter, sulfur dioxide, 

and nitrogen oxides.200 

Several years later, the EPA proposed its implementing 

regulations for CAA section 111(d).201 These regulations were 

finalized in November 1975, and provided for the publication of 

emission guidelines.202 The first emissions guidelines were 

proposed in May 1976 and finalized in March 1977.203

 

199 “Standards of Performance for New Stationary Sources: Proposed 

Standards for Five Categories,” 36 F.R. 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). 

200 36 F.R. at 15704-706; and “Standards of Performance for New 

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

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

F.R. 36102 (Oct. 7, 1974). 

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

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

203 See “Phosphate Fertilizer Plants; Draft Guideline Document; 

Availability,” 41 F.R. 19585(May 12, 1976); and “Phosphate 
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Despite these first steps taken under CAA sections 111(b) 

and (d), Congress revisited the CAA in 1977 to address growing 

concerns with the nation’s response to the 1973 oil embargo 

(noted above), to respond to new environmental problems such as 

stratospheric ozone depletion, and to resolve other issues 

associated with implementing the 1970 CAA Amendments.204 Most 

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

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

“even more urgent.”205 Thus, to curb the projected surge in air 

emissions, Congress enacted several new provisions to the CAA. 

 

Fertilizer Plants; Final Guideline Document Availability,” 42 

F.R. 12022 (Mar. 1, 1977) 

204 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). 

205 See Statement of EPA Administrator Costle, S. Hearings on S. 

272, S. 273, S. 977, and S. 1469 (Apr. 5, 7, May 25, June 24 and 

30, 1977), 1977 CAA Legis. Hist. at 3532. 
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These new provisions include the prevention of significant 

deterioration (PSD) program, visibility protections, and 

requirements for nonattainment areas.206 

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.207

The 1977 definition for a standard of performance required 

“all new sources to meet emission standards based on the 

reductions achievable through the use of the ‘best technological 

system of continuous emission reduction.’”208 For fossil-fuel 

 

206 See “Clean Air Act Amendments of 1977,” Pub. L. 95-95, §§ 127-

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

207 “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 697. 208 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 
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fired stationary sources, Congress further required a percentage 

reduction in emissions from the use of fuels.209 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.”210

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)”.211 This was intended to 

distinguish existing source standards from new source standards, 

for which “the requirement for [the BSER] has been more narrowly 

redefined as best technological system of continuous emission 

reduction.”212 Additionally, Congress clarified that states could 

 

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). 

209 “Clean Air Act Amendments of 1977,” § 109, 91 Stat. at 700. 210 “New Stationary Sources Performance Standards; Electric 

Utility Steam Generating Units,” 44 F.R. 33580, 33581-82 (June 

11, 1979). 

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

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

564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353. 
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consider “the remaining useful life” of a source when applying a 

standard of performance to a particular existing source.213 

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.”214 Indeed, in 1988, 

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

enough and much remains to be done.’”215 This time, with the 1990 

CAA Amendments, Congress substantially overhauled the CAA. In 

particular, Congress again added to the NAAQS program, 

completely revised CAA section 112, added a new title to target 

existing fossil fuel-fired stationary sources and address 

growing concerns with acid rain, imported an operating permit 

modeled off the Clean Water Act, and established a phase out of 

certain ozone depleting substances. 

All told, however, there was minimal debate on changes to 

CAA section 111. In fact, the only discussion centered on the 

repeal of the percentage reduction requirement, which became 

seen as unduly restrictive. Accordingly, Congress reverted the 

 

213 This concept was already reflected in the EPA’s CAA section 

111(d) implementing regulations under 40 C.F.R. § 60.24(f). See 

40 F.R. 53340, 53347 (Nov. 17, 1975). 

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

215 H.R. Rep. No. 101-490, at 144 (May 17, 1990). 
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definition of “standard of performance” to the definition agreed 

to in the 1970 CAA Amendments, but retained the requirement to 

consider nonair quality environmental impacts and energy 

requirements added in 1977.216 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.217

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.218

H. Clean Power Plan Proposal and Supplemental Proposal 

On June 18, 2014, the EPA proposed emission guidelines for 

states to follow in developing plans to address greenhouse gas 

(GHG) emissions from existing fossil fuel-fired electric 

generating units (EGUs). Specifically, the EPA proposed ratebased goals for carbon dioxide (CO2) emissions for each state 

with existing fossil fuel-fired EGUs, as well as guidelines for 

plans to achieve those goals. On November 4, 2014, the EPA 

published a supplemental proposal that proposed emission rate-

 

216 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. 

217 “Clean Air Act Amendments of 1990,” § 403, 104 Stat. at 2631. 218 “Clean Air Act Amendments of 1990,” § 301, 104 Stat. at 2631. 
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based goals for CO2 emissions for U.S. territories and areas of 

Indian country with existing fossil fuel-fired EGUs. In the 

supplemental proposal, the EPA also solicited comment on 

authorizing jurisdictions (including any states, territories and 

areas of Indian country) without existing fossil fuel-fired EGUs 

subject to the proposed emission guidelines to partner with 

jurisdictions (including any states) that do have existing 

fossil fuel-fired EGUs subject to the proposed emission 

guidelines in developing multi-jurisdictional plans. The EPA 

also solicited comment on the treatment of renewable energy, 

demand-side energy efficiency and other new low- or non-emitting 

electricity generation across international boundaries in a 

state plan. 

The EPA also issued two notices after the June 18, 2014 

proposal. On October 30, 2014, the EPA published a notice of 

data availability (NODA) in which the agency provided additional 

information on several topics raised by stakeholders and 

solicited comment on the information presented. The notice 

covered three topic areas: 1) the emission reduction compliance 

trajectories created by the interim goal for 2020 to 2029, 2) 

certain aspects of the building block methodology, and 3) the 

way state-specific CO2 goals are calculated. 
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In a separate action, the EPA published a notice regarding 

potential methods for determining the mass that is equivalent to 

an emission rate-based CO2 goal (79 FR 67406; November 13, 2014). 

With the notice, the EPA also made available, in the docket for 

this rulemaking, a technical support document (TSD) that 

provided two examples of how a state, U.S. territory or tribe 

could translate a rate-based CO2 goal to total metric tons of CO2

(a mass-based equivalent). 

J. Stakeholder Outreach and Consultations 

Following the direction in the Presidential Memorandum to 

the Administrator (June 25, 2013),219 the EPA engaged in 

extensive and vigorous outreach to stakeholders and the general 

public at every stage of development of this rule. Our outreach 

has included direct engagement with the energy and environment 

officials in states, tribes, and a full range of stakeholders 

including leaders in the utility power sector, labor leaders, 

non-governmental organizations, other federal agencies, other 

experts, community groups and members of the public. The EPA 

participated in more than 300 meetings before the rule was 

proposed and more than 300 after the proposal. 

 

219 Presidential Memorandum – Power Sector Carbon Pollution 

Standards, June 25, 2013. http://www.whitehouse.gov/the-pressoffice/2013/06/25/presidential-memorandum-power-sector-carbonpollution-standards. 
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Throughout the rulemaking process, the agency has 

encouraged, organized, and participated in hundreds of meetings 

about CAA section 111(d) and reducing carbon pollution from 

existing power plants. The agency’s outreach prior to proposal, 

as well as during the public comment period, was designed to 

solicit policy ideas,220 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,221

teleconferences and meetings held all across the country. 

Our engagement has brought together a variety of states and 

stakeholders to discuss a wide range of issues related to the 

utility power sector and the development of emission guidelines 

under CAA section 111(d). The meetings were attended by the EPA 

Regional Administrators, other senior managers and staff who 

have been instrumental in the development of the rule and will 

play key roles in developing and implementing it. 

 

220 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. 

221 Summaries of the 11 public listening sessions in 2013 are 

available at www.regulations.gov at EPA Docket ID No. EPA-HQOAR-2014-0020. 
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This outreach process has produced a wealth of information 

which has informed this rule significantly. The pre-proposal 

outreach efforts far exceeded what is required of the agency in 

the normal course of a rulemaking process, and the EPA expects 

that the dialogue with states and stakeholders will continue 

after the rule is finalized. The EPA recognizes the importance 

of working with all stakeholders, and in particular with the 

states, to ensure a clear and common understanding of the role 

the states will play in addressing carbon pollution from power 

plants. We firmly believe that our outreach has resulted in a 

more workable rule that will achieve the statutory goals and has 

enhanced the likelihood of timely and successful achievement of 

the carbon reduction goals, given the critical importance and 

urgency of the concrete action. 

The EPA has given stakeholder comments careful 

consideration and, as a result, this final rule includes 

features that are responsive to many stakeholder concerns. 

1. Public hearings 

More than 2,700 people attended the public hearings 

sessions held in Atlanta, Denver, Pittsburgh, and Washington, 

DC. More than 1,300 people spoke at the public hearings. 

Additionally, about 100 people attended the public hearing held 

in Phoenix, Arizona, on the November 4, 2014 supplemental 
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proposal. Speakers at the public hearings included Members of 

Congress, other public officials, industry representatives, 

faith-based organizations, unions, environmental groups, 

community groups, students, public health groups, energy groups, 

academia and concerned citizens. 

Participants shared a range of perspectives. Many were 

concerned with the impacts of climate change on their health and 

on future generations, others were worried about the impact of 

regulations on the economy. Their support for the agency’s 

efforts varied. 

2. State officials 

Since fall 2013, the agency has provided multiple 

opportunities for the states to inform this rulemaking. 

Administrator McCarthy has engaged with governors from states 

with a variety of interests in the rulemaking. Other senior 

agency officials have engaged with every branch and major agency 

of state government - including state legislators, attorneys 

general, state energy, environment, and utility officials, and 

governors' staff. 

On several occasions, state environmental commissioners met 

with senior agency officials to provide comments on the Clean 

Power Plan. The EPA organized, encouraged and attended meetings 

with states to discuss multi-state planning efforts. States have 
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come together with several collaborative groups to discuss ways 

to work together to make the Clean Power Plan more affordable. 

The EPA has participated in and supported the states in these 

discussions. Because of the interconnectedness of the power 

sector, and the fact that electricity generated at power plants 

crosses state lines; states, utilities and ratepayers may 

benefit from states working together to implement the 

requirements of this rulemaking. The meetings provided state 

leaders, including governors, environmental commissioners, 

energy officers, public utility commissioners, and air 

directors, opportunities to engage with the EPA officials. In 

addition, the states submitted public comments from several 

agencies within each state. The wealth of comments and input 

from states was important in developing the final rulemaking. 

Agency officials listened to ideas, concerns and details 

from states, including from states with a wide range of 

experience in reducing carbon pollution from power plants. The 

EPA reached out to all 50 states to engage with both 

environmental and energy departments at all levels of 

government. As an example, a three-part webinar series in 

June/July 2014 for the states and tribes offered an interactive 

format for technical staff at the EPA and in the states/tribes 

to exchange ideas and ask clarifying question. The webinars were 
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then posted online so other stakeholders could view them. A few 

weeks after the postings, the EPA organized follow-up conference 

calls with stakeholder groups. Also, the EPA hosted scores of 

technical meetings between states and the EPA in the weeks and 

months after the rule was proposed. 

Additionally, the EPA organized “hub” calls; these 

teleconferences brought all of the states in a given EPA region 

together to discuss technical and interstate aspects of the 

proposal. These exchanges helped provide the stakeholders with 

the information they needed to comment on the proposal 

effectively. The EPA also held a series of webinars with state 

environmental associations and their members on a series of 

technical issues. 

The agency has collected policy papers and comment letters 

from states with overarching energy goals and technical details 

on the states’ utility power sector. EPA leadership and staff 

also participated in webinars and meetings with state and tribal 

officials hosted by collaborative groups and trade associations. 

After the comment period closed, and based on our meetings over 

the last year, as well as written comments on the proposal and 

NODA, the EPA analyzed information about data errors that needed 

to be addressed for the final rule. In February and March 2015, 

we reached out to particular states to clarify ambiguous or 
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unclear information that was submitted to the EPA related to 

NEEDS and eGRID data. The EPA contacted particular states to 

clarify the technical comments or concerns to ensure that any 

changes we make are accurate and appropriate. 

To help prepare for implementation of the Clean Power Plan, 

the agency initiated several outreach activities to assist with 

state planning efforts. The agency participated in meetings 

organized by the National Association of State Energy Officials 

(NASEO), the National Association of Regulatory Utility 

Commissioners (NARUC), and the National Association of Clean Air 

Agencies (NACAA) (the “3N” groups). Meeting participants 

discussed issues related to energy efficiency and renewable 

energy. 

To help state officials prepare for the planning process 

that will take place in the states, the EPA presented a webinar 

on February 24, 2015. This webinar provided an update on 

training plans and further connection with states in the 

implementation process. Forty-nine states, the District of 

Columbia, and 14 tribes were represented at this webinar. The 

EPA is developing a state plan electronic collection system to 

receive, track, and store state submittals of plans and reports. 

The EPA plans to use an integrated project team to solicit 

stakeholder input on the system during development. The team 
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membership, including state representatives, will bring together 

the business and technology skills required to construct a 

successful product and promote transparency in the EPA’s 

implementation of the rule. 

To help identify training needs for the final Clean Power 

Plan, the agency reached out to a number of state and local 

organizations such as the Central State Air Resources Agencies 

and other such regional air agencies. The EPA’s outreach on 

training has included sharing the plans with the states and 

incorporating changes to the training topics based on the 

states’ needs. The EPA training plan includes a wide variety of 

topics such as basic training on the electric power sector as 

well as specific pollution control strategies to reduce carbon 

emissions from power plants. In particular the states requested 

training on how to use programs such as combined heat and power, 

energy efficiency and renewable energy to reduce carbon 

emissions. EPA will continue to work with states to tailor 

training activities to their needs. 

The agency has engaged, and will continue to engage with 

states, territories, Washington, D.C., and tribes after the 

rulemaking process and throughout implementation. 

3. Tribal officials 
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 The EPA conducted significant outreach to and consultation 

with tribes. Tribes are not required to, but may, develop or 

adopt Clean Air Act programs. The EPA is aware of four 

facilities with affected EGUs located in Indian country: the 

South Point Energy Center, in Fort Mojave Indian country, 

geographically located within Arizona; the Navajo Generating 

Station, in Navajo Indian country, geographically located within 

Arizona; the Four Corners Power Plant, in Navajo Indian country, 

geographically located within New Mexico; and the Bonanza Power 

Plant, in Ute Indian country, geographically located within 

Utah. The EPA offered consultation to the leaders of the tribes 

on whose lands these facilities are located as well as all of 

the federally recognized tribes to ensure that they had the 

opportunity to have meaningful and timely input into this rule. 

Section III (“Stakeholder Outreach and Conclusions”) of the June 

18, 2014 proposal documents the EPA’s extensive outreach efforts 

to tribal officials prior to that proposal, including an 

informational webinar, outreach meeting, teleconferences with 

tribal officials and the National Tribal Air Association (NTAA), 

and letters offering consultation. Additional outreach to tribal 

officials conducted by the EPA prior to the November 4, 2014 

supplemental proposal is discussed in Section II.D (“Additional 

Outreach and Consultation”) of the supplemental proposal. The 
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additional outreach for the supplemental proposal included 

consultations with all three tribes that have affected EGUs on 

their lands, as well as several other tribes that requested 

consultation, and also additional teleconferences with the NTAA. 

After issuing the supplemental proposal, the EPA offered an 

additional consultation to the leaders of all federally 

recognized tribes. The EPA held an informational meeting open to 

all tribes and also held consultations with the Navajo Nation, 

Fort McDowell Yavapai Nation, Fort Mojave Tribe, Ak-Chin Indian 

Community, and Hope Tribe on November 18, 2014. The EPA held a 

consultation with the Ute Tribe of the Uintah and Ouray 

Reservation on December 16, 2014, and a consultation with the 

Gila River Indian Community on January 15, 2015. The EPA held a 

public hearing on the supplemental proposal on November 19, 

2014, in Phoenix, Arizona. On April 28, 2015, the EPA held an 

additional consultation with the Navajo Nation. 

 Tribes were interested in the impact of this rule on other 

ongoing regulatory actions at the affected EGUs, such as 

permitting or requirements for the best available retrofit 

technology (BART). Tribes also noted that it was important to 

allow renewable energy projects on tribal lands to contribute 

toward meeting state goals. Some tribes indicated an interest in 

being involved in the development of implementation plans for 
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areas of Indian country. Additional detail regarding the EPA’s 

outreach to tribes and comments and recommendations from tribes 

can be found in Section X.F of this preamble. 

4. U.S. territories 

The EPA has met with individual U.S. territories and 

affected EGUs in U.S. territories during the rulemaking process. 

On July 22, 2014, the EPA met with representatives from the 

Puerto Rico Environmental Quality Board, the Puerto Rico 

Electric Power Authority, the Governor’s Office, and the Office 

of Energy, Puerto Rico. On September 8, 2014, the EPA held a 

meeting with representatives from the Guam Environmental 

Protection Agency (GEPA) and the Guam Power Authority and, on 

February 18, 2015, the EPA met again with representatives from 

GEPA. 

5. Industry representatives 

Agency officials have engaged with industry leaders and 

representatives from trade associations in many one-on-one and 

national meetings. Many meetings occurred at the EPA 

headquarters and in the EPA’s Regional Offices and some were 

sponsored by stakeholder groups. Because the focus of the rule 

is on the utility power sector, many of the meetings with 

industry have been with utilities and industry representatives 

directly related to the utility power sector. The agency has 
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also met with energy industries such as coal and natural gas 

interests, as well as companies that offer new technology to 

prevent or reduce carbon pollution, including companies that 

have expertise in renewable energy and energy efficiency. Other 

meetings have been held with representatives of energy intensive 

industries, such as the iron and steel and aluminum industries, 

to help understand the issues related to large industrial users 

of electricity. 

6. Electric utility representatives 

Agency officials participated in many meetings with 

utilities and their associations to discuss all aspects of the 

proposed guidelines. We have met with all types of companies 

that produce electricity, including private utilities or 

investor owned utilities. Public utilities and cooperative 

utilities were also part of in-depth conversations about CAA 

section 111(d) with EPA officials. 

The conversations included meetings with the EPA 

headquarters and regional offices. State officials were included 

in many of the meetings. Meetings with utility associations and 

groups of utilities were held with key EPA officials. The 

meetings covered technical, policy and legal topics of interest 

and utilities expressed a wide variety of support and concerns 

about CAA section 111(d). 
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7. Electricity grid operators 

The EPA had a number of conversations with the Independent 

System Operators and Regional Transmission Organizations (ISOs 

and RTOs) to discuss the rule and issues related to grid 

operations and reliability. EPA staff met with the ISO/RTO 

Council on several occasions to collect their ideas. The EPA 

regional offices also met with the ISOs and RTOs in their 

regions. System operators have offered suggestions in using 

regional approaches to implement CAA section 111(d) while 

maintaining reliable, affordable electricity. 

8. Representatives from community and non-governmental 

organizations 

Agency officials engaged with community groups representing 

low-income communities, and faith-based groups, among others, 

during the outreach effort. In response to a request from 

communities, the EPA held a day-long training on the Clean Power 

Plan on October 30, 2014, in Washington D.C. At this meeting, 

the EPA met with a number of environmental groups to provide 

information on how the agency plans on reducing carbon pollution 

from existing power plants using CAA section 111(d). 

Many environmental organizations discussed the need for 

reducing carbon pollution. Meetings were technical, policy and 

legal in nature and many groups discussed specific state 
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policies that are already in place to reduce carbon pollution in 

the states. 

 A number of organizations representing religious groups 

have reached out to the EPA on several occasions to discuss 

their concerns and ideas regarding this rule. Many members of 

faith communities attended the four public hearings. 

 Public health groups discussed the need for protection of 

children’s health from harmful air pollution. Doctors and health 

care providers discussed the link between reducing carbon 

pollution and air pollution and public health. Consumer groups 

representing advocates for low income electricity customers 

discussed the need for affordable electricity. They talked about 

reducing electricity prices for consumers through energy 

efficiency and low-cost carbon reductions. 

 In winter/spring 2015, EPA continued to offer webinars and 

teleconferences for community groups on the rulemaking. 

9. Environmental Justice Organizations 

Agency officials engaged with environmental justice groups 

representing communities of color, low-income communities and 

others during the outreach effort. Agency officials also engaged 

with the EPA’s National Environmental Justice Advisory Council 

(NEJAC) members in September 2013. The NEJAC is composed of 

stakeholders, including environmental justice leaders and other 
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leaders from state and local government and the private sector. 

Additionally, the agency conducted a community call on February 

26, 2015, and on February 27, 2015, the EPA conducted a follow 

up webinar for participants in an October 30, 2014 training 

session. The EPA also held a webinar for communities on the 

Clean Air Act (CAA) and section 111(d) of the CAA on April 2, 

2015. 

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 
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adversely and disproportionally affects vulnerable and 

disadvantaged communities in the US and throughout the world. 

In addition, the rule will result in substantial reductions of 

conventional air pollutants, providing immediate public health 

benefits to the communities where the facilities are located and 

for many miles around. The EPA is committed to ensuring that all 

Americans benefit from the public health and other benefits that 

this rule will bring. Further discussion of the impacts of this 

rule on 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 
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the American Federation of Labor-Congress of Industrial 

Organizations (AFL-CIO) at the AFL-CIO headquarters. 

EPA officials attended meetings sponsored by labor unions 

to give presentations and engage in discussions about reducing 

carbon pollution using CAA section 111(d). These included 

meetings sponsored by the IBB and the IBEW. 

11. Other federal agencies and independent agencies 

Throughout the development of the rulemaking, the EPA 

consulted with other federal agencies with relevant expertise. 

For example, the EPA met with managers from the U.S. Department 

of Agriculture’s (USDA’s) Rural Utility Service to discuss the 

rule and potential effects on affected EGUs in rural areas and 

how USDA programs could interact with affected EGUs during rule 

implementation. 

The U.S. Department of Energy (DOE) was a frequent source 

of expertise and advice on the proposed and final rule. EPA 

management and staff had numerous meetings with management and 

staff at DOE on a range of topics, including the effectiveness 

and costs of energy generation technologies, and energy 

efficiency. 

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 
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deploying and reliably integrating increased RE generation. 

Further, EPA and DOE staff discussed emission measurement and 

verification (EM&V) strategies. 

 The EPA also consulted with DOE on electric reliability 

issues. EPA staff and managers met and spoke with DOE staff and 

managers throughout the development of the proposed and final 

rules on topic related to electric system reliability. 

 EPA officials worked closely with DOE and Federal Energy 

Regulatory Commission (FERC) officials to ensure, to the 

greatest extent possible, that actions taken by states and 

affected EGUs to comply with the final rule mitigate potential 

electric system reliability issues. Senior EPA officials met 

with each of the FERC Commissioners and EPA staff had frequent 

contact with FERC staff throughout the development the rule. 

FERC held four technical conferences to discuss implications of 

compliance approaches to the rule for electric reliability. EPA 

staff attended the four conferences and EPA leadership spoke at 

all of them. The EPA, DOE, and FERC will continue to work 

together to ensure electric grid reliability in the development 

and implementation of state plans. 

K. 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 
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available to the public at http://www.epa.gov/cleanpowerplan/.

The 120-day public comment period on the proposal began on June 

18, 2014, the day of publication of the proposal in the Federal 

Register. On September 18, 2014, in response to requests from 

stakeholders, the EPA extended the comment period by 45 days, to 

December 1, 2014, giving stakeholders over 165 days to review 

and comment upon the proposal. Stakeholders also had the 

opportunity to comment on the NODA, as well as the notice and 

TSD regarding potential methods for determining the mass that is 

equivalent to an emission rate-based CO2 goal, through December 

1, 2014. The EPA offered a separate 45-day comment period for 

the November 4, 2014 supplemental proposal, and that comment 

period closed on December 19, 2014. 

The EPA received more than 4.2 million comments on the 

proposed carbon pollution emission guidelines from a range of 

stakeholders that included, including state environmental and 

energy officials, local government officials, tribal officials, 

public utility commissioners, system operators, utilities, 

public interest advocates, and members of the public. The agency 

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 
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The EPA is establishing emission guidelines for states to 

use in developing plans to address greenhouse gas emissions from 

existing fossil fuel-fired electric generating units. The 

emission guidelines are based on the EPA’s determination of the 

“best system of emission reduction ... adequately demonstrated” 

(BSER) and include source category-specific CO2 emission 

performance rates, state-specific goals, requirements for state 

plan components, and requirements for the process and timing for 

state plan submittal and compliance. 

Under CAA section 111(d), the states must establish 

standards of performance that reflect the degree of emission 

limitation achievable through the application of the “best 

system of emission reduction” that, taking into account the cost 

of achieving such reduction and any non-air quality health and 

environmental impact and energy requirements, the Administrator 

determines has been adequately demonstrated. 

The EPA has determined that the BSER is the combination of 

emission rate improvements and limitations on overall emissions 

at affected EGUs that can be accomplished through any 

combination of one or more measures from the following three 

sets of measures or building blocks: 
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1. Reducing the carbon intensity of generation at 

individual affected coal-fired steam EGUs through heat 

rate improvements. 

2. Substituting increased generation from loweremitting existing natural gas combined cycle units for 

reduced generation from higher-emitting affected steam 

generating units. 

3. Substituting increased generation from new low- and 

zero-emitting generating units for reduced generation 

from affected fossil fuel-fired generating units. 

Consistent with CAA section 111(d), 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-fired electric utility steam generating units and 

stationary combustion turbines. The EPA is finalizing source 

subcategory-specific 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 1,290 

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

finalizing a performance rate of 780 lb/MWh of CO2. The EPA has 

also translated the source subcategory-specific CO2 emission 

performance rates into equivalent statewide rate-based and mass-
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based CO2 goals and is providing those as an option for states to 

use. 

Under CAA section 111(d), each state must develop, adopt, 

and then submit its plan to the EPA. For its CAA section 111(d) 

plan, a state will determine whether to apply these emission 

performance rates to each affected EGU, individually or 

together, or to take an alternative approach and meet either an 

equivalent statewide rate-based goal or an equivalent statewide 

mass-based goal, as provided by the EPA in this rulemaking. 

For these final emission guidelines, the term “state,” when 

used in the context of section 111(d) plans, encompasses 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. However, such a “state” would not be obligated or 

potentially eligible to submit a CAA section 111(d) plan unless 

it has within its jurisdictional boundaries one or more affected 

EGUs that commenced construction on or before January 8, 2014. 

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
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emission performance rates or the state-specific CO2 emission 

goal to affected EGUs in the form of federally enforceable 

emission standards. With a state measures approach, a state plan 

would be comprised, at least in part, of measures implemented by 

the state that are not included as federally enforceable 

components of the plan, along with a backstop of federally 

enforceable emission standards for affected EGUs that would 

apply in the event the plan does not achieve its anticipated 

level of CO2 emission performance. 

The EPA is requiring states to make their initial plan 

submittals 13 months from the signature date of the rule and to 

make their final plan submittals no later than 3 years from the 

signature date of the rule. 

The EPA is 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 eightyear interim period from 2022 through 2029, is separated into 

three steps, 2022-2024, 2025-2027, and 2028-2029, each 

associated with its own interim CO2 emission performance rates 

that states must meet, as explained in Section VI of this 

preamble. Affected EGUs must achieve the final emission 

performance rates or equivalent statewide goals by 2030 and 

maintain that level thereafter. 
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The EPA is further establishing, as part of the guidelines, 

timetables for states to submit their plans. Each state must use 

the established electronic submittal system to provide the EPA 

its complete plan submittal by August 31, 2016. However, if a 

state needs additional time to provide the EPA with a complete 

plan submittal, the state must provide an initial plan submittal 

by August 31, 2016, that documents the reasons that more time is 

needed to provide a complete plan submittal and includes 

commitments to take concrete steps that will ensure that the 

state will submit a complete plan by August 31, 2018. 

For the final emission guidelines, the EPA is revising 

the list of components required in a state plan submittal 

to reflect: 1) components required for all state plan 

submittals; 2) components required for the emission 

standards approach; and 3) components required for the 

state measures approach. The revised list of components 

also reflects the approvability criteria, which are no 

longer separate from the state plan submittal components. 

All state plans must include the following components:

• Description of the plan approach and geographic scope 

• Identification of state state CO2 interim period goal (for 

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

2024; interim step goal 2 for 2025-2027; interim step goal 

3 for 2028-2029) and final CO2 emission goal of 2030 and 

beyond 

• Demonstration that the plan submittal is projected to 

achieve the state’s CO2 emission goal 
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• State recordkeeping and reporting requirements 

• Certificatin of hearing on state plan 

• Supporting documentation 

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

documentation, states must include a description of their 

required consultation with relevant ISOs/RTOs and/or 

planning/reliability authorities during plan development, 

including any recommendations and other comments provided by 

those authorities. 

Further, the EPA is requiring that states provide, in their 

initial plan submittal, a summary of how they have been engaging 

with community stakeholders and how they intend to meaningfully 

engage with community stakeholders during the additional time 

(if an extension is granted) for development of the final plan. 

In their report, states must show how they identified low income 

and communities of color that they are conducting meaningful 

community engagement with in the state plan development process. 

For the final plan submittal, states must engage with all 

members of the public, including communities, during the 

complete plan development process pursuant to the public 

participation requirements of the framework regulations. 

State plan submittals using the emission standards approach 

must also include: 

 Identification of each affected EGU; identification of 

federally enforceable emission standards for the affected 
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EGUs; and monitoring, recordkeeping and reporting 

requirements. 

 Demonstrations that each emission standard is 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 is 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. 

 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 

letter submitted to the EPA by August 31, 2016. In the case of a 

tribe that has one or more affected EGUs in its area of Indian 

country,222 the tribe has the opportunity, but not the 

 

222 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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obligation, to establish a CAA section 111(d) plan for its area 

of Indian country. If a tribe with one or more affected EGUs 

located in its area of Indian country does not submit a plan or 

does not receive EPA approval of a submitted plan, the EPA has 

the responsibility to establish a CAA section 111(d) plan for 

that area if it determines that such a plan is necessary or 

appropriate. 

 During and following implementation of its 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. State 

plan requirements and flexibilities are described more fully in 

Section VIII of this preamble.

B. Legal Basis 

This rule is consistent with the requirements of CAA 

section 111(d) and the implementing regulations. 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 
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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;223 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 

 

223 The EPA is not re-opening that interpretation in this 

rulemaking. 
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“reasonable.” Building blocks 2 and 3 include increases in lowor 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 environment 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 include reduced generation from the 

fossil fuel-fired EGUs because that is a step in the process of 

substituting lower- or zero-emitting generation for higheremitting generation. 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 
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focusing costs on the affected EGUs for which reducing emissions 

is most cost-effective. Because trading facilitates 

implementation of the building blocks and may help to optimize 

cost-effectiveness, trading is within the BSER as well. 

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

achieving its emission standards. It 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 

measures through a set of actions that range from purchasing 

full or partial interest in existing NGCC or new renewable 

energy assets to purchasing emission rate credits that represent 

the environmental attributes of increased NGCC generation or new 

renewable generation. In addition, the affected EGU may reduce 

its generation and thereby reduce the extent that it needs to 

implement the building blocks. In addition, the affected EGU may 

purchase rate-based emission credits from other affected EGUs. 

If the state chooses to impose a mass-based emission standard, 

the affected EGU 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 
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reductions and maintain the reliability of the electricity 

system. 

With the promulgation of the emission guidelines, each 

state must develop and submit a plan to achieve the CO2 emission 

performance rates established by the EPA or the equivalent 

statewide rate-based or mass-based goal provided by the EPA in 

this rule. The EPA interprets CAA section 111(d) to allow states 

to establish standards of performance and provide for their 

implementation and enforcement through either the “emission 

standards” or the “state measures” plan type. In the case of the 

“emission standards” plan type, the emission standards establish 

standards of performance, and the other components of the plan 

provide for their implementation and enforcement. In the case of 

the “state measures” plan type, the state submits standards of 

performance in the form of a federally enforceable backstop, the 

trigger mechanism provides for the implementation of such 

backstop, and the other components of the plan also provide for 

implementation and enforcement of the standards of performance. 

 These two types of state plans and their respective 

approaches, which could be implemented on a single-state or 

multi-state basis, allow states to meet the statutory 

requirements of section 111(d) while accommodating the wide 

range of regulatory requirements and other programs that states 
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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 

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, 
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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 discusses certain issues in 

more detail in the Legal Memorandum included in the docket for 

this rulemaking. 

IV. Authority for this Rulemaking, Definition of Affected 

Sources, and Treatment of Source Categories 

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

EPA’s authority for this rule is CAA section 111(d). CAA 

section 111(d) provides that the EPA will promulgate regulations 

under which each state will establish standards of performance 

for existing sources for any air pollutant that meets two 

criteria. First, CAA section 111(d) applies to air pollutants 

that are not regulated as a criteria pollutant under section 108 

or as a hazardous air pollutant (HAP) under CAA section 112. 42 
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U.S.C. 7411(d)(1)(A)(i). 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 published today 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 of air pollutants that are regulated under CAA 

section 112. 42 U.S.C. 7411(d)(1)(A)(i). This “Section 112 

Exclusion” in CAA section 111(d) was the subject of a 

significant number of comments based on two differing amendments 

to this exclusion enacted in the 1990 CAA Amendments. As 

discussed in more detail below, the House and the Senate each 

passed different amendments to the Section 112 Exclusion and 

both amendments were signed into law. In 2005, in connection 

with the Clean Air Mercury Rule (CAMR), the EPA discussed the 

agency’s interpretation of the exclusion in light of these two 

differing amendments and concluded that the two amendments were 

in conflict, should be read to give both meaning, and should be 
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interpreted as follows: where a source category has been 

regulated under CAA section 112, a CAA section 111(d) standard 

of performance cannot be established to address any HAP listed 

under CAA section 112(b) that may be emitted from that 

particular source category. See 70 FR 15994, 16029-30 (March 29, 

2005). 

 In June 2014, the EPA presented this previous 

interpretation along with the proposed rule and requested 

comment on it. The EPA received numerous comments on its 

previous interpretation, including comments on the proper 

interpretation and effect of each of the two differing 

amendments, and whether the Section 112 Exclusion should be read 

to mean that the EPA’s regulation of HAP from power plants under 

CAA section 112 bars the EPA from establishing CAA section 

111(d) regulations covering CO2 emissions from power plants. In 

particular, many comments focused on two specific issues. 

First, some commenters -- including some industry and state 

commenters that had previously endorsed the EPA’s interpretation 

of the Section 112 Exclusion in other contexts224 -- argued that 

 

224 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 
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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 categories were also 

regulated for different pollutants under CAA section 112. 

Second, some commenters argued that the EPA’s previous 

interpretation of the House amendment (as originally represented 

in 2005 at 70 FR at 16029-30) was in error because it improperly 

read that amendment as focusing on whether a source category was 

regulated under CAA section 112 rather than on whether the air 

pollutant was regulated under CAA section 112, and that improper 

reading lead to an interpretation that was inconsistent with the 

structure and purpose of the CAA. 

In light of the comments, the EPA has reconsidered its 

previous interpretation of the Section 112 Exclusion and, in 

particular, considered whether the exclusion precludes the 

regulation under CAA section 111(d) of CO2 from power plants 

given that power plants are regulated for certain HAP under CAA 

section 112. On this issue, the EPA has concluded that the two 

differing amendments are not properly read as conflicting. 

Instead, the House amendment and the Senate Amendment should 

 

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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each be read to mean the same in this context: that the Section 

112 Exclusion does not bar the regulation under CAA section 

111(d) of any non-HAP from a source category, regardless of 

whether that source category may be subject to standards for HAP 

under CAA section 112. In reaching this conclusion, the EPA has 

revised its previous interpretation of the House amendment, as 

discussed below. 

The EPA’s analysis is entitled to deference under the 

principles established in Chevron v. NRDC, 467 U.S. 837 (1984). 

See White Stallion Energy v. EPA, 748 F.3d 1222, 1235 (D.C. Cir. 

2014) (a revision to an agency interpretation is reviewed under 

the Chevron framework. Under that framework, the revised 

interpretation will be upheld if the court finds that it “is 

permissible under the statute, that there are good reasons for 

it, and that the agency believes it to be better.”) (quoting FCC 

v. Fox Television Stations, Inc., 556 U.S. 502, 515 (2009)).225 

The EPA’s revised interpretation is discussed below. 

1. Structure of the CAA and Pre-1990 Section 112 Exclusion 

The Clean Air Act sets out a comprehensive scheme for air 

pollution control, addressing three general categories of 

 

225 Indeed, the Chevron case itself involved the EPA’s 

reevaluation of how to interpret an ambiguous statutory term. 

See 467 U.S. at 857-58 (EPA reevaluation of how to interpret the 

term “source”).
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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 Fed. Reg. 53,340 (Nov. 17, 1975). 

Six “criteria” pollutants are regulated under sections 108-

110. These are pollutants that the Administrator has concluded 

“cause or contribute to air pollution which may reasonably be 

anticipated to endanger public health or welfare;” “the presence 

of which in the ambient air results from numerous and diverse 

mobile or stationary sources;” and for which the Administrator 

has issued, or plans to issue, “air quality criteria. 42 U.S.C. 

§7408(a)(1). Once the EPA issues air quality criteria for such 

pollutants, the Administrator must propose primary National 

Ambient Air Quality Standards (NAAQS) for them, set at levels 

“requisite to protect the public health” with an “adequate 

margin of safety. 42 U.S.C. § 7409(a)-(b). States must then 

adopt plans for implementing NAAQS. 42 U.S.C. § 7410. 

Hazardous air pollutants 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 
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EPA will publish and revise a list of “major” and “area” source 

categories of hazardous pollutants, and then establish emissions 

standards for hazardous air pollutants emitted by sources within 

a listed category. 42 U.S.C. § 7412(c)(1) & (2). 

 CAA section 111, 42 U.S.C. § 7411, is the third part of the 

CAA’s structure for regulating stationary sources. CAA section 

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

the EPA to promulgate federal “standards of performance” 

addressing new stationary sources that cause or contribute 

significantly to “air pollution which may reasonably be 

anticipated to endanger public health or welfare.” 42 U.S.C. § 

7411(b)(1)(A). Once the EPA has set new source standards 

addressing emissions of a particular pollutant, CAA section 

111(d) provides that the EPA will promulgate regulations 

requiring states to establish standards of performance for 

existing stationary sources of the same pollutant. 42 U.S.C. § 

7411(d)(1). 

Together, the criteria pollutant/NAAQS provisions in 

sections 108-110, the hazardous air pollutant provisions in 

section 112, and performance standard provisions in section 111 

constitute a comprehensive scheme to regulate air pollutants 

with ““no gaps in control activities pertaining to stationary 
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source emissions that pose any significant danger to public 

health or welfare.” S. Rep. No. 91-1196, at 20 (1970). 226 

The specific role of CAA section 111(d) in this structure 

can be seen in CAA subsection 111(d)(1)(A)(i), which provides 

that regulation under CAA section 111(d) regulation of 

pollutants is intended to cover pollutants that are not 

regulated under either the criteria pollutant/NAAQS provisions 

or the hazardous air pollutants regulated under section 112. 

Prior to 1990, this limitation was laid out in plain language, 

which stated that CAA section 111(d) regulation applied to “any 

air pollutant... for which air quality criteria have not been 

issued or which is not included on a list published under 

section [108(a)] or [112(b)(1)(A)].” This plain language 

demonstrated that section 111(d) is designed to regulate 

pollutants from existing sources that fall in the gap between 

the criteria pollutant provisions and 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 

 

226 In subsequent CAA amendments, Congress has maintained this 

three-part scheme, but supplemented it with the Preservation of 

Significant Deterioration (PSD) program, the Acid Rain Program 

and the Regional Haze program. 
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section 114) was described as covering pollutants that would not 

be controlled by the criteria pollutant provisions or the 

hazardous air pollutant provisions. See S. Committee Rep. to 

accompany S. 4358 (Sept. 17, 1970), 1970 CAA Legis. Hist. at 420 

(“It should be noted that the emission standards for pollutants 

which cannot be considered hazardous (as defined in section 115 

[which later became section 112]) could be established under 

section 114 [later, section 111]. Thus, there should be no gaps 

in control activities pertaining to stationary source emissions 

that pose any significant danger to public health or welfare.”); 

Statement by S. Muskie, S. Debate on S. 4358 (Sept. 21, 1970), 

1970 CAA Legis. Hist. at 227 (“[T]he bill [in section 114] 

provides the Secretary with the authority to set emission 

standards for selected pollutants which cannot be controlled 

through the ambient air quality standards and which are not 

hazardous substances.”). 

2. The 1990 Amendments to the Section 112 Exclusion 

The Act was amended extensively in 1990. Among other 

things, Congress sought to accelerate the EPA’s regulation of 

hazardous pollutants under section 112. To that end, Congress 

established a lengthy list of hazardous air pollutants; set 

criteria for listing “source categories” of such pollutants; and 

required the EPA to establish standards for each source category 
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or subcategory’s hazardous pollutant emissions. 42 U.S.C. § 

7412(a), (b)(1) & (2), & (d)(1). In the course of overhauling 

the regulation of hazardous air pollutants under section 112, 

Congress needed to edit section 111(d), which cross-referenced a 

provision of old section 112 that was to be eliminated – section 

112(b)(1)(A). 

To address the obsolete cross-reference to section 

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

from the House and one from the Senate – that were never 

reconciled in conference. The House amendment replaced the 

cross-reference with the phrase “emitted from a source category 

which is regulated under section [112].” Pub. L. No. 101-549, § 

108(g), 104 Stat. 2399, 2467 (1990). The Senate amendment 

replaced the same text with a cross-reference to new section 

112. Pub. L. No. 101-549, § 302(a), 104 Stat. 2399, 2574 (1990). 

Both amendments were enacted into law, and are thus both are 

part of the current CAA. To determine how this this provision is 

properly applied in light of the two differing amendments, we 

first look at the Senate amendment, then at the House amendment, 

then discuss how the two amendments are properly read together. 

3. The Senate Amendment is Clear and Unambiguous 

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

House amendment (discussed below), the Senate amendment is 
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straightforward and unambiguous. It maintained the pre-1990 

meaning of the Section 112 Exclusion by simply substituting 

“section 112(b)” for the prior cross-reference to “section 

112(b)(1)(A).” Pub. L. No. 101-549, § 302(a), 104 Stat. 2399, 

2574 (1990). So amended, section 111(d) mandates that the EPA 

require states to submit plans establishing standards for “any 

air pollutant . . . which is not included on a list published 

under section [108(a)] or section [112(b)].” Thus, the Section 

112 Exclusion resulting from the Senate amendment would not 

preclude the EPA from regulating CO2 from power plants 

notwithstanding that power plants are also regulated for HAP 

under CAA section 112 under the MATS rule. 

 Some commenters have argued that the Senate amendment 

should be given no effect, because only the House amendment is 

shown in the U.S. Code, and because the Senate amendments 

appeared under the heading “conforming amendments,” and for 

various other reasons. The EPA disagrees. The Senate amendment, 

like the House amendment, was enacted into law as part of the 

1990 CAA amendments, and must be given effect. 

 First, that the U.S. Code only reflects the House amendment 

does not change the fact that both amendments were signed into 

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

Large. Pub. L. No. 101-549, §§ 108(g) and 302(a), 104 Stat. 
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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 

the heading under which it was enacted (“Miscellaneous 
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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 

over 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, as reported (Dec. 20, 
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1989), 1990 CAA Legis. Hist. at 7906. As reported and eventually 

passed, S. 1630 did not contain the text in the House amendment 

(“or emitted from a source category which is regulated under 

section 112”) and instead contained the substitution of cross 

references (changing “section 112(b)(1)(A)” to “section 112(b)”) 

as a “conforming” amendment. See S. 1630, as reported, 101st

Cong. § 305, 1990 CAA Legis. Hist. at 8153; S. 1630, as passed, 

§ 305 (Apr. 3, 1990), 1990 CAA Legis. Hist. at 4534. Though the 

EPA is not aware of any statements in the legislative history 

that expressly explain the Senate’s intent in making these 

changes to the Senate bill, the sequence itself supports the 

conclusion that the Senate’s substitution reflects a decision to 

retain the pre-1990 approach of using a cross-reference to 

112(b) to define the scope of the Section 112 Exclusion. Whether 

the difference in approach between the final Senate amendment in 

S.1630 and the House amendment in H.R. 3030 creates a 

substantive difference or are simply two different means of 

achieving the same end depends on what interpretation one gives 

to the text in the House amendment, which we turn to next. 

4. The House Amendment 

a. The House Amendment is Ambiguous. Statutory interpretation 

begins with the text, but does not end there. As the D.C. 

Circuit Court has explained, “[t]he literal language of a 
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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). Rather, a proper 

reading of statutory text “must employ all the tools of 

statutory interpretation, including text, structure, purpose, 

and legislative history.” Loving v. I.R.S., 742 F.3d 1013, 1016 

(D.C. Cir. 2014) (internal quotation omitted). See, also, 

Robinson v. Shell Oil Co., 519 U.S. 337, 341 (1997) (statutory 

interpretation involves consideration of “the language itself, 

the specific context in which that language is used, and the 

broader context of the statute as a whole.”). Moreover, one 

principle of statutory construction that has particular 

application here is that provisions in a statute should be read 

to be consistent, rather than conflicting, if possible. This 

principle was discussed in the recent case of Scialabba v. 

Cuellar De Osorio, 134 S. Ct. 2191, 2214 (concurring opinion by 

Chief Justice Roberts and Justice Scalia), 2219-2220 (dissent by 

Justices Sotomayor, Breyer and Thomas). As Justice Sotomayor 

wrote (at 134 S. Ct. at 2220): 

“We do not lightly presume that Congress has legislated in 

self-contradicting 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 
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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 coexistence, it is the duty of the courts . . . to regard each as 

effective”). In reviewing an agency’s construction of a statute, 

courts “must,” we have emphasized, “interpret the statute ‘as a 

. . . coherent regulatory scheme’” rather than an internally 

inconsistent muddle, at war with itself and defective from the 

day it was written. Brown & Williamson, 529 U.S., at 133, 120 S. 

Ct. 1291, 146 L. Ed. 2d 121.” 

As amended by the House, CAA section 111(d)(1)(A)(i) limits 

CAA section 111(d) to any air pollutant “for which air quality 

criteria have not been issued or which is not included on a list 

published under section 7408(a) of this title or emitted from a 

source category which is regulated under section 7412 of this 

title . . .” This statutory text is ambiguous and subject to 

numerous possible readings. Two possible readings are based on 

its literal text, but neither of those readings is reasonable 

and no one has advocated that either of those readings be 

adopted. Further, there are additional interpretations that 

arise from different readings of the ambiguous phrases and 

structure created by the House amendment. As discussed below, 

two of these additional interpretations are unreasonable, while 

three are reasonable. 

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

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

any pollutant that is not a criteria pollutant. This 
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interpretation becomes apparent 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, one reading of the 

literal language of section 111(d) provides that the 

Administrator may require states to establish standards for an 

air pollutant so long as either air quality criteria have not 

been established for that pollutant, or one of the remaining 

criteria is met. If this reading were applied to determine 

whether the EPA may regulate CO2 from power plants under section 

111(d), the analysis would be (a) air quality criteria have not 

been issued for CO2, (b) whether CO2 or power plants are 

regulated under section 112 is irrelevant, and (c) CO2 emissions 

from power plants may be regulated under section 111(d). This 

interpretation, however, is not a reasonable reading of the 

statute because, among other reasons, it gives little or no 
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meaning to the limitation covering hazardous air pollutants that 

are regulated under CAA section 112 and thus is contrary to both 

the CAA’s comprehensive scheme created by the three sets of 

provisions (under which CAA section 111 is not intended to 

duplicate the regulation of pollutants regulated under 

section112) and the principle of statutory construction that 

text should not be construed such that a provision does not have 

effect. 

A second literal reading of CAA section 111(d) as revised 

by the House amendment arises from the lack of a negative before 

the third clause. That is, unlike the first and second clauses 

that each contain negative phrases (either “has not been issued” 

or “which is not included”), the third clause does not. One 

could presume that the negative from the second clause was 

intended to carry over, implicitly inserting another “which is 

not” before “emitted from a source category which is regulated 

under section [112].” But that is a presumption, and not the 

plain language of the statute. The text as amended by the House 

says that the EPA “shall” require standards for “any air 

pollutant . . . emitted from a source category which is 

regulated under section [112].” 42 U.S.C. § 7411(d)(1). Thus, 

section 111(d) could be read literally as requiring EPA to 

regulate emissions of pollutants from a source category under 
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section 111(d) if that source category is regulated under CAA 

section 112. If this reading were applied to the question of the 

EPA’s authority for this rule, the result would be that the EPA 

not only has the authority to regulate CO2 from power plants, but 

became obligated to do so once power plants were regulated under 

section 112. Again, this interpretation is not reasonable 

because it would not only call for the regulation under CAA 

section 111(d) of pollutants that were not regulated under CAA 

section 112, but would also provide for the regulation of a 

source’s HAP emissions under CAA section 111(d) when those same 

emissions were also subject to standards under CAA section 112. 

Thus, this reading would be contrary to the comprehensive scheme 

of the statute under which CAA section 111(d) regulation is 

intended to fill the gap between the other programs by covering 

pollutants that the other programs do not, and not duplicate the 

regulation of pollutants that the other programs cover. 

Turning now to the interpretation of the ambiguous phrases 

and structure created by the House amendment, 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 would be 

limited to “any air pollutant...which is not... emitted from a 

source category which is regulated under section [112].” Even 

with this presumption, however, the House amendment contains 
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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 section 111(d). 

The phrase “regulated under section 112” is ambiguous, 

first, because the sentence structure in the text does not make 

clear what that phrase is intended to modify. Young v. 

Community Nutrition Inst., 476 U.S. 974, 980-81 (1986) (“As 

enemies of the dangling participle well know, the English 

language does not always force a writer to specify which of two 

possible objects is the one to which a modifying phrase 

relates.”) Second, 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 
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give to the phrase “a source category” and leads to a third and 

fourth interpretation of the House amendment. 

In this context, a third interpretation of the Section 112 

Exclusions arises if one reads “a source category” to mean “any” 

source category. Under this third interpretation of the House 

amendment, CAA section 111(d) regulation is limited to air 

pollutants that are not emitted by any source category for which 

the EPA has issued standards for HAP under CAA section 112. But 

this interpretation would read CAA section 111(d) out of the 

statute. Given the extensive list of source categories regulated 

under CAA section 112 and the breadth of the pollutants emitted 

by those categories collectively, literally all air pollutants 

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

interpretation, because any given air pollutant is emitted by at 

least one source category for which the EPA has issued standards 

for HAP under the mandate of CAA section 112. Based on the 

principle that statutes should be interpreted such that all 

parts of it have meaning, see, e.g., Mountain States Tel. & Tel. 

v. Pueblo of Santa Anna, 472 U.S. 237, 249 (1985), the EPA 

concludes this is not a reasonable interpretation of the House 

amendment. 

A fourth interpretation would read the words “a source 

category” to mean the particular source category, again without 
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regard to the scope of pollutants that are regulated under CAA 

section 112, and interpret the House amendment to preclude the 

regulation under CAA section 111(d) of a specific source 

category for any pollutant if that source category has been 

regulated for any HAP under CAA section 112. 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 hazardous air pollutants 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. But, after considering all of the comments 

and reconsidering this interpretation, the EPA has concluded 

that this interpretation of the Section 112 Exclusion as amended 

by just the House amendment is not a reasonable reading because 

it would disrupt the comprehensive scheme for regulating 

existing sources created by the three sets of provisions 

covering criteria pollutants, hazardous air pollutants and the 

other pollutants that fall outside of those two programs.227 

 

227 In assessing any interpretation of section 111(d), EPA must 

consider how the three main programs set forth in the CAA work 
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Specifically, under this fourth interpretation, the EPA could 

not both (a) regulate a source category’s emissions of hazardous 

air pollutants under CAA section 112, and (b) regulate that 

category’s other pollutants under section 111(d). 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 nonhazardous pollutants under section 7411. 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 and subcategories, 42 U.S.C. 

§§ 7412(c)(1) and (c)(2), the EPA has listed and regulated over 

140 categories of sources under CAA section 112. Thus, similar 

to the third reading above, this reading would prevent section 

111(d) from serving as the gap-filling provision within the 

comprehensive scheme of the CAA. For these reasons, and as 

further discussed [below/in the Response to Comments], it is not 

 

together. See UARG, 134 S. Ct. at 2442 (a “reasonable statutory 

interpretation must account for . . . the broader context of the 

statute as a whole”) (quotation omitted). 
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reasonable to interpret the CAA 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 eliminate regulation of non-hazardous emissions from 

that source category under section 111(d).228

b. The EPA’s Interpretation of the House Amendment. Having 

concluded that the interpretations discussed above are not 

reasonable, the EPA has identified three reasonable 

interpretations of the House amendment. 

First, one could interpret the House amendment to mean that 

the Section 112 Exclusion excludes the regulation of HAP if the 

source category at issue is regulated under CAA section 112, but 

does not exclude the regulation of other pollutants, regardless 

 

228 Some commenters have stated that EPA could chose to regulate 

both HAP and non-HAP under section 111(d), and thus could 

regulate HAP without creating a gap. But this presumes that 

Congress intended EPA to have the choice of declining to 

regulate a section 112-listed source category for HAP under 

section 112, which is inconsistent with the mandatory language 

in section 112. See, e.g., section 112(d)(1)(“The Administrator 

shall promulgate regulations establishing emissions standards 

for each category or subcategory of major sources and area 

sources of hazardous air pollutants listed for regulation 

pursuant to subsection (c) of this section in accordance with 

the schedules provided in subsections (c) and (e) of this 

section.”). Moreover, given the prescriptive language that 

Congress added into section 112 concerning how to set standards 

for HAP, see section 112(d)(2) and (d)(3), it is unreasonable 

to conclude that Congress intended that EPA could simply choose 

to ignore the provisions in section 112 and instead regulate HAP 

for a section 112 listed source category under section 111(d). 
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of whether that source category is subject to CAA section 112 

standards. This interpretation reads the phrase “regulated under 

section 112” as modifying the words “source category” (as does 

the fourth interpretation discussed above) but also recognizes 

that the phrase “regulated under section 112” refers to the 

regulation of HAP emissions. In other words, this 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 first reasonable interpretation 

of the House amendment alone is the same as the 2005 CAMR 

interpretation of the two amendments combined: where a source 

category has been regulated under CAA section 112, a CAA section 

111(d) standard of performance cannot be established to address 

any HAP listed under CAA section 112(b) that may be emitted from 

that particular source category. See 70 FR 15994, 16029-30 

(March 29, 2005). 

Second, one could interpret the House amendment to mean 

that the Section 112 Exclusion always excludes the regulation of 

CAA section 112 pollutants, but does not exclude other 
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pollutants, and the scope of the exclusion is the same 

regardless of whether the source category is subject to 

standards under CAA section 112. This interpretation of the 

House amendment reads the phrase “regulated under section 112” 

as modifying “air pollutant” rather than “source category” and 

reads the phrase “emitted by a source category” as having 

minimal import because it is the remnant of phrasing that was 

originally intended to be an exclusion within CAA section 112 

for source categories regulated under section 111.229 A key 

 

229 Originally, when the House bill to amend the CAA was 

introduced in January 1989, it focused on amendments to control 

HAP. Of particular note, the amendments to CAA section 112 

included a provision that excluded regulation under section 112 

of “[a]ny air pollutant which is included on the list under 

section 108(a), or which is regulated for a source category 

under CAA section 111(d).” H.R. 4, § 2 (Jan. 3, 1989), 1990 CAA 

Legist. Hist. at 4046. In other words, the Section 112 Exclusion 

in CAA section 111(d) that was ultimately contained in the House 

amendment was originally crafted as what might be called a 

“Section 111(d) Exclusion” in CAA section 112. This is 

significant because the “source category” phrasing in the 

original January 1989 text with respect to CAA section 111(d) 

makes sense, whereas the “source category” phrasing in the 1990 

House amendment does not. When referring to the scope of what is 

regulated under section 111(d), it makes sense to frame that 

scope with respect to source categories, because CAA section 111 

regulation begins with the identification of source categories 

under CAA section 111(b)(1)(A). By contrast, regulation under CAA

section 112 begins with the identification of HAP under CAA 

section 112(b); the listing of source categories under section 

112(c) is secondary to the listing of HAP. From this history, 

and in light of this difference between the scope of what is 

regulated in CAA sections 111 and 112, it is reasonable to 

conclude that the “source category” phrasing is a legacy from 

the original 1989 bill—that is, when converting the 1989 text 
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distinction between this second reasonable interpretation and 

the first reasonable interpretation discussed above is that this 

second reasonable interpretation concludes that HAP can never be 

regulated under CAA section 111(d). 

Third, one could interpret the House amendment to mean that 

the Section 112 Exclusion excludes all of the CAA section 112 

pollutants that have actually been regulated for at least one 

source category under CAA section 112, but does not exclude 

other pollutants (that is, pollutants that are not listed under 

CAA section 112). This third reasonable interpretation reads the 

phrase “a source category” as meaning “any” source category 

listed under section 112 and the phrase “regulated under section 

112” in light of the fact that a source category is “regulated 

under 112” with respect to HAP and not other pollutants. Thus, 

under this third reasonable interpretation of the House 

amendment, the scope of the Section 112 Exclusion does not cover 

non-HAP. 

These three interpretations share a number of common 

reasons why they are reasonable and avoid the issues discussed 

above. 

 

into the Section 112 Exclusion that we see in the 1990 House 

amendment, the legislative drafters continued to use phrasing 

based on “source category” notwithstanding that this phrasing 

created a mismatch with the way that the scope of CAA section 

112 regulation is determined. 
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First, all three of these reasonable interpretations read 

the House amendment to the Section 112 Exclusion as determining 

the scope of what air pollutants are 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 Exclusion to do also address the question of what 

air pollutants may be regulated under CAA section 111(d) is 

consistent with the overall nature of the text in which it 

appears. 

Second, all three reasonable interpretations further – 

rather than undermine – the purpose of CAA section 111(d) within 

the long-standing structure of the CAA. That is, these 

interpretations support 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. 

Third, by avoiding the creation of gaps in the statutory 

structure, all three interpretations are 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.230 Conversely, the 

the EPA is aware of no statement in the legislative history 

indicating that Congress simultaneously sought to restrict the 

EPA’s authority under CAA section 111(d) or to create gaps in 

the comprehensive structure of the statute. If Congress had 

intended this amendment to make such a change, one would expect 

to see some indication of that in the legislative history. 

Fourth, when applied in the context of this rule, all three 

of these reasonable interpretations of the House amendment are 

consistent with the Senate amendment. Thus, these 

interpretations in this context avoid creating a conflict within 

the statute and fulfill that principle of statutory 

construction. See discussion above of Scialabba, 134 S. Ct. 2191 

 

230 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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at 2220 (citing and quoting, among other authorities, A. Scalia 

& B. Garner, Reading Law: The Interpretation of Legal Texts 180 

(2012) (“The provisions of a text should be interpreted in a way 

that renders them compatible, not contradictory. . . . [T]here 

can be no justification for needlessly rendering provisions in 

conflict if they can be interpreted harmoniously”)). 

In sum, when either of these three reasonable 

interpretations of the House amendment is applied in the context 

of this rule, each interpretation reaches the same result: the 

EPA may promulgate CAA section 111(d) regulations covering 

carbon dioxide emissions from existing power plants 

notwithstanding that power plants are regulated for their HAP 

emissions under CAA section 112. Thus, in the context of this 

rule, the EPA does not need to decide which of these three 

reasonable interpretations is better. 

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) 

allows the EPA to regulate non-HAP from a source category 

regardless of whether that source category is also regulated 
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under CAA section 112. Thus, the EPA has the authority to 

regulate CO2 from power plants notwithstanding that power plants 

are regulated for HAP under CAA section 112. 

C. Authority to Regulate EGUs 

In a separate, concurrent action, the EPA is also 

finalizing two CAA section 111(b) rulemakings, one that 

regulates CO2 emissions from new EGUs and another that regulates 

CO2 emissions from modified and reconstructed EGUs. The 

promulgation of either of these is 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 
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“reconstruction,” which the implementing regulations go on to 

define as the replacement of components of an existing facility 

to an extent that (i) the fixed capital cost of the new 

components exceeds 50 percent of the fixed capital cost that 

would be required to construct a comparable entirely new 

facility, and (ii) it is technologically and economically 

feasible to meet the applicable standards. 

 Under CAA section 111(d)(1), in order for existing sources 

to become subject to that provision, the EPA must promulgate 

standards of performance under CAA section 111(b) to which, if 

the existing sources were new sources, they would be subject. 

Those standards of performance may include standards for sources 

that undertake new construction, modifications, or 

reconstructions. 

The EPA is finalizing two rulemakings 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).231

D. Definition of Affected Sources 

 

231 In the past, the EPA has issued standards of performance 

under section 111(b) and emission guidelines under section 

111(d) simultaneously. See “Standards of Performance for new 

Stationary Sources and Guidelines for Control of Existing 

Sources: Municipal Solid Waste Landfills – Final Rule,” 61 Fed. 

Reg. 9905 (March 12, 1996). 
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For the emission guidelines, an affected EGU is any steam 

generating unit, IGCC, or stationary combustion turbine that was 

in operation or had commenced construction as of January 8, 

2014,232 and that meets the following criteria, which differ 

depending on the type of unit. To be an affected source, such a 

unit, if it is a steam generating unit or IGCC, 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 

 

232 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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stationary combustion turbine itself. Combined cycle combustion 

turbine means any stationary combustion turbine which recovers 

heat from the combustion turbine engine exhaust gases to 

generate steam that is used to create additional electric power 

output in a steam turbine. Combined heat and power (CHP) 

combustion turbine means any stationary combustion turbine which 

recovers heat from the combustion turbine engine exhaust gases 

to heat water or another medium, generate steam for useful 

purposes other than exclusively for additional electric 

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 those that (1) are subject to subpart 

TTTT as a result of commencing modification or reconstruction; 

(2) steam generating units or IGCC units that are currently and 

always have been subject to a federally enforceable permit 

limiting net-electric sales to one-third or less of its 

potential electric output or 219,000 MWh or less on an annual 

basis; (3) non-fossil units (i.e., units that are capable of 

combusting 50 percent or more non-fossil fuel) that have 

historically limited the use of fossil fuels to 10 percent or 

less of the annual capacity factor or are subject to a federally 
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enforceable permit limiting fossil fuel use to 10 percent or 

less of the annual capacity factor; (4) stationary combustion 

turbines that are not capable of combusting natural gas (i.e., 

not connected to a natural gas pipeline); (5) are a combined 

heat and power unit 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) serve 

a generator along with other steam generating unit(s), IGCC(s), 

or stationary combustion turbine(s) where the effective 

generation capacity (determined based on a prorated output of 

the base load rating of each steam generating unit, IGCC, or 

stationary combustion turbine) is 25 MW or less; (7) are a 

municipal waste combustor unit subject to subpart Eb of Part 60; 

or (8) are a commercial or industrial solid waste incineration 

unit that is subject to subpart CCCC of Part 60.

The rationale for applicability of this final rule is 

multi-fold. We had proposed that affected EGUs were those 

existing source fossil fuel-fired EGUs that met the 

applicability criteria for coverage under the final GHG 

standards for new fossil fuel-fired EGUs being promulgated under 

section 111(b). However, we are finalizing that States need not 
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include certain units that would otherwise meet the CAA section 

111(b) applicability in this CAA section 111(d) emission 

guidelines. These include simple cycle turbines, certain nonfossil units, and certain combined heat and power units. The 

final 111(b) standards include applicability criteria for simple 

cycle combustion turbines, for reasons relating to 

implementation and minimizing emissions from all future 

combustion turbines. However, for the following reasons none of 

the building blocks would apply to simple cycle turbines so we 

are not requiring that States including them in their CAA 

section 111(d) plans. First, even more than combined cycle 

units, simple cycle units have limited opportunities, compared 

to steam generating units, to reduce their heat rate. Further, 

we have not evaluated any opportunities that existing simple 

cycle have to reduce their heat rate. Therefore, nothing would 

be required of simple cycle units under building block 1. 

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 
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be available to serve as peaking units. Therefore, building 

block 2 would not apply to simple cycle units. 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, building block 

3 would not apply to 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, 

it would not impact the stringency of the plans. Such inclusion 

would increase burden but result in no environmental benefit. 

Finally, 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 
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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 two existing 

categories for the affected EGUs into a single category for 

purposes of 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 electric utility steam generating units, as well as 

natural gas-fired stationary combustion turbines -- in that 

newly created subpart.233

We believe that combining the emission guidelines for 

affected sources into a new subpart UUUU is appropriate because 

the emission guidelines the EPA is establishing do not vary by 

type of source. Combining the two categories will facilitate 

implementation of CO2 mitigation measures, such as shifting 

generation from higher to lower-carbon intensity generation 

 

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

rulemaking in subparts Da or KKKK. 
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among existing sources (e.g., shifting from utility boilers to 

NGCC units), and emission trading among sources in both 

categories. 

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 

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 
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codifying the final requirements in a new 40 CFR part 60 subpart 

TTTT. 

In this rulemaking, the EPA is combining the two categories 

into a single category for purposes of the CO2 emissions from 

existing affected EGUs. Because the two categories are preexisting and the EPA would not be subjecting any additional 

sources to regulation, the combined category is not considered a 

new category that the EPA must list under CAA section 

111(b)(1)(A). As a result, this final rule does not list a new 

category under section 111(a)(1)(A), nor does this final rule 

revise either of the two source categories – steam-generating 

boilers and combustion turbines – that the EPA has already 

listed under that provision. Thus, the EPA is not required to 

make a finding that the combined category causes or contributes 

significantly to air pollution which may reasonably be 

anticipated to endanger public health or welfare. 

V. The Best System of Emission Reduction and Associated Building 

Blocks 

 In the June 2014 proposal, the EPA proposed to determine 

that the best system of emission reduction adequately 

demonstrated (BSER) for reducing CO2 emissions from existing EGUs 

was a combination of measures –- (1) increasing the operational 

efficiency of existing coal-fired steam EGUs, (2) substituting 
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increased generation at existing NGCC units for generation at 

existing steam EGUs, (3) substituting generation from low- and 

zero-carbon generating capacity for generation at existing 

fossil fuel-fired EGUs, and (4) increasing demand-side energy 

efficiency to reduce the amount of fossil fuel-fired generation 

–- which we categorized as four “building blocks.” As an 

alternative to the proposed building blocks 2, 3, and 4, the EPA 

also identified reduced generation in the amount of those 

building blocks as part of the BSER. These measures are not the 

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 

other approaches. We have considered thoroughly the extensive 

comments submitted on a variety of topics related to the BSER 

and the individual building blocks, along with our own continued 

analysis, and we are finalizing the BSER based on the first 

three building blocks, with certain refinements. 

 Consistent with the approach taken in the proposed rule, in 

determining the BSER we have taken account of the global nature 

of CO2 pollution and the unique characteristics of the source 

category, particularly the exceptional degree of 

interconnectedness among individual affected sources and the 

longstanding practice of coordinating planning and operations 
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across multiple sources. Each building block is a proven 

approach for reducing emissions from the affected source 

category that is appropriate in this pollutant- and industryspecific context. Each building block also encompasses a variety 

of actions that individual affected sources may take, including 

direct investment in efficiency improvements and in lower- and 

zero-carbon generation, cross-investment in these activities 

through mechanisms such as emissions trading or other multi-unit 

compliance approaches, and reduction of higher-carbon 

generation. 

 With attention to costs 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, nonbuilding block specific aspects of the BSER quantification 

methodology discussed below are similarly conservative. 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. The wide range 

of actions encompassed in the building blocks, and a further 

wide range of possible emissions-reducing actions not included 
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in the BSER but nevertheless available to help with compliance, 

ensure that the BSER is achievable by individual affected 

sources as well. 

 The final BSER reflects certain changes from the proposed 

rule, reflecting consideration of comments received and further 

analysis. The principal changes are the exclusion from the BSER 

of emission reductions achievable through demand-side energy 

efficiency and through nuclear generation; a revised approach to 

determination of emission reductions achievable through 

increased renewable energy generation, based on an alternate 

approach on which we solicited comment in the proposed rule; a 

consistent approach to determination of emission reductions 

achievable through all the building blocks that better reflects 

the regional nature of the electricity system; and 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 in response to 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, 
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the final rule also provides weighted-average state-specific 

goals that a state may choose as an alternative to the 

nationwide subcategory-based CO2 emission performance rates. The 

change to uniform CO2 emission performance rates is discussed in 

this section and in section VI of the preamble, and the relation 

of the performance rates to the state-specific goals and states’ 

section 111(d) plan options is discussed in sections VII and 

VIII of the preamble. 

 Section V.A. describes our determination of the final BSER, 

including a discussion of the associated emissions performance 

level, and provides the rationale for our determination. In 

section V.B. we address certain legal issues in greater detail, 

including key issues raised in comments. Sections V.C. through 

V.E. contain more detailed discussions of the three individual 

building blocks included in the final BSER. Further information 

can be found in the Legal Memorandum for the CPP Final Rule, the 

GHG Mitigation Measures TSD for the CPP Final Rule, the CO2

Emission Performance Rate and Goal Computation TSD for the CPP 

Final Rule, the Rate-based Program Accounting TSD for the CPP 

Final Rule, and the Response to Comments document, all of which 

are available in the docket. 

A. The Best System of Emission Reduction 
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 This section sets forth our determination of the BSER for 

reducing CO2 emissions from existing EGUs, including a discussion 

of the associated emissions performance level, and the rationale 

for that determination. In section V.A.1., we describe the legal 

framework for determination of the BSER in general. Section 

V.A.2. summarizes the determination of the BSER for this rule. 

In section V.A.3., we discuss changes from the proposal. Section 

V.A.4. provides more detail on our determination of the BSER, 

including our determinations regarding the individual elements 

of the BSER, viewed from the perspective of the overall category 

of affected sources. In section V.A.5. we discuss the BSER from 

a second perspective, comprising the range of actions that 

individual affected sources may take to achieve the EPAidentified performance levels that reflect the BSER and that 

form the basis for the standards of performance that states must 

set. 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 sources can use to achieve their standards 
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of performance. Finally, section V.A.7. addresses 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 requirement for standards of 

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

description in part on our discussion of the legal requirements 

for standards of performance under CAA section 111(b) and 

(a)(1), which we included in the January 2014 proposal for 

standards of performance for CO2 emissions from new 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.234

We received comments on our proposed interpretation, and in 

light of those comments, in this rule, we are clarifying our 

interpretation in certain respects. We discuss our 

interpretation below.235 

 

234 79 FR 1430, 1462 (January 8, 2014). 

235

 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. Our interpretations of 

these requirements in the two rules are generally consistent 

except to the extent that they reflect distinctions between new 
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b. CAA requirements and court interpretation. Section 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 

 

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. 
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CAA requirements, the EPA’s regulations require that the EPA’s 

guidelines reflect-- 

the degree of emission reduction achievable through the 

application of the best system of emission reduction which 

(taking into account the cost of such reduction) the 

Administrator has determined has been adequately demonstrated.236 

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

BSER on a source category-wide basis, to determine the emission 

limitation that results from applying the BSER to the sources, 

and then to establish emission guidelines that incorporate those 

emission limitations. The EPA expresses these emission 

limitations in the form of the performance levels, and they must 

be achievable by the source category. However, the state has 

broad discretion in applying the standards of performance to its 

sources. That is, for any particular source, a state may apply a 

standard of performance that is either more stringent or less 

stringent than the EPA’s performance level, 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 

 

236 40 C.F.R. § 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). 
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guidelines.237 

The states must include the standards of performance in 

their state plans and submit the plans to the EPA for review.238

Section 111(d)(2) authorizes the EPA to approve state plans as 

long as they are “satisfactory.” Under the EPA’s regulations, 

state plans must include emission standards and compliance 

schedules for all “designated facilities” within the state, and 

may, “[o]n a case-by-case basis for particular designated 

facilities, or classes of facilities, ... provide for the 

application of less stringent emission standards or longer 

compliance schedules than those otherwise required” by the 

corresponding emission guideline.239 This variance provision, 

promulgated in 1976, in conjunction with CAA section 111(d)’s 

“remaining useful life” provision, allows the states to vary the 

emission reduction obligations for their sources. 

 

237 In addition, under CAA section 116, the state is authorized 

to set a standard of performance for any particular source that 

is more stringent than the BSER, and for all of its sources that 

is more stringent than the EPA’s performance level. Further, the 

state may consider remaining useful life and other factors in 

applying a standard of performance to a source, as discussed 

below. 

238 40 C.F.R. § 60.23. 

239 40 C.F.R. § 60.24(f). Some of the factors that a state may 

consider for this case-by-case analysis include the “cost of 

control resulting from plant age, location, or basic process 

design” and the “physical impossibility of installing necessary 

control equipment,” among other factors “that make application 

of a less stringent standard or final compliance time 

significantly more reasonable.” Id.
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As noted in the January 2014 proposal and discussed in more 

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

definition of “standard of performance” when enacting CAA 

section 111 in the 1970 Clean Air Act Amendments (CAAA), amended 

it in the 1977 CAAA, and then amended it again in the 1990 CAAA 

to largely restore the definition as it read in the 1970 CAAA. 

It is in the legislative history for the 1970 and 1977 CAAA that 

Congress primarily addressed the definition as it read at those 

times and that legislative history provides guidance in 

interpreting this provision.240 In addition, although the D.C. 

 

240 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 
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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 2011,241 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 the EPA 

determines to be the “best” that is “adequately demonstrated,” 

“taking into account ... 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 

 

provisions with the terms used in the 1970 CAAA version of 

§111(a)(1) that the standard of performance be based on the 

“best system of emission reduction ... adequately demonstrated.” 

This 1990 CAAA version is the current definition, which is 

applicable at present. Even so, because parts of the definition 

as it read under the 1977 CAAA were retained in the 1990 CAAA, 

the explanation in the 1977 CAAA legislative history, and the 

interpretation in the case law, of those parts of the definition 

in the case law remain relevant to the definition as it reads 

today. 

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

1973); Essex Chemical Corp. v. Ruckelshaus, 486 F.2d 427, (D.C. 

Cir. 1973); Portland Cement Ass’n v. EPA, 665 F.3d 177 (D.C. 

Cir. 2011). See also Delaware v. EPA, No. 13-1093 (D.C. Cir. May 

1, 2015). 
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also take into account “the amount of air pollution”242 reduced 

and the role of “technological innovation.”243 

Before turning to each of these elements below, we discuss 

our overall approach to determining the BSER and emission 

guidelines more generally. 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 emission reduction systems that have been 

“adequately demonstrated” for a particular source category. 

Second, we determine the best of these systems after evaluating 

costs, any nonair health and environmental impacts, and energy 

requirements. And third, we select an achievable emission limit 

–- here, the emission performance standard -- based on the BSER. 

(1) Achievability of the emission limitation in the 

emission guidelines. 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. For existing sources, section 111(d)(1) 

requires the EPA to establish requirements for state plans that 

 

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

1981). 

243 See Sierra Club v. Costle, 657 F.2d at 347. 
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must include “standards of performance.” Through long-standing 

regulations244 and consistent practice, the EPA has interpreted 

this provision to require the EPA to promulgate emission 

guidelines that determine the BSER for a source category and 

that identify the amount of emission limitation achievable by 

application of the BSER. 

Although section 111(d)(1) and (a)(1) are not explicit on 

whether the emission limitation must be achievable by each 

source in the source category, the EPA has promulgated these 

emission guidelines on the basis that each source can achieve 

the limitation, even though the State retains discretion to 

apply standards of performance to individual sources that are 

more or less stringent. By comparison, in a rulemaking for new 

sources under section 111(b), the EPA must promulgate the 

“standards of performance” directly, and the first element of 

the definition of “standard of performance” is that the emission 

limitation reflected in the “standard for emissions” that the 

EPA promulgates must be “achievable” based on application of the 

BSER. 79 FR 1430, 1463 (January 8, 2014). Moreover, again, for 

new sources, a standard of performance is “achievable” if a 

technology can reasonably be projected to be available to an 

 

244 40 C.F.R. § 60.21(e). 
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individual source at the time it is constructed that will allow 

it to meet the standard.245 In this rulemaking, we are taking the 

same approach for the emission limitation that the EPA 

identifies in the emission guidelines. 

According to the D.C. Circuit, ”[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.”246

To be achievable, a standard “must be capable of being met under 

most adverse conditions which can be reasonably be expected to 

recur and which are not or cannot be taken into account in 

determining the ‘cost of compliance.’”247 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 

 

245 246 Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433-34 (D.C. 

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

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

1980). 
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standard.”248

(2) System of emission reduction. As we discuss below, the 

CAA does not define the phrase “system of emission reduction.” 

The ordinary, everyday meaning of “system” is “a set of things 

working together as parts of a mechanism or interconnecting 

network; a complex whole.”249 With this definition, the phrase 

“system of emission reduction” takes a broad meaning: a set of 

things that work together to reduce emissions. The EPA 

interprets this phrase to carry an important limitation: Because 

the emission guidelines for the existing sources must reflect 

“the degree of emission limitation achievable through the

application of the best system of emission reduction ... 

adequately demonstrated,” the system must be limited to things 

that can be implemented – “appl[ied]” -- by the sources 

themselves, that is, as a practical matter, by actions taken by 

 

248 Sierra Club v. Costle, 657 F.2d 298, 377 (D.C. Cir. 1981) 

(citing Nat’l Lime Ass’n v. EPA, 627 F.2d 416 (D.C. Cir. 1980). 

In considering the representativeness of the source tested, the 

EPA may consider such variables as the “‘feedstock, operation, 

size and age’ of the source.” Nat’l Lime Ass’n v. EPA, 627 F.2d 

416, 433 (D.C. Cir. 1980). Moreover, it may be sufficient to 

“generalize from a sample of one when one is the only available 

sample, or when that one is shown to be representative of the 

regulated industry along relevant parameters.” Nat’l Lime Ass’n 

v. EPA, 627 F.2d 416, 434, n.52 (D.C. Cir. 1980). 

249

Oxford Dictionary of English (3rd ed.) (published 2010, online 

version 2013) 

http://www.oxfordreference.com.mutex.gmu.edu/view/10.1093/acref/

9780199571123.001.0001/acref-9780199571123. 
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the owners or operators of the sources. As we discuss below, 

this definition is sufficiently broad to include the building 

blocks. 

(3) Technical feasibility of the best system of emission 

reduction. As indicated in the proposed rulemakings for this 

rule and the associated section 111(b) rule, the requirement 

that the emission limitation in the emission guidelines be 

“achievable” based on the “best system of emission reduction ... 

adequately demonstrated” indicates that the technology or other 

measures that the EPA identifies as the BSER must be technically 

feasible. See 79 FR 1430, 1463 (January 8, 2014). 

(4) Amount of emissions reductions. In the proposed 

rulemakings for this rule and the associated section 111(b) 

rule, we noted that although the definition of “standard of 

performance” does not by its terms identify the amount of 

emissions from the category of sources or the amount of emission 

reductions achieved as factors the EPA must consider in 

determining the “best system of emission reduction,” the D.C. 

Circuit has stated that the EPA must do so. See Sierra Club v. 

Costle, 657 F.2d 298, 326 (D.C. Cir. 1981) (“we can think of no 

sensible interpretation of the statutory words “best ... system” 

which would not incorporate the amount of air pollution as a 

relevant factor to be weighed when determining the optimal 
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standard for controlling ... emissions”).250 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 

under Chevron step 2 to allow that discretion. 

(5) Costs. Under CAA section 111(a)(1), the EPA is required 

to take into account “the cost of achieving” the required 

emission reductions. As described in the January 2014 

proposal,251 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 

 

250 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” to read, 

“best technological system.” As noted above, the 1990 CAAA 

deleted “technological,” and thereby returned the phrase to how 

it read under the 1970 CAAA. The court’s interpretation of this 

phrase in Sierra Club v. Costle to require consideration of the 

amount of air emissions remains valid for the phrase “best 

system.” 

251 79 FR 1430, 1464 (January 8, 2014). 
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which would be “exorbitant,”252 “greater than the industry could 

bear and survive,”253 “excessive,”254 or “unreasonable.”255 These 

formulations appear to be synonymous, and for convenience, in 

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

that a control technology may be considered the “best system of 

emission reduction ... adequately demonstrated” if its costs are 

reasonable, but cannot be considered the best system if its 

costs are unreasonable.256 

 

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

1999). 

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

1975). 

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

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

256 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. 
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The D.C. Circuit has never invalidated a standard of 

performance on grounds that it was too costly. In several cases, 

the Court upheld standards that entailed significant costs, 

consistent with Congress’s view that “the costs of applying best 

practicable control technology be considered by the owner of a 

large new source of pollution as a normal and proper expense of 

doing business.”257 See Essex Chemical Corp. v. Ruckelshaus, 486 

F.2d 427, 440 (D.C. Cir. 1973);258 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”).259 

As discussed below, the EPA may consider costs on both a 

source-specific basis and a sector-wide, regional, or nationwide 

 

S. Comm. Rep. No. 91-1196 at 16. 

257 1977 House Committee Report at 184. 

258 The costs for these standards were described in the 

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

5769 (March 21, 1972). 

259 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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basis. 

(6) Non-air health and environmental impacts. Under CAA 

section 111(a)(1), the EPA is required to take into account “any 

nonair quality health and environmental impact” in determining 

the BSER and whether it is adequately demonstrated. This 

requirement makes explicit what was implicit in the initial 

version of section 111: a system cannot be “best” if it does 

more harm than good due to cross-media environmental impacts.260

(7) Energy considerations. Under CAA section 111(a)(1), the 

EPA is required to take into account “energy requirements.” As 

discussed below, the EPA may consider energy requirements on 

both a source-specific basis and a sector-wide, region-wide, or 

nationwide basis. Considered on a source-specific basis, “energy 

requirements” entails, for example, the impact, if any, of the 

system of emission reduction on the source’s own energy needs. 

(8) Sector- or nationwide component of factors in 

determining the BSER. As discussed in the January 2014 proposal, 

another component of the D.C. Circuit’s interpretations of CAA 

section 111 is that the EPA may consider the various factors it 

is required to consider on a national or regional level and over 

 

260 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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time, and not only on a plant-specific level at the time of the 

rulemaking.261 The D.C. Circuit based this conclusion on a review 

of the legislative history, stating, 

The Conferees defined the best technology in terms of 

“long-term growth,” “long-term cost savings,” effects on 

the “coal market,” including prices and utilization of coal 

reserves, and “incentives for improved technology.” Indeed, 

the Reports from both Houses on the Senate and House bills 

illustrate very clearly that Congress itself was using a 

long-term lens with a broad focus on future costs, 

environmental and energy effects of different technological 

systems when it discussed section 111.262

 

The Court has upheld EPA rules that the EPA “justified ... in 

terms of the policies of the Act,” including balancing long-term 

national and regional impacts: 

The standard reflects a balance in environmental, 

economic, and energy consideration by being sufficiently 

stringent to bring about substantial reductions in SO2

emissions (3 million tons in 1995) yet does so at 

reasonable costs without significant energy penalties.... 

By achieving a balanced coal demand within the utility 

sector and by promoting the development of less expensive 

SO2 control technology, the final standard will expand 

environmentally acceptable energy supplies to existing 

power plants and industrial sources. 

By substantially reducing SO2 emissions, the standard 

will enhance the potential for long term economic growth at 

both the national and regional levels.263

 

261

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

Costle, 657 F.2d at 351). 

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

(citing legislative history).

263 Sierra Club v. Costle, 657 F.2d at 327-28 (quoting 44 Fed. 

Reg. at 33,583/3 - 33,584/1). In the January 2014 proposal, we 

explained that although the D.C. Circuit decided Sierra Club v. 
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As with the final rule under section 111(b) that is 

associated with this rule, the EPA is considering costs and 

energy implications on the basis of both their sourcespecific impacts and a sector-wide, regional, or national 

basis. 

(9) “Adequately demonstrated.” Under section 111(a)(1), in 

order for a system of emission reduction to qualify as the 

“best” and to serve as the basis for an “achievable” emission 

limitation, the Administrator must determine that the system is 

“adequately demonstrated.” This means, according to the D.C. 

Circuit, that the system is “one which has been shown to be 

reasonably reliable, reasonably efficient, and which can 

reasonably be expected to serve the interests of pollution 

control without becoming exorbitantly costly in an economic or 

environmental way.”264 It does not mean that the system “must be 

in actual routine use somewhere.”265 Rather, the court has said, 

“[t]he Administrator may make a projection based on existing 

 

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). 

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

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

265 Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 391 

(D.C. Cir. 1973) (citations omitted) (discussing the Senate and 

House bills and reports from which the language in CAA section 

111 grew). 
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technology, though that projection is subject to the restraints 

of reasonableness and cannot be based on ‘crystal ball’ 

inquiry.”266 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.”267 Ultimately, the analysis “is partially dependent on 

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

have to be available.”268 Unlike for CAA section 111(b) standards 

that are immediately applicable, compliance with CAA section 

111(d) standards may be set sometime in the future. 

(10) 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.269 In 

 

266

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

Cir. 1973) (citations omitted). 

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

268

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

Cir. 1973) (citations omitted). 

269 Sierra Club v. Costle, 657 F. 2d at 346 (“Our interpretation 

of section 111(a) is that the mandated balancing of cost, 
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addition, the Court’s interpretation finds firm support in the 

legislative history.270 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);271 (ii) the 

expanded use of the best demonstrated technology;272 and (iii) 

the development of emerging technology.273 Even if the EPA were 

not required to consider technological innovation as part of its 

 

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.”). 

270 See S. Rep. 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. 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”). 

271 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”). 

272 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”). 

273 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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determination of the BSER, it would be reasonable for the EPA to 

consider it, either because technological innovation may be 

considered an element of the term “best,” or because the term 

“best system of emission reduction” is ambiguous as to whether 

technological innovation may be considered, and it is reasonable 

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 technologies identified in this rule as the BSER even 

without considering the factor of incentivizing technological 

innovation or development. 

(11) Agency 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,”274 and emphasized that “[t]he text 

gives the EPA broad discretion to weigh different factors in 

 

274 Sierra Club v. Costle, 657 F.2d at 319. 
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setting the standard.”275 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 

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 111.276 

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 

 

275 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). 

276

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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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 discretion as to whether and, if so, how to 

subcategorize. In addition, the regulations under CAA section 

111(d) provide -- 

The Administrator will specify different emission 

guidelines or compliance times or both for different sizes, 

types, and classes of designated facilities when costs of 

the control, physical limitations, geographical location, 

or similar factors make subcategorization appropriate.277

 

 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, 

 

277 40 CFR 60.22(b)(5). 
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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, and the BSER is the 

central determination that the EPA must make in doing so. In 

understanding the EPA’s basis for the BSER, it is useful to view 

the BSER from two complementary perspectives. The first 

perspective considers the subcategory of the steam affected EGUs 

as a whole, and the subcategory of the combustion turbine 

affected EGUs as a whole, treats the BSER for each subcategory 

as the measures identified by the EPA that the sources, viewed 

together, can implement to reduce their emissions to an 

appropriate amount, and that meet the other requirements for the 

BSER including, for example, cost reasonableness. For 

convenience, this may be referred to as the source-category 

perspective because it views the BSER on a category- or 

subcategory-wide basis. 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. 
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The second perspective considers the affected EGUs 

individually, and treats the BSER as the set of actions that an 

EGU 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 other 

requirements for the BSER. For convenience, this may be referred 

to as the individual-source perspective. 

Under either perspective, the EPA determines the BSER as 

encompassing the same set of actions, but the two perspectives 

serve to elucidate the EPA’s reasoning. 

An 

 example illustrating the relationship between the sourcecategory and individual-source perspectives for this rule is the 

substitution of non-emitting generation for CO2-emitting 

generation. This measure involves two distinct actions: 

increasing the amount of non-emitting generation and reducing 

the amount of CO2-emitting generation. From the source-category 

perspective, the two actions are halves of a single balanced 

endeavor, but from the individual-source perspective, 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 
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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 sources to determine the performance levels 

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

generators and for combustion turbines. States must impose 

emission limits on their sources that, in total, achieve the 

same 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. 

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 assign the CO2 emission performance rates 

or the mass equivalents thereof to each of its affected EGUs. If 

a state does so, then the affected EGUs may achieve their 

emission limits by taking the actions that qualify as the BSER. 

Since the BSER and, in this case its constituent elements, 

reflect the critical criteria of feasibility, reasonable cost, 

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

one pathway –- the CO2 emission performance rates or mass 
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equivalents -- for the state and its affected EGUs to take that 

achieves the requisite level of emission reductions, while, 

again, assuring that the affected EGUs can achieve those 

emission limits at reasonable cost and consistent with the other 

factors for the BSER. 

This section describes the EPA’s process and basis for 

determining the BSER for the purpose of determining the CO2

emission performance rates.278 As noted above, the BSER 

determined through this process can be described from two 

perspectives. Viewed from the source-category perspective, the 

EPA is identifying the BSER as a well-established set of 

measures that EGUs have used for many years to achieve various 

business and policy purposes, and have used in recent years for 

the specific purpose of reducing their CO2 emissions, and that 

are appropriate to the global nature of carbon pollution and 

afforded by the highly integrated nature of the utility power 

sector. These measures include (i) increasing the operational 

efficiency of 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 

 

278 Other sections in this preamble describe how EPA calculated 

the CO2 emission performance rates based on the BSER. 
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block 2); and (iii) substituting increased generation from new 

zero-carbon generating capacity for reduced generation at 

existing fossil fuel-fired EGUs in specified amounts (building 

block 3). It should be noted that building block 2 incorporates 

reduced generation from steam EGUs on a source category-wide 

basis and building block 3 incorporates reduced generation from 

all fossil fuel-fired EGUs on a source category-wide basis. 

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 location on the interconnected electricity system. The 

range of mechanisms includes bilateral investment of various 

kinds, the issuance and purchase of emission rate credits 

representing the emissions-reducing effects of specific 

activities, more general emissions trading using rate-based 

credits or mass-based allowances, and other multi-unit 

compliance approaches such as averaging or bubbling.279

Viewed from the individual-source perspective, the EPA is 

identifying the BSER as a menu of actions -- all of which fall 

 

279 Conditions for the use of these mechanisms under various 

state plans are discussed in section VIII. 
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within the set of measures identified as the BSER from the 

source-category perspective -- that individual affected EGUs may 

implement in different amounts and combinations in order to 

achieve their emission limits at reasonable cost. This menu 

includes actions that (i) affected coal-fired steam EGUs can 

implement to improve their heat rates; (ii) affected steam EGUs 

can implement to increase generation from lower-emitting 

existing NGCC units in specified amounts, (iii) all affected 

EGUs can implement to increase generation from new low- or zerocarbon generation sources in specified amounts, (iv) all 

affected EGUs can implement to reduce their generation in 

specified amounts, and (v) all affected EGUs can implement by 

means of purchasing rate-based emission credits or mass-based 

emission allowances from other affected EGUs through trading, 

since the effect of the purchase would be the same as achieving 

the other listed actions through direct means, and (vi) all 

affected EGUs can implement through other multi-unit compliance 

approaches such as averaging or bubbling.280 

Importantly, viewed from either the source-category 

perspective or the individual-source perspective, affected EGUs 

also have available numerous other measures that are not 

 

280 Again, conditions for the use of these mechanisms under 

various state plans are discussed in section VIII. 
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included in the BSER but that could materially help the EGUs 

achieve their emission limits and thereby provide compliance 

flexibility. Examples include investment in demand-side energy 

efficiency, co-firing with natural gas (for coal-fired steam 

EGUs), and investment in new generating units using low- or 

zero-carbon generating technologies other than those that are 

part of building block 3. 

b. The EPA’s review of measures for determining the BSER. The 

EPA described in the proposal for this rule the analytical 

process by which the EPA determined the BSER for this source 

category. The EPA is finalizing large parts of that analysis, 

but the EPA is also refining that analysis based on comments and 

further evaluation. What follows is the EPA’s final 

determination. 

As described in the proposal, to determine the BSER, the 

EPA began by considering the characteristics of CO2 pollution and 

the utility power sector. The characteristics of CO2 pollution 

are discussed at length in the proposed rule and in section II 

above. The salient facts include the pollutant’s global nature, 

which makes the specific location of emission reductions 

unimportant; the need to make large reductions in order to 

protect human health and the environment; and fact that the 
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utility power sector is the single largest source category by a 

considerable margin. 

The characteristics of the utility power sector are also 

discussed at length in the proposal and in section II above. 

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 in both planning and realtime system operation among the owners and operators of the 

facilities comprised within each of the three large electrical 

interconnections covering the contiguous 48 states. Given these 

unique characteristics, it is not surprising that the North 

American power system has been characterized as a “complex 

machine.”281 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 

 

281 S. Massoud Amin, Securing the Electricity Grid, 40 The Bridge 

1, 14 (2010); Phillip F. Schewe, The Grid: A Journey Through the 

Heart of Our Electrified World 1 (2007). 
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of environmental impacts are also carried out to a great extent 

on a multi-unit basis rather than an individual-unit 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. It is evident that, in the recent past, coal-fired 

electricity generation has been reduced, and projected future 

trends are for continued reduction. By the same token, loweremitting NGCC generation and renewable generation have 

increased, and projected future trends are for continued 

increases.282 A survey of integrated resource plans (IRPs), 

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

are taking actions to reduce emissions of both non-GHG air 

pollutants and GHGs.283 Some fossil fuel-fired EGUs are investing 

in lower- or zero-emitting generation. In fact, our review 

indicates that the great majority of fossil fuel-fired 

generators surveyed are including new renewable energy resources 

 

282 Demand-side energy efficiency measures have also increased, 

and the projected future trends are for continued increase. 

283 The IRPs typically also indicate planned investment in 

demand-side energy efficiency. 
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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 higher-emitting generation without fully 

replacing it. These measures in aggregate result in the 

replacement of higher-emitting generation with lower- or zeroemitting generation, reflecting the integrated nature of the 

electricity system. 

The EPA examined state and company programs intended at 

least in part to reduce CO2 from fossil fuel-fired power plants. 

These programs include GHG performance standards established by 

states including California, New York, Oregon, and Washington; 

utility planning approaches carried out by companies in Colorado 

and Minnesota; and renewable portfolio standards (RPS) 

established in more than 25 states.284 They also include marketbased initiatives, such as the Regional Greenhouse Gas 

Initiative (RGGI) and the GHG emissions trading program 

established by the California Global Warming Solutions Act. 

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 

 

284 See 79 FR 34848-34850. 
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to reduce SO2 and NOX, the MATS program to reduce mercury and air 

toxic emissions, and the CSAPR program to reduce SO2 and NOX.285

This analysis demonstrated that, among other measures, the 

application of control technology, fuel-switching, and 

improvements in the operational efficiency of EGUs all resulted 

in reductions in a range of pollutants. These programs also 

demonstrate that replacement of higher-emitting generation with 

lower-emitting generation -- including generation shifts between 

coal-fired EGUs and natural gas-fired EGUs –- and zero-emitting 

generation such as renewable energy, also reduce emissions. Some 

of these programs also include emissions trading among the power 

plants. 

In this rule, when evaluating the types and amounts of 

measures that the source category can take to reduce CO2

emissions, we have appropriately taken into account the global 

nature of the pollutant and the high degree to which each 

individual affected EGU is integrated into a “complex machine” 

that makes it possible for generation from one generating unit 

to be replaced with generation from another generating unit for 

the purpose of reducing generation from CO2–emitting generating 

units. We have also taken into account the trends away from 

higher-carbon generation toward lower- and zero-carbon 

 

285 Many of these programs are discussed in section V.B. 
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generation. These factors strongly support consideration of 

emission reduction approaches that focus on the machine as a 

whole –- that is, the overall source category –- by shifting 

generation from dirtier to cleaner sources in addition to 

emission reduction approaches that focus on improving the 

emission rates of individual sources. 

The factors just discussed that support consideration of 

emission reduction measures at the source-category level 

likewise strongly support consideration of mechanisms such as 

emissions trading and other multi-unit compliance approaches, 

especially since, as discussed in section VIII, the states will 

have every opportunity to design their section 111(d) plans to 

allow the affected EGUs in their respective jurisdictions to 

employ emissions trading or other multi-unit compliance 

approaches to achieve the standards of performance established 

in those plans, and we believe it is highly likely 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 
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the control activity may be occurring at another source. As 

noted above, the utility power sector has a long history of 

using the “complex machine” to address objectives and 

constraints of various kinds. When afforded the opportunity to 

address environmental objectives on a multi-unit basis, the 

industry has done so. Congress and the EPA have selected 

emissions trading approaches when addressing regional pollution 

from the utility power sector contributing to problems such as 

acid precipitation and interstate transport of ozone and 

particulate matter. Similarly, states have selected market-based 

approaches for their own programs to address regional and global 

pollutants. The industry has readily adapted to that form of 

regulation, taking advantage of the flexibility and 

incorporating those programs into the planning and operation of 

the “machine.” These multi-unit mechanisms are an inherent 

aspect of the way in which the machine is managed to address 

constraints at the source-category level, and they can therefore 

be considered an inherent aspect of emission reduction measures 

available at the source-category level to address a global 

pollutant such as CO2. Although the choice of which particular 

multi-unit compliance mechanisms to allow is a matter to be 

determined primarily by the states in carrying out their 

obligations to set standards of performance through their 
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section 111(d) plans, a plan that did not allow the use of any 

such mechanisms would be so contrary to the integrated nature of 

the industry and so disadvantageous to a state’s own individual 

sources that we, again, view any such plan as extremely unlikely 

and not a possibility that we would be obligated to view as 

constraining the appropriate analysis of the BSER. Further 

reinforcing our conclusion that such an outcome is unlikely is 

the extensive interest in using such mechanisms that states and 

utilities demonstrated through their formal comments and in 

discussions during the outreach process. 

This entire review has made clear that there are numerous 

measures that, alone or in various combinations, merit analysis 

for inclusion in the BSER. The review has also made clear that 

the global nature of CO2 pollution and the unique, interconnected 

nature of 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 loweremitting fossil fuel-fired units for generation from higher-
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emitting fossil fuel-fired units, (iii) substitute generation 

from new low- or zero-emitting generating capacity, especially 

renewable energy, for generation from fossil fuel-fired units, 

and (iv) increase demand-side energy efficiency to avoid 

generation from fossil fuel-fired units. In the proposal, we 

described our evaluations of various measures in each of these 

categories. In this rule, with the benefit of comments, we have 

refined our evaluation of which specific measures should 

comprise the first three building blocks, and, for reasons 

discussed below, we have determined that the fourth building 

block, demand-side energy efficiency, should not be included in 

the BSER. 

The measures are discussed more fully below, but it should 

be noted here that because of the integrated nature of the 

utility power sector, 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 lowerand zero-emitting sources, may occur in several different ways 

from the individual-source perspective, all of which are 

equivalent from the source-category perspective. First, a 

higher-emitting fossil unit may invest in cleaner generation 

without reducing its own generation, which would result in less 

demand for, and therefore reductions in generation by, other 
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higher-emitting units. Second, a higher-emitting fossil unit may 

reduce its generation, which, in the presence of requirements 

for the source category as a whole to reduce CO2 emissions, would 

result in increased demand for, and therefore increased amounts 

of, cleaner generation. Third, a higher-emitting fossil unit may 

do both of these things, directly replacing part of its 

generation with investments in lower- or zero-emitting 

generation.286 In addition, for measures in all of the 

categories, multiple mechanisms exist by which an individual 

affected source may make these investments, ranging from 

bilateral investments, to purchase of credits representing the 

emissions-reducing benefits of specific activities, to purchase 

of general rate-based emissions credits or mass-based emission 

allowances, to other multi-unit compliance approaches such as 

averaging or bubbling. 

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 of the sources’ 

need to comply for identifying the BSER. As part of the EPA’s 

emission guidelines in this rule, and based on the BSER, the EPA 

 

286 The same is true for demand-side energy efficiency measures. 
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is identifying CO2 emission performance rates and, for purposes 

of facilitating states’ efforts to formulate compliance plans 

encompassing maximum flexibilities, aggregating them into goals 

for each state. As discussed below, a state, in turn, is charged 

with 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. 

A state has significant flexibility in several respects. 

For example, a state may impose standards of performance on its 

steam EGU sources and on its combustion turbine sources 

representing 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 requires. In addition 

–- and most importantly for purposes of describing the BSER -- a 

state may set standards of performance either as emission rates 

(e.g., lbs of CO2 per MWh) or mass limits (e.g., tons of CO2 per 

year). Under a mass limit approach, each affected EGU must 

retire an allowance for each ton of CO2 emitted. Moreover, a 
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state may make those limits tradable or authorize other multiunit compliance mechanisms (subject to conditions described in 

section VIII below). The form of the emission limits, whether 

emission rate limits or mass limits, has implications for what 

specific actions the individual affected EGUs may take to 

achieve those limits –- that is, the measures that comprise the 

BSER from the individual-source perspective –- as well as what 

specific non-BSER measures are available to the individual 

affected EGUs for compliance flexibility. For example, if an 

individual source chooses to adopt building block 3 by both 

investing in lower- or zero-emitting generation and reducing its 

own generation, both those actions will be accounted for in its 

emission rate and both will therefore help the source meet its 

rate-based limit. If the same individual source takes the same 

actions but is subject to a mass-based limit, the action of 

reducing its generation will directly count in helping the 

source meet its own mass-based limit but the action of investing 

in cleaner generation will not. However, the investment in 

lower-or zero-emitting generation by that source and other 

sources collectively will help the overall source category 

achieve the emission limits consistent with the BSER and in 

doing so will make it easier for that source and other sources 

collectively to meet their mass-based limits. 
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d. Identification of the BSER measures – the source-category 

perspective. We first discuss the evaluation of potential 

measures for inclusion in the BSER from the source-category 

perspective. 

(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 included a set of measures that the EPA determined would 

result in improvements in heat rate at coal-fired steam EGUs in 

the amount of 6 percent on average, and the EPA proposed that 

this set of measures qualifies as a component of the BSER. As 

described below, in this rule, the EPA concludes that those 

measures do qualify as a component of the BSER, although, based 

on comments and further evaluation, the EPA is narrowing the set 

of these types of measures that qualify as a component of the 

BSER and has quantified the emission reductions achievable 

through application of the measures on a regional basis, 

consistent with the treatment of the other building blocks in 

this final rule, rather than the nationwide basis used for 

building block 1 in the proposed rule. As a result of these 

refinements, the EPA is reducing the amount of emission 

reductions achievable on average from heat rate improvement 

measures at coal-fired steam EGUs to 4.3 percent for the Eastern 
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Interconnection, 2.1 percent for the Western Interconnection, 

and 2.3 percent for the Texas Interconnection. 

 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 anticipated state 

approaches to setting standards of performance, emissions 

trading or other multi-unit compliance approaches could be used 

as mechanisms through which one affected source could invest in 

heat rate improvements at another source. We discuss this aspect 

below in describing the individual-source perspective of the 

BSER. 

These heat rate improvements are a low-cost option that fit 

the criteria for the BSER, but alone, they lead to only small 

emission reductions for the source category. Given the magnitude 

of the environmental problem and projections by climate 
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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 emission reductions limited to this set of 

measures would not meet one of the considerations critical to 

the BSER determination –- the quantity of emissions reductions 

resulting from the application of the BSER to the 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.287 The EPA also considered implementation of 

carbon capture and storage (CCS).288 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. 

 

287 The EPA further addressed co-firing in the NODA. 79 FR 64549-

51. 

288 CCS is also sometimes referred to as carbon capture and 

sequestration. 
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However, these co-firing and CCS measures are more 

expensive than other available measures. This is because the 

integrated nature of the electricity system affords 

significantly lower cost options, ones that fossil fuel-fired 

power plants throughout the United States and in foreign nations 

are already using to reduce their CO2. 

The less expensive options include shifting generation to 

existing NGCC units -- an option that has become particularly 

attractive in light of the increased availability and lower 

prices of natural gas -- as well as shifting generation to new 

renewable energy generating units.289 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 

 

289 Similarly, demand-side energy efficiency measures are lowcost measures. 
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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.290

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 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. 

 

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

measures. 
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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). 

The EPA further discusses the potential use of these non-BSER 

measures for compliance flexibility below. Other measures to 

reduce emissions that some sources may implement, but that the 

EPA is not identifying as part of the BSER for various reasons, 

and that are also further discussed below, include biomass cofiring and conversion of an affected EGU’s waste heat to useful 

thermal energy. 

The EPA’s quantification of the CO2 emission reductions 

achievable through heat rate improvements as a component of the 

BSER (building block 1) is discussed in section V.C. of this 

preamble and in the GHG Mitigation Measures TSD for the CPP 

Final Rule. 
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(2) Measures available because of the integrated 

electricity system. To achieve the needed emission reductions, 

the EPA turned next to the set of measures that presented 

themselves as a result of the integrated nature of the 

electricity system. Those are the measures in the categories 

represented in the proposal by building blocks 2, 3, and 4. This 

section discusses the components of the BSER that relate to 

building blocks 2 and 3, which the EPA is finalizing as 

components of the BSER. This section also discusses the measures 

comprising the proposed building block 4, which the EPA is not 

including in the BSER in this final rule. 

It bears reiterating that the integrated nature of the 

electricity system is a highly salient and unique attribute of 

this source category. Because of this integration, the 

individual sources in the source category operate through a 

network that physically connects them to each other and to their 

customers, an interconnectedness that is essential to their 

operation under the status quo and by all indications is 

projected to be augmented further on a continual basis in the 

future to address fundamental objectives of reliability 

assurance and cost reduction. In analyzing BSER from a sourcecategory perspective, because the affected EGUs are connected to 

each other operationally, a combination of dispatching and 
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investment in lower- and zero-emitting generation allows the 

replacement of higher-emitting generation with lower-emitting 

and zero-emitting generation (measures in building blocks 2 and 

3), and thereby reduces emissions while continuing to serve 

load. 

 As noted above, substitution of higher-emitting generation 

for lower- or zero-emitting generation may include reduced 

generation, depending on the specific action taken by the 

individual EGU. Likewise, emissions trading or other multi-unit 

compliance mechanisms may be used as mechanisms for implementing 

these building blocks. We discuss these aspects below in 

describing the individual-source perspective of the BSER. 

 (a) Substituting generation from lower-emitting affected 

EGUs for reduced generation from higher-emitting affected EGUs 

(building block 2). 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 coalfired 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 
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more electricity from a given quantity of natural gas than a 

steam unit can, generation shifting from coal-fired steam EGUs 

to existing NGCC units is a more cost-effective strategy for 

reducing CO2 emissions from the source category than converting 

coal-fired steam EGUs to combust natural gas or co-firing coal 

and natural gas in steam EGUs. We proposed to find that shifting 

generation consistent with a 70 percent target utilization rate 

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

should be a component of the BSER. 

Further analysis reflecting consideration of the many 

comments we received on 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 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. Some commenters stated that 

summer capacity ratings are a more appropriate basis upon which 
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to compute a target utilization than nameplate capacity ratings 

used at proposal. Accordingly, using the same data on historical 

generation as at proposal, we have reanalyzed feasible NGCC 

utilization levels expressed in terms of summer capacity ratings 

and have found that a 75 target utilization rate based on summer 

capacity ratings is feasible. 

The EPA is finalizing a determination that generation shift 

from higher-emitting affected EGUs to lower-emitting affected 

EGUs is a component of the BSER (building block 2). Our 

quantification of the associated emission reductions is 

discussed in section V.D. of this preamble and in the GHG 

Mitigation Measures TSD for the CPP Final Rule. 

(b) Substituting increased generation from new low- or 

zero-carbon generating capacity for reduced generation from 

affected EGUs (building block 3). Reducing generation from 

fossil fuel-fired EGUs and replacing it with generation from 

lower- or zero-emitting EGUs is another method for reducing CO2

emissions from the utility power sector. In the proposal, the 

EPA identified renewable energy (RE) generating capacity and 

nuclear generating capacity as potential sources lower- or zeroCO2 generation that could replace higher-CO2 generation from 

affected EGUs. 
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(i) Increased generation from new RE generating capacity. 

The EPA’s survey of trends and actions already being taken in 

the utility power sector indicated that RE generating capacity 

and generation have grown rapidly in recent years, in part 

because of the environmental benefits of shifting away from 

fossil fuel-fired generation and in part because of improved 

economics of RE generation relative to fossil fuel-fired 

generation. It is clear that increasing the amount of new RE 

generating capacity and allowing the increased RE generation to 

replace generation from fossil fuel-fired EGUs can reduce CO2

emissions from the affected source category. Accordingly, we 

proposed to include replacement of defined quantities of fossil 

generation by RE generation in the BSER. 

With the benefit of comments, the EPA is finalizing the 

determination that substitution of RE generation from new RE 

generating capacity is a component of the BSER but 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 
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the preamble and in the GHG Mitigation Measures TSD for the CPP 

Final Rule. 

(ii) Increased and preserved generation from nuclear 

generating capacity. In the June 2014 proposal, the EPA also 

identified the replacement of generation from fossil fuel-fired 

EGUs with generation from nuclear units as a potential approach 

for reducing CO2 emissions from the affected source category. We 

proposed to include two elements of nuclear generation in the 

BSER: an element representing projected generation from nuclear 

units under construction, and an element representing preserved 

generation from existing nuclear generating capacity at risk of 

retirement. 

Like generation from new RE generating capacity, generation 

from new nuclear generating capacity can clearly replace fossil 

fuel-fired generation and thereby reduce CO2 emissions. However, 

there are also important differences between these types of lowor zero-CO2 generation. Investments in new nuclear capacity are 

very large, “lumpy,” capital-intensive investments and the 

building of nuclear facilities historically has been subject to 

delays and substantial risks of non-completion, both of which 

tend to raise costs. By comparison, investments in new RE 

generating capacity are relatively small and low-risk. Based on 

the small number of new nuclear generating projects, it is 
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difficult to ascertain a trend of increasing nuclear generation 

in the industry. These differences create greater uncertainty 

regarding the achievability and cost of generation from new 

nuclear capacity as a replacement for fossil fuel-fired 

generation, two important factors in determination of the BSER. 

Accordingly, as described in section V.A.3., the EPA is not 

finalizing increased generation from new 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. 

(c) Increasing demand-side energy efficiency to avoid 

generation and emissions from fossil fuel-fired EGUs. The final 

category of approaches for reducing generation and CO2 emissions 

from affected EGUs that the EPA considered in the proposal 

involves increasing demand-side energy efficiency. When demand-
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side energy efficiency is increased, energy consumers need less 

electricity in order to provide the same level of electricitydependent 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 demand-side energy programs 

are being implemented widely across the sector and that 

investments are increasing. We proposed to include avoidance of 

defined quantities of fossil fuel-fired generation through 

increased demand-side energy efficiency as a component of the 

BSER (proposed building block 4). 

Commenters expressed a wide range of views on the proposed 

reliance on demand-side energy efficiency in the BSER. Some 

commenters strongly supported the proposal, with suggestions for 

improvements, while some commenters strongly opposed the 

proposal and took the position that it exceeded the EPA’s legal 

authority. We do not address the merits of these comments here 

because, for the reasons discussed in V.A.3.e. below, we are not 

finalizing the proposal to include avoided generation achieved 

through demand-side energy efficiency as a component of the 
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BSER. However, we note that most commenters also supported the 

use of demand-side energy efficiency for compliance whether or 

not it is used in determining the BSER, and we are allowing 

demand-side energy efficiency to be used for that purpose. 

(3) Further analysis to quantify the BSER. While the 

discussion above summarizes how and why the components of the 

BSER were determined in terms of qualitative characteristics, it 

still leaves a wide range of potential stringencies for the 

BSER. As explained in sections V.C., V.D., and V.E. below, 

discussing building blocks 1, 2, and 3 respectively, the EPA has 

determined a reasonable level of stringency for each of the 

building blocks rather than the maximum possible level of 

stringency. We have taken this approach in part to ensure that 

there is “headroom” within the BSER measures that increases the 

achievability of the BSER for the source category and for 

individual sources. We note that a feature of the method by 

which we have quantified the degree of emission limitation 

achievable through application of the BSER to the two source 

subcategories -– namely, the use of the least stringent CO2

emission performance rate quantified for a given source 

subcategory for any of the three major Interconnections as the 

CO2 emission performance rate for that source subcategory in all 
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three Interconnections291 –- provides additional headroom within 

the BSER for sources 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 or other multi-unit compliance 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 multi-state approaches, the 

guidelines include mechanisms for implementing standards of 

performance that foster 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 

 

291 Specifically, the respective CO2 emission performance rates 

quantified for the steam EGU subcategory and for the stationary 

combustion turbine subcategory in the Eastern Interconnection 

are being applied to those subcategories in the Western and 

Texas Interconnections as well. This aspect of the BSER 

quantification methodology is discussed below in section V.A.3 

and section VI. 
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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 for the energy sector as a whole. In 

addition, as explained below, each is adequately demonstrated. 

Importantly, past industry practice and current trends strongly 

support each of the building blocks, as do federal and state 

pollution control programs that require or result in similar 

measures. 

For example, all of the measures in building blocks 2 and 3 

have been implemented for decades, initially for reasons 

unrelated to pollution control, then in recent years in order to 

control non-GHG air pollutants, and more recently, for purposes 

of CO2-emission control by states and companies. Moreover, 

Congress itself recognized in enacting the acid rain provisions 

of CAA Title IV that renewable energy measures reduce CO2 from 

affected EGUs. In addition, the EPA has relied on the measures 

in building blocks 2 and 3 in other rules. It should also be 

noted that combinations of the building blocks also meet the 

criteria for the BSER, as described below. 
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e. Identification of the BSER measures – the individual-source 

perspective. We now turn to a summary of the evaluation of 

potential BSER measures from the individual-source perspective. 

 (1) Improvement in CO2 emission rate at the unit. An 

affected EGU may take steps to improve its CO2 emission rate as 

discussed above under the source-category perspective. Although 

the only actions in this category identified for inclusion in 

the BSER are heat rate improvements at coal-fired steam EGUs, if 

a particular affected EGU found that its circumstances made some 

other actions in the category relatively attractive –- for 

example, heat rate improvements at other types of EGUs, cofiring of natural gas, or retrofit of CCS –- the EGU could 

pursue those improvements. The resulting improvements in the 

EGU’s CO2 emission rate would help the EGU achieve an emission 

limit imposed in the form of an emission rate, and would also 

help the EGU achieve an emission limit imposed in the form of a 

mass limit if the EGU did not increase its generation by a 

larger percentage than the percentage of its emission rate 

improvement. 

(2) Actions to implement measures in building blocks 2 and 

3. Viewing the BSER from the individual-source perspective, 

because of the integrated nature of the electricity system, 

coupled with the system’s high degree of planning and 
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reliability mechanisms, there are several ways that affected 

EGUs can access the measures in building blocks 2 and 3. The 

affected EGUs can (a) invest in lower- or zero-emitting 

generation, which will lead to reductions in higher-emitting 

generation at other units in the integrated system; (b) reduce 

their generation, which in the presence of emission reduction 

requirements applicable to the source category as a whole will 

have the effect of increasing demand for and thereby 

incentivizing 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.292 

 (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 

 

292 These same methods are available for demand-side energy 

efficiency measures. 
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to increase generation, and purchase the CO2-reducing effects of 

that increased generation as emission rate credits. 

Similarly, for building block 3, an owner/operator of an 

affected EGU may build, or purchase an ownership interest in, 

new renewable energy generating capacity and purchase the CO2-

reducing effects of that increased generation. Alternatively, an 

owner/operator may, through bilateral transactions, purchase the 

CO2-reducing effects of that increased generation from renewable 

generation providers. 

In case of an investment in either building block 2 or 

building block 3 by a unit subject to a rate-based form of CO2

performance standard, the section 111(d) plan would need to 

provide –- and we expect that states would do so in their plans 

-- a mechanism by which the affected unit could account for the 

emissions-reducing benefit of the investment when computing its 

emission rate for purposes of determining compliance with the 

performance standard. The mechanism could involve use of an 

approved and validated instrument such as an “emission rate 

credit” representing the emissions-reducing benefit of the 

investment or could involve an approved averaging arrangement.293 

 

293 Criteria for issuance of valid emission rate credits and for 

tracking credits after issuance are discussed in section VIII 

below and in the Rate-based Program Accounting TSD for the CPP 

Final Rule. 
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When combined with reduced generation, either at the 

affected EGU or elsewhere in the interconnected system, the 

types of actions listed above would be fully equivalent to 

building blocks 2 and 3 when viewed from the source-category 

perspective. Therefore, the menu of these actions, including 

reduced generation, is appropriate for inclusion in the BSER. 

That is, if a state assigns to a source a standard of 

performance that is the same as the applicable CO2 emission 

performance rate in the EPA emission guidelines, or the mass 

limit equivalent, the source could achieve the limit through 

implementation of the actions described above for building 

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

for building block 1. 

By the same token, for the demand-side energy measures that 

the EPA proposed as building block 4, an owner/operator of an 

affected EGU may implement demand-side energy efficiency 

programs directly or hire contractors or energy service 

companies to do so, and claim the resulting emission rate 

credits. The owner/operator may also engage in bilateral 

transactions with distribution utilities that already implement 

demand-side energy efficiency programs and pay them to implement 
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such a program.294 When combined with reduced generation, either 

at the affected EGU or elsewhere in the interconnected system, 

these types of actions would be fully equivalent to proposed 

building block 4 when viewed from a source-category perspective. 

As noted elsewhere, the EPA has determined not to include 

proposed building block 4 in the BSER in this final rule. 

However, the measures in building block 4 would still be 

available for compliance purposes to the extent permitted under 

state plans, and the list of actions above indicates the range 

of ways through which affected EGUs could access this resource. 

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

plans provide for the use of instruments such as emission rate 

credits as a mechanism to facilitate use of these measures, 

organized markets will develop so that owner/operators of 

affected EGUs that have invested in measures eligible for the 

issuance of emission rate credits will be able to sell those 

credits and other affected EGUs will be able to purchase them. 

 

294 For affected EGUs subject to a rate-based form of CO2 

performance standard, the section 111(d) plan would need to 

provide a mechanism by which the affected unit could account for 

the emissions-reducing benefit of the investment when computing 

its emission rate for purposes of determining compliance with 

the performance standard. This mechanism could be similar to the 

mechanism required with respect to investments in building 

blocks 2 and 3, although use of demand-side energy efficiency 

measures involves some additional considerations as well. 

Further discussion can be found in section VIII below and in the 

Rate-based Program Accounting TSD for the CPP Final Rule. 
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Such markets have developed for other instruments used for 

emissions trading purposes. 

If states choose to allow through section 111(d) plans a 

mechanism involving instruments such as emission rate credits –- 

and, as indicated above, the record strongly indicates that they 

can be expected to -- there is no reason to expect a shortage of 

supply of such credits. 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 sources in the 

Western and Texas Interconnections on average do not need to 

implement the building blocks to their full extent in order to 

achieve their emission limits because the performance rates for 

sources in these regions are set at the less stringent rates 

determined to be reasonable for application of the BSER to 

sources in the Eastern Interconnection. Further, to the extent 

that section 111(d) plans take advantage of the final rule’s 

flexibility to allow the use of multi-state emissions trading or 

other multi-unit compliance approaches among sources in 
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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 

renewable energy remain available to serve as the basis for 

issuance of credits for all affected EGUs in both source 

subcategories to rely on to achieve their emission limits. 

Because 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, the EPA believes that it is 

reasonable to anticipate as highly likely that a virtually 

nationwide emission trading market for compliance will emerge, 

and that these credits will be available to any source wherever 

located, as long as its state plan authorizes their purchase and 

use in meeting the standard of performance the state 

establishes. 

It should also be noted that although the measures in 

building blocks 2 and 3 can be taken into account directly in 

computations to determine whether an individual affected EGU has 

achieved an emissions limit set in an emission rate-based form 

if, as expected, the state chooses to authorize a mechanism for 

doing so, they are not taken into account directly in 

computations to determine whether an individual affected EGU has 
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achieved an emissions limit set in a mass-based form. However, 

by reducing generation and therefore CO2 emissions from the group 

of affected EGUs within a region, these measures facilitate the 

ability of the individual EGUs within the region to achieve 

mass-based limits by choosing to reduce their own generation and 

emissions. 

(b) Reduced generation. In addition, the owner/operator of 

an affected EGU may help itself meet its emission limit by 

reducing its generation. If the owner/operator reduces 

generation and therefore the amount of its CO2 emissions, then, 

if the affected EGU is subject to an emission rate limit, the 

owner/operator will need to implement fewer of the building 

block measures, e.g., buy fewer emission rate credits, to 

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

a mass emissions limit, the owner/operator will need fewer mass 

allowances. 

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 
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that increases the total variable cost considered when dispatch 

decisions are made for the unit. 

Because of the integrated nature of the electricity system, 

combined with the system’s high degree of planning and 

reliability safeguards, as well as the long planning horizon 

afforded by this rule, individual affected steam EGUs, reducing 

their generation in the amounts of building blocks 2 and 3, and 

individual affected NGCC units, reducing their generation in the 

amounts of building block 3, can in aggregate achieve the 

requisite level of reductions in generation adequate to achieve 

emission limits reflecting the BSER.295 With emission limits for 

the source category as a whole in place, the resulting reduction 

in supply of higher-emitting generation will incentivize 

additional utilization of existing NGCC capacity, and the 

resulting reduction in overall fossil fuel-fired generation will 

incentivize investment in additional renewable energy generating 

capacity, and the integrated system’s response to these 

incentives will ensure that the demand for electricity services 

will continue to be met.

 

295 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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(c) Emissions trading. As described above, viewed from the 

source-category perspective, the BSER implicitly includes an 

element of source-category-wide multi-unit compliance, which at 

the level of implementation could be realized through trading of 

rate-based emission credits or mass-based emission allowances. 

Indeed, as we have already observed, the comment record provides 

ample evidence that states themselves anticipate establishing 

standards of performance that allow the use of emissions trading 

or other multi-unit compliance approaches, and the guidelines’ 

reliance on state level goals as the basis on which states must 

demonstrate compliance can be expected to be the cornerstone on 

which states construct plans that rely, at least implicitly, on 

multi-unit compliance. The inclusion in the guidelines –- at the 

request of states and utilities –- of provisions that allow 

states to create “trading ready” plans for the purpose of 

facilitating interstate emissions trading or other multi-unit 

compliance approaches, as discussed in section VIII, is further 

evidence that utilities as well as states anticipate standards 

of performance that rely on emissions trading or other multiunit compliance approaches. Emissions trading, whether 

implemented through rate-based or mass-based standards of 

performance, enables the building blocks to be implemented by 

the EGUs with the lowest costs, and the overall costs to be 
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distributed throughout the existing source universe, such that 

costs can be reduced for the source category and for many 

individual affected EGUs. By the same token, viewed from the 

individual-source perspective, 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 sources’ section 111(d) plans and would have to 

meet conditions set out for such approaches in section VIII 

below, but the record provides ample evidence that such 

authorization can be expected and section VIII addresses the 

necessary conditions extensively. 

It has been recognized for decades, starting with the Acid 

Rain SO2 trading program under Title IV of the CAA, that the 

availability of emissions trading facilitates the implementation 

of control measures and reduces their cost. For example, in this 

rule, while each affected EGU could, in theory, implement each 

of the building blocks, some affected EGUs would face lower 

costs in doing so than others, at least for individual building 

blocks and likely for the combination of all three building 

blocks as well. Thus, the EPA expects that affected EGUs for 
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whom application of one or more building blocks is relatively 

less expensive may overcomply. As a result, to the extent that 

the applicable section 111(d) plans permit emissions trading, 

the EGUs that overcomply would have rate-based emission credits 

or mass-based emission allowances to sell, which would enable 

affected EGUs for whom compliance is relatively more expensive 

to achieve their emission limits by purchasing those credits or 

allowances. Any of the building blocks could be the basis for 

overcompliance and consequent creation of a surplus of credits 

or allowances. When an EGU obtains an emission rate-based credit 

or mass-based allowance from another EGU, that is effectively 

the same as investing directly in the control measures that 

created the surplus, such that when emissions trading is 

permitted, all of the building blocks are effectively available 

to all affected EGUs through “cross investment” using emission 

credits or allowances. EGUs currently operating under a variety 

of pollution control programs incorporating emissions trading 

have effectuated such investments and actions through the 

purchase of surplus emissions reductions, in that the purchase 

price represents investment in other EGUs’ pollution reduction 

actions that encompass a range of activity, including the use of 

cleaner generation. 
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(d) Other multi-unit compliance approaches. The set of 

multi-unit compliance approaches inherent in the BSER because of 

the global nature of the CO2 pollutant and the interconnected 

nature of the electricity system is broader than just the 

emissions trading approaches described above. In addition to 

emissions trading approaches -– in essence, multi-unit 

compliance approaches that use tradable emission credits or 

allowances as marketable instruments to facilitate coordination 

among the sets of participating units -– it is possible for 

section 111(d) plans to provide for the use of multi-unit 

approaches that do not involve tradable instruments. Although 

potentially somewhat less flexible than emissions trading 

approaches, other types of multi-unit compliance approaches 

generally offer the same ability for affected sources with 

lower-cost emission-reduction opportunities to overcomply and to 

make surplus emission reductions available for use by affected 

sources with higher-cost emission-reduction opportunities. Thus, 

like emissions trading, these approaches effectively make it 

possible for affected EGUs to invest in emission reduction 

measures that are physically implemented at other locations, 

consistent with longstanding practice in the interconnected 

electricity system. 
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For units subject to rate-based performance standards, 

multi-unit compliance approaches other than emissions trading 

approaches would generally be “averaging” approaches where 

multiple units would combine their monitored emissions and 

generation (as well as any authorized emission rate credits 

representing the emissions-reducing benefits of investments in 

specific emissions-reducing activities) in order to compute a 

combined emission rate that would, in turn, be compared to a 

combined rate-based performance standard. For units subject to 

mass-based performance standards, such approaches would 

generally be “aggregation” approaches where multiple units would 

combine their monitored emissions in order to compute a combined 

total mass of emissions that would, in turn, be compared to a 

combined mass-based performance standard.296 The use of averaging 

or aggregation approaches would have to be authorized in the 

111(d) plans covering all the participating affected sources and 

would have to meet conditions set out for such approaches in 

section VIII below. 

f. 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 

 

296 Approaches that aggregate emissions of multiple units at a 

single facility are commonly known as “bubbling” approaches. 
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that they can achieve their emission limits, even though the EPA 

is not identifying these measures as part of the BSER. These 

measures include demand-side energy efficiency implementable by 

affected EGUs; new or up-rated nuclear generation; renewable 

measures other than those that are part of building block 3, 

including distributed generation solar power and off-shore wind; 

combined heat and power and waste heat power; and transmission 

and distribution improvements. In addition, a state may 

implement measures that yield emission reductions for use in 

reducing the obligations on affected EGUs, such as demand-side 

energy efficiency measures not implementable by affected EGUs, 

including appliance standards, building codes, and drinking 

water or wastewater system efficiency measures. The availability 

of these measures further assures that the appropriate level of 

emission reductions can be achieved and that affected EGUs will 

be able to achieve their emission limits. 

g. Ability of EGUs to implement the BSER. The EPA’s analysis, 

based in part on observed decades-long behavior of EGUs, shows 

that all types and sizes of affected EGUs in all locations are 

able to undertake the actions described as the BSER, including 

investor-owned utilities, merchant generators, rural 

cooperatives, municipally-owned utilities, and federal 

utilities. Some may need to focus more on certain measures; for 
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example, an owner of a small generation portfolio consisting of 

a single coal-fired steam EGU may need to rely more multi-unit 

compliance 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 renewable capacity in addition to coal-fired capacity. As 

noted elsewhere, as a legal matter, it is not necessary that 

each affected source be able to implement the BSER, but in any 

event, in this rule, all affected EGUs can do so. Affected EGUs 

may rely on emissions trading or other multi-unit compliance 

approaches authorized under their states’ section 111(d) plans 

to, in effect, invest in building block measures that are 

physically implemented at other locations. As discussed above, 

the EPA’s quantification of the CO2 emission performance rates in 

a manner that provides headroom within the BSER also contributes 

to the ability of all affected EGUs to implement the BSER and 

achieve emissions limitations consistent with those performance 

rates. 

h. 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 
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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 what multi-unit compliance approaches to permit, 

possibly including emissions trading approaches -- including 

investment in the building blocks, replaced or reduced 

generation, and emissions trading or other multi-unit compliance 
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approaches. Further, in the case of a rate-based state plan, 

several other compliance options not included in the BSER for 

this rule are also available to all affected sources, including 

investment in demand-side energy efficiency measures. Such 

compliance options may also indirectly help affected sources 

achieve compliance under a mass-based plan. 

 Our approach of subcategorizing between steam EGUs and 

combustion turbines is reasonable because building blocks 1 and 

2 apply only to steam EGUs. Moreover, our approach of not 

further subcategorizing as between different types of steam EGUs 

or combustion turbines reflects the reasonable policy that 

affected EGUs with higher emission rates should reduce their 

emissions by a greater percentage than affected EGUs with lower 

emission rates 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, the EPA has adopted certain 

refinements to the proposed BSER. In this subsection we describe 

the most significant refinements, including some that relate to 

individual building blocks and some that are more general. 

Additional refinements 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 refinements yield emission 

reductions requirements that commence more gradually than the 

proposed goals but are projected to produce slightly greater 

emission reductions overall by 2030. We also note that the 

refinements lead to requirements that are more uniform across 

states than was the case in the proposal. 

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.297 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 

 

297 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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applied. The clarified and more refined interpretations replace 

the proposed interpretations, as indicated in section V.A.1. and 

the Legal Memorandum for the CPP Final Rule available in the 

docket, as well as in the final rule for new sources promulgated 

concurrently with this final rule for existing sources. 

 Two of these points merit mention here. First, the EPA is 

clarifying in this rule that the interpretation of “system of 

emission reduction” does not include emission reduction measures 

that the states have authority to mandate without the affected 

sources 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 sources, not by the states, and we 

show that all the components of the BSER have been demonstrated 

to be achievable on that basis without reliance on actions that 

can only be accomplished through state 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, 

places more weight on the historical interpretations of section 

111(a)(1), which have generally supported emissions standards 
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that are nationally uniform for sources incorporating a given 

technology, and less weight on 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 sources in each individual state, and because the relative 

magnitudes of these opportunities varied by state, sources 

incorporating the same technology could have faced disparate 

standards of performance (depending to some extent on how the 

states chose to distribute the emission reduction requirements 

among their individual sources). Some commenters viewed this 

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

inequitable, or both. While we continue to believe that, for the 

purposes of this rule, the focus of section 111(d) on individual 

state plans could justify an interpretation of section 111(a)(1) 

that emphasizes maximization of state-by-state emission 

reduction opportunities, we have determined that by assessing 

the emission reduction opportunities at an appropriate regional 

scale, it is possible to reconcile the use of uniform emissions 

standards by technology with the state-focused 111(d) scheme. 

The methodological refinements related to regional assessment of 
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emission reduction opportunities and the use of uniform 

emissions standards by technology are further discussed below. 

b 

. Approach to quantification of emission reductions from 

increased RE generation. In the June 2014 proposal, the EPA 

described two possible approaches for quantifying the amount of 

emission reductions achievable from affected EGUs through the 

use of renewable energy generation. The proposed approach used 

information on state RPS aggregated at a regional level to 

project the amount of RE generation used in quantifying the 

emission reductions achievable through the BSER. The alternative 

approach used information on the technical and market potential 

for development of renewable resources in each state to project 

the RE-related emission reductions. In the October 30, 2014 

Notice of Data Availability, we provided notice that some 

commenters had suggested modifying the alternative approach to 

aggregate the state-level information to a regional level. In 

this final rule we are adopting the alternative approach from 

the proposal, modified as described in the NODA. 

 In the June 2014 proposal, RE generation was also 

quantified as generation from total –- that is, existing and new 

–- RE generating capacity, a formulation that was consistent 

with the formulation of most RPS, which are typically framed in 
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terms of total rather than incremental generation. Commenters 

observed that this quantification 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 RPSbased methodology in the final rule, and we agree with comments 

that quantification of RE generation on an incremental basis is 

both more consistent with the treatment of other building blocks 

and more consistent with the general principle that the BSER 

should comprise incremental measures that will reduce emissions 

below existing levels, not measures that are already in place, 

even if those in-place measures help current emission levels be 

lower than would be the case without the measures. The final 

rule therefore defines the RE component of the BSER in terms of 

incremental rather than total RE generation.298 Further details 

regarding the final rule’s quantification of RE generation are 

provided in section V.E. below. 

c 

 

298 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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. Exclusion from the BSER of emission reductions from use of new 

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 sources. We proposed to 

include in building block 3 the potential generation from five 

under-construction nuclear generating units whose construction 

had commenced prior to the issuance of the proposal. In 

addition, to address the potential that some currently operating 

nuclear facilities may shut down prior to 2030, the proposal 

incorporated into the BSER for each state with nuclear capacity 

a projected 5.8 percent reduction in nuclear generation, based 

on an estimate of potential nationwide loss of nuclear 

generation from existing units. We sought comment on all aspects 

of these proposed approaches. 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 new nuclear units, some commenters expressed strong 

opposition to the inclusion of this generation in the BSER and 

the setting of state goals, stating that inclusion would result 

in very stringent state goals for the states where the new units 
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are being built and that the inclusion of the generation in the 

goals is premature because the units’ actual completion dates 

are uncertain. Some commenters expressed concern regarding the 

lack of flexibility to find alternative emission reduction 

measures comparable in magnitude to the assumed emission 

reductions from the new nuclear generation in the event that 

construction was not completed, potentially hampering the 

ability to achieve the state goals. Commenters also stated that 

inclusion of the new 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 

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 is 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, 
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although we believe that other refinements to this final rule 

would address commenters’ concerns that host states would be at 

risk of being unable to achieve their goals if the units were 

not completed, we also acknowledge that including generation 

from the units in the BSER would fail to recognize the 

significant ongoing commitment required to complete these major 

investments by instead treating them as though there were no 

chance they would not be completed. With respect to existing 

nuclear units, although again we believe that other refinements 

in the final rule would address the concern about disparate 

impacts on particular states, we acknowledge that we lack 

information on shutdown risk that would enable us to improve the 

estimated 5.8 percent factor for nuclear capacity at risk of 

retirement. Further, based in part on comments received on 

another aspect of the proposal –- specifically, the proposed 

inclusion of existing RE generation in the goal-setting 

computations –- we believe that it is inappropriate to base the 

BSER in part on the premise that the 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. 
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 Generation from 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 of credits, as discussed in section V.A.6.b., 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 nuclear capacity to 

serve as the basis for creation of credits that individual 

affected EGUs could use for compliance.299

d. Exclusion from the BSER of emission reductions from demandside energy efficiency. The June 2014 proposal included demandside energy efficiency measures in building block 4 as part of 

the BSER, but the EPA is not finalizing that part of the 

proposal, for the following reasons. 

 

299 As with generation from existing RE capacity, generation from 

existing nuclear capacity will continue to make compliance with 

mass-based standards easier to achieve by making the overall 

amount of fossil fuel-fired generation that is required to meet 

the demand for energy services lower than it would otherwise be, 

thereby keeping CO2 emissions lower than they would otherwise be. 
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Building block 4 caused more controversy among commenters 

than any other aspect of the June 2014 proposal. While many 

commenters emphasized the cost-effectiveness of demand-side 

energy efficiency measures, others expressed significant 

concerns. 

As a legal matter, commenters emphasized that demand-side 

energy efficiency measures reduce emissions from the generation 

of electricity by reducing overall demand for electricity and 

that this is different from generation shifts and renewable 

energy. Commenters also asserted that those differences are 

legally significant for purposes of determining whether demandside energy efficiency measures may qualify as part of the BSER. 

Commenters viewed demand-side energy efficiency as a restriction 

on the amount of electricity that the affected industry could 

generate, and they viewed that type of restriction as beyond the 

scope of the EPA’s authority under CAA section 111. 

The demand-side energy efficiency measures in building 

block 4 are different in certain respects from the generation 

shifts and renewable energy measures in building blocks 2 and 3. 

As noted, the generation shifts and renewable energy measures 

are mechanisms through which affected EGUs may generate the same 

electricity (which is a fungible product) with fewer CO2

emissions whereas the demand-side energy efficiency measures in 
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building block 4 do not provide the same amount of generation 

but through cleaner processes, and instead bring about 

reductions in demand for electricity, which avoids the need for 

variable generation, which tends to be higher-emitting. 

Commenters also assert that inclusion of building block 4 

would amount to an attempt to extend EPA regulation beyond 

emitting sources to electricity end-users, and they observe that 

such an extension would exceed the EPA’s authority. While we do 

not agree that inclusion of building block 4 in the BSER would 

be equivalent to regulation of electricity end-users, the legal 

uncertainty associated with this claim would increase the 

uncertainty for states during a window of time when significant 

progress must be made on their section 111(d) plans, potentially 

hindering those planning efforts. 

In addition, commenters noted that as a practical matter, 

demand-side energy efficiency programs involve the participation 

of more entities, including end-users, which creates levels of 

complexity in implementation not found with the other building 

blocks. Commenters also asserted that the record for the 

proposal lacked information demonstrating that a number of 

states could implement demand-side energy efficiency programs in 

the amounts and on the time-table that the proposal called for, 

or that certain segments of the industry –- independent power 
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producers, who comprise some 35-40 percent of the industry, but 

do not have a direct business relationship with end-users –- 

could do so. 

Upon consideration of the variety of points raised above, 

without necessarily agreeing with those points, the EPA has 

determined not to include demand-side energy efficiency in the 

BSER in this final rule. 

 It should be noted that commenters also took the position 

that the EPA should allow demand-side energy efficiency as a 

means of compliance with the requirements of this rule, and, as 

discussed 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 

of each individual state, considering the amount of generation 

that could be shifted from steam EGUs to NGCC units within the 
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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.300 

 For the final rule, with the benefit of comments received, 

we have adopted a consistent regionalized approach to 

quantification of emission reductions achievable through all the 

building blocks. The regions we have determined to be 

appropriate for this purpose are the Eastern, Western, and Texas 

Interconnections, as we explain in more detail below.301 Each of 

the building blocks is quantified and applied at the regional 

level, resulting in the computation for each region of a 

 

300 For building block 4, potential demand-side EE was first 

quantified on a state-specific basis but the emission reduction 

consequences for electricity-importing states were then adjusted 

downward in the goal setting process in order to account for 

regional effects; we solicited comment on making parallel upward 

adjustments to the goals for net electricity-exporting states to 

account for the regional effects more completely. 

301 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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performance rate for steam EGUs and a performance rate for NGCC 

units. We then apply these performance rates to the baseline 

data for each state in a region to establish state goals of 

consistent stringency across the states (although the actual 

state goals vary among states to reflect the differences in 

generation mix among states).302 Further description of the steps 

in this overall process is contained in the preamble sections 

addressing the individual building blocks (sections V.C., V.D., 

and V.E.) and CO2 emission performance rate and state goal 

computation (sections VI and 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. 

 

In determining that the appropriate regional level for 

quantification of the BSER was the level of the interconnection, 

the EPA considered several factors. First, we considered the 

regional scale on which electricity is actually produced, 

coordinated, and consumed in real time, and concluded that the 

 

302 As discussed below, we have determined that it is appropriate 

to go further and to use the single most conservative – that is, 

the least stringent – set of the three regionally developed 

uniform emissions standards to establish state goals for the 

states, in all three regions, thereby ensuring a consistent 

stringency of goals for all states. 
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three large interconnections –- Eastern, Western and Texas –- 

were more appropriate than subregions within these 

interconnections. The Bulk Power System (BPS) in the contiguous 

United States (including adjacent portions of Canada) consists 

of 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. Interconnection 

planning and management follows the NERC functional model, which 

defines subregional areas and regional entities within each 

interconnection for the purposes of balancing generation with 

load and ensuring that reliability is maintained. While a 

variety of organizations plan and operate these subregions –- 

with the borders of the subregions occasionally changing as 

planning and management functions evolve or as owners of various 

portions of the grid change affiliations –- those activities 

always occur in the context of the interconnections, whose 

boundaries change much less often. The need to maintain common 

frequency and stable voltage levels throughout the 

interconnections requires constantly changing flows of 
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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 regions within the interconnection. Although this 

coordination has always been important, grid planning and 

management has evolved to be increasingly interconnection-wide, 

through the development of larger regional entities, such as 

RTO/ISOs, or large-utility dispatch across multiple balancing 

areas. As a result, the fact that much of the necessary 

coordination for the interconnections is performed regionally on 

a partially decentralized basis (at least in the case of the 

Eastern and Western Interconnections) or occurs through the 

operation of automated equipment and the physics of the grid 

does not render the subregions more relevant than the 
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interconnections as the ultimate regions within which 

electricity supply and demand must balance. 

 Second, 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 

of renewable energy throughout each interconnection -- as well 

as the management of the interconnected grid as loads are 

reduced through energy efficiency, which is not reflected in the 

final BSER, are already driving power system development and are 

being managed through interconnection-wide planning, 

coordination and operations, and will continue to be managed in 

that manner in the future with or without this rule. While 

electricity supply and demand must be balanced in real time in a 

manner that observes all security constraints at that point in 

time, and key aspects of that management are carried out at a 

subregional scale, the emissions standards established in this 

rule can be met over longer timeframes through processes managed 
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at larger geographic scales, just as they are today. We believe 

this rule will reinforce these developments and help provide a 

secure basis for moving forward. If a local transmission 

constraint requires that for reliability reasons a higheremitting resource must operate during a certain period of time 

in preference to a lower-emitting resource that would otherwise 

be the more economic choice when all costs are considered, 

nothing in this rule prevents the higher-emitting source from 

being operated. If the same transmission constraint causes the 

same conditions to occur frequently, the extra cost associated 

with finding alternative ways to reduce emissions will provide 

an economic incentive for concerned parties to explore ways to 

relieve the transmission constraint. If relieving the constraint 

would be more costly than employing alternative measures to 

reduce emissions, the rule allows parties to pursue those 

alternative emission reduction measures. Accommodation of 

intermittent constraints and evaluation of alternatives for 

relieving or working around them have been routine operating and 

planning practices within the utility power sector for many 

years; the rule will not change these basic economic practices 

that occur today. The 2022-29 schedule for the rule’s interim 

goals and the 2030 schedule for the rule’s final goals allow 
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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 sources 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, 

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 
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activities, such as renewable energy certificates, which, again, 

represent investments in pollution control measures, are already 

traded separately from the underlying electric energy and 

capacity. There is no reason that whatever geographic limits may 

exist for electricity and capacity transactions by an affected 

source should also limit the source’s transactions for emission 

rate credits or 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 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 type. In 

conjunction with the refinements to the interpretations of 

section 111 reflected in the final rule, the EPA has refined the 

methodology for applying the BSER to the affected sources so as 

to incorporate performance rates that are uniform across 

technology types. 
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 Specifically, the final rule reflects a performance rate of 

1290 lbs. per net MWh for all affected steam EGUs nationwide and 

a performance rate of 780 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. This refinement is 

consistent with a number of comments we received on the proposal 

and is a logical outgrowth of the proposal informed by the 

comments. The commenters took the position that the proposed 

state goals varied too much among states and unavoidably 

implied, or would inevitably result in states establishing 

inconsistent standards of performance for sources of the same 

technology type in their respective states, which in the 

commenters’ view was not appropriate under section 111. 

 In section VI, below, we describe how we use data assembled 

for the building blocks through the consistent regional approach 

described above to determine for each region a set of uniform 

performance rates representing emission limits achievable 

through the application of the BSER to the subcategory of steam 

EGUs and the subcategory of NGCC units. Recognizing the comments 

favoring the use of nationally uniform performance rates by 

technology, the EPA considered whether any of the regional 
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performance rates could represent the emission limitation 

achievable through application of the BSER for its respective 

source subcategory nationwide. Except for Alaska, Hawaii, Puerto 

Rico, and Guam, which are geographically isolated from the three 

major interconnections as well as from one another, the 

standards developed using data for the Eastern, Western and 

ERCOT Interconnections represented sufficiently broad 

combinations of affected sources and emission reduction 

opportunities to apply nationally. 

 We also determined that it would be more appropriate to use 

the least stringent of the regional performance rates for the 

three interconnections for each technology type as the basis for 

nationally uniform performance rates for that technology type 

than to use the most stringent or the region-specific 

performance rates. This is generally consistent with the 

approach taken in other NSPS rulemakings, where once the 

appropriate technology has been identified, stringencies are 

generally set based on the least stringent level reasonably 

achieved using that technology. Using the least stringent rate 

would provide greater “headroom” –- that is, emission reduction 

opportunities beyond those reflected in the performance rates –- 

to affected sources in regions not setting the national level, 

and therefore greater compliance flexibility and assurance that 
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the standards would be achievable at reasonable cost, while 

still representing an appropriately large set of emission 

reduction opportunities to reasonably be considered the “best” 

system of emission reduction for each technology type. 

 We have determined that the nationwide performance rates 

should not necessarily apply to states and territories that are 

isolated from the three major interconnections –- that is, 

Alaska, Hawaii, Puerto Rico, and Guam303 –- because affected EGUs 

in those areas lack the same opportunities to access the 

building blocks across wide regions that affected EGUs in the 

contiguous states enjoy. Instead, if the performance rates 

computed using data specific to one of these isolated states or 

territories is less stringent than the nationwide performance 

rates, we have determined that the less stringent state- or 

territory-specific rates should apply. 

 The computations of the regionally uniform performance 

rates for each of the three major interconnections as well as 

Alaska, Hawaii, Guam, and Puerto Rico are shown in the Final 

Rule Goal Computations TSD. 

 

303 The section 111(d) requirements do not currently apply to the 

other isolated U.S. territories –- the U.S. Virgin Islands, 

American Samoa, and the Northern Mariana Islands –- because no 

affected EGUs currently operate in these territories. 
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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. 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 complying while maintaining reliable 

electricity supplies. 

 The EPA has considered these comments and in the final rule 

has established an interim compliance period of 2022-2029, 

providing two additional years for planning and investment 

before the start of compliance. We are persuaded by comments and 

by our own further analysis that this timeframe is appropriate 

given the nature and magnitude of planning and investment 

activities that will be necessary to begin compliance with the 

final rule’s requirements in an orderly manner while maintaining 

reliability of electricity supplies. Further discussion is 

provided in the sections of the preamble addressing the 
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individual building blocks and on electricity system 

reliability. 

h. Refinements to stringency for individual building blocks. For 

each individual building block, the EPA has reexamined the data 

and assumptions used at proposal in light of comments received, 

and has made a number of refinements in the final rule in light 

of that information. The refinements are discussed in the 

preamble sections for each building block (sections V.C., V.D., 

and V.E.) and goal computation (section VI) and in the GHG 

Mitigation Measures TSD for the CPP Final Rule and the CO2

Emission Performance Rate and Goal Computation TSD for the CPP 

Final Rule. In general, viewed in terms of projected nationwide 

emission reductions, these refinements tend to make the interim 

goals somewhat less stringent than at proposal with the 2030 

goals being either at the same level of stringency as that of 

the proposal or at a somewhat more stringent level. 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. 
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 Use of 75 percent of summer capacity (rather than 70 percent of 

nameplate capacity) as the target capacity factor for existing 

NGCC units under building block 2. 

 Use of updated information from the National Renewable Energy 

Laboratory (NREL) on renewable energy costs and potential, and 

revision of the list of quantified RE technologies to exclude 

landfill gas under building block 3. 

4. Determination of the BSER 

 In this rule, the EPA is finalizing as the BSER a 

combination of building blocks 1, 2, and 3, with refinements as 

discussed below. The building blocks constitute the BSER from 

the source-category perspective. Each building block includes a 

set of actions and facilitating mechanisms that individual 

sources can use to achieve the emission limitations reflecting 

the BSER. These actions and mechanisms, which include reduced 

generation and emissions trading or other multi-unit compliance 

approaches, represent the BSER from the individual-source 

perspective and will be discussed below in section V.A.5. 

 As discussed above, one of the refinements being made in 

this rule is the establishment of uniform performance rates by 

technology type. 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 
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electricity system and the region-wide scope of opportunities 

available for affected sources in each region to access emission 

reduction measures. However, 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. In 

order to achieve uniform performance rates by technology type, 

and to do so in a way that respects regional differences in 

emission reduction opportunities, we have determined that it is 

reasonable not to establish the stringency of the BSER 

separately by region based on the maximum emission reduction 

that would be achievable in that region, but instead to 

establish uniform stringency across all regions at a level that 

is achievable at reasonable cost in any region. Thus, for each 

technology type, the BSER is the combination of the elements 

described above at the combined stringency that is reasonably 

achievable in the Eastern Interconnection, which is the region 

where the CO2 emission performance rates determined to be 

achievable at reasonable cost for both steam EGUs and combustion 

turbines were least stringent. (For the isolated states and 

territories of Alaska, Hawaii, Puerto Rico, and Guam, if the 

performance rates determined to be achievable at reasonable 
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costs based on the application of the BSER to that state or 

territory are less stringent than the nationwide rates, the 

state- or territory-specific performance rates are used 

instead.) This approach is consistent with the approach we have 

taken in other NSPS rulemakings, where the BSER for each 

subcategory of affected sources generally has been determined 

not on the basis of what is achievable by the sources that can 

reduce emissions most easily, but instead on the basis of the 

least stringent rate that is reasonably achievable. 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 the emission reductions that could be achieved at 

reasonable cost exceed the reductions that are achievable at 

reasonable cost in the limiting region, thereby promoting 

compliance flexibility. Further, because we are not 

geographically restricting the opportunity of affected EGUs to 

engage in emissions trading or other multi-unit compliance 

approaches to the extent allowed under the relevant section 

111(d) plans, the availability of additional, lower-cost 

emission reduction opportunities in other regions will also 

promote compliance flexibility and reduces compliance costs. 

 Briefly, the elements of the BSER are: 
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Building block 1: Reducing the carbon intensity of generation 

at individual affected coal-fired steam EGUs through heat rate 

improvements in specified percentages. 

Building block 2: Substituting increased generation from 

existing affected NGCC units for reduced generation from 

affected steam EGUs in specified quantities. 

Building block 3: Substituting generation from new low- or 

zero-carbon generating capacity for reduced generation from 

affected EGUs in specified quantities. 

a. Building block 1. Building block 1 -- reducing the carbon 

intensity of generation at individual affected coal-fired steam 

EGUs through heat rate improvements -- is a component of the 

BSER with respect to coal-fired steam EGUs304 because the 

measures the affected sources 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 

 

304

 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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emission reduction” for steam EGUs because owners of these EGUs 

can take actions that will improve their heat rates and thereby 

reduce their rates of CO2 emissions with respect to generation. 

 The EPA has analyzed the technical feasibility, costs, and 

magnitude of CO2 emission reductions achievable through heat rate 

improvements at coal-fired steam EGUs based on engineering 

studies and on these EGUs’ reported operating and emissions 

data. We conclude that taking action to improve heat rates is a 

common and well-established practice within the industry that is 

capable of achieving meaningful reductions in CO2 emissions at 

reasonable cost. 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. 

 Consideration of other BSER factors also favors a 

conclusion that building block 1 is a component of the BSER. For 

example, with respect to non-air health and environmental 

impacts, heat rate improvements cause fuel to be used more 

efficiently, reducing the volumes of, and therefore the adverse 
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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 BSER without reference to 

technological innovation, we will 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). However, we believe that this concern can 

be readily addressed by ensuring that the BSER also reflects 

other CO2 reduction strategies that encourage increases in 

generation from lower- or zero-carbon EGUs or in demand-side 

energy efficiency, thereby allowing building block 1 to be 
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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.305 

b. Building block 2. Building block 2 –- reducing CO2 emissions 

at, and substituting for generation from, the most carbonintensive affected EGUs with generation from less carbonintensive affected EGUs (specifically NGCC units that are 

currently operating or under construction) –- 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 

 

305 Concern about a rebound effect could also be addressed by 

requiring that standards of performance for affected EGUs be set 

in the form of mass-based caps, but the EPA has determined that 

it is appropriate to allow states the flexibility to establish 

either emission rate-based or mass-based standards of 

performance for their affected EGUs. 
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from NGCC units through a variety of possible mechanisms. A 

steam EGU investing in incremental generation from NGCC units 

may choose to reduce its own generation or may maintain its 

generation level and choose to allow the reduction in generation 

to occur at other steam EGUs through the coordinated planning 

and operation of the interconnected electricity system. An 

affected EGU may also invest in emission reductions from 

building block 2 through the mechanism of engaging in emissions 

trading. 

 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. 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 –- 
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in some cases centralized and in others not -- that regularly 

deal with such changes on both a short-term and a longer-term 

basis. Our analysis demonstrates that the emission reductions 

that can be achieved or supported by such generation shifts are 

substantial and of reasonable cost. Further, both the 

achievability of this building block and the reasonableness of 

its costs are supported by the fact that there has been a 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., Congress has long recognized that generation 

shifts among EGUs are one means of reducing emissions from the 

utility power sector and multiple provisions of the CAA reflect 

that recognition, and generation shifts similarly have been 

recognized as 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 securityconstrained, 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 
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V.D. Thus, legislative history, regulatory precedent, and 

industry practice support interpreting the broad term “system of 

emission reduction” as including 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 

operating an NGCC unit it already owns more or by purchasing an 

existing NGCC unit and operating that unit more. Increases in 

generation by NGCC units over baseline levels can also serve as 

the basis for creation of CO2 emission rate credits (ERCs) –- 

that is, instruments representing the ability of incremental 

electricity generated by NGCC units to cause emission reductions 

at affected steam EGUs, as distinct from the incremental 

electricity itself. Again, it is important to note that the 

acquisition of such ERCs, represents an investment in the 

actions of the facility or facilities whose alteration of 

utilization levels generated the emissions rate improvement or 

reduction. In the context of the BSER, purchase of instruments 

representing the emissions-reducing benefit of an action is 
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simply a medium 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 emission rate credits by NGCC 

units and for the use of such credits 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 credits. 

The minimum criteria are discussed in section VIII of this 

preamble. 

 We note that an affected source 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 requirements that will be imposed on 

affected sources 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 

requirements, the decrease in generation resulting from that 
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coordinated operation is most likely to be generation from an 

affected steam EGU. Measures taken by affected sources that 

result in emission reductions from other sources in the source 

category may appropriately be deemed components of a “system of 

emission reduction.” 

 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.306 With respect to energy impacts, 

building block 2 represents replacement of electrical energy 

from one generator with electrical energy from another generator 

 

306 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 we consider the incentive for technological advancement 

only in the alternative, we note that building block 2 does not 

call for deployment of new technology, but does promote 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.307 Through application of this 

building block considered in isolation, some affected sources –- 

mostly coal-fired steam EGUs -- would reduce their generation 

and CO2 emissions, while other affected sources –- NGCC units –- 

would increase their generation and CO2 emissions. However, 

 

307 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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because for each MWh of generation, NGCC units produce fewer CO2

emissions than coal-fired steam EGUs, the total quantity of CO2

emissions from all affected sources in aggregate would decrease. 

In the context of the integrated electricity system, where the 

operation of affected EGUs of multiple types is routinely 

coordinated to provide a fungible service, and in the context of 

CO2 emissions, where location is not a consideration, in contrast 

with other pollutants, a measure that takes advantage of that 

integration to reduce CO2 emissions from the overall set of 

affected EGUs is readily encompassed within the meaning of 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). Emissions trading and other multi-unit compliance 

approaches can facilitate the implementation of such a “system” 

and have already been used in the electricity industry to 

address CO2 as well as other pollutants, as discussed above. 

c. Building block 3. Building block 3 –- reducing CO2 emissions 

at, and substituting for generation from, affected EGUs by using 

generation from expanded RE generating capacity –- is a 

component of the BSER because the expansion and use of renewable 
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generating capacity to reduce emissions from affected sources is 

technically feasible, will not jeopardize system reliability, is 

of reasonable cost, and performs well with respect to other 

factors relevant to a determination of the “best system of 

emission reduction ... adequately demonstrated.” Building block 

3 is a “system of emission reduction” for all affected EGUs 

because incremental RE generation will result in reduced 

generation and emissions from affected EGUs, and owners of 

affected EGUs can invest in incremental RE generation either 

directly or through the purchase of emission rate credits. 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. 

 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. We consider 

construction and operation of expanded RE generating capacity to 

be proven, well-established practices within the industry 

consistent with recent industry trends. States are already 
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pursuing policies that encourage production of greater amounts 

of renewable energy, such as the establishment of targets for 

procurement of renewable generating capacity. Moreover, markets 

are likely to develop for emission rate credits that would 

facilitate investment in increased RE generation as a means of 

helping sources comply with their standards of performance; 

indeed, markets for renewable energy certificates, which 

similarly facilitate investment in renewable energy for other 

purposes, are already well-established. As noted in Section 

V.A.5. below, an allowance system or tradable emission rate 

system would provide incentives for affected sources to reduce 

their emissions as much as possible, including through 

substituting for their generation with generation from renewable 

energy, 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. Both Congress and the 

EPA have previously established frameworks under which RE 

generation could be used as a means of achieving emission 

reductions from the utility power sector, as discussed in 

section V.B. Investment in RE generation has grown rapidly, such 

that in recent years the amount of new RE generating capacity 

brought into service has been comparable to the amount of new 
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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. Operation of new 

RE generating capacity could also serve as the basis for 

issuance of an ERC, and the owner of the affected EGU could 

either operate new RE generating capacity in order to obtain 

ERCs or could purchase ERCs created based on the operation of an 

unaffiliated RE generating facility, effectively investing in 

the actions at another site that allow CO2 emission reductions to 

occur. These mechanisms are discussed further in section V.A.5. 

As with building block 2, in this rule the EPA is establishing 

minimum criteria for the creation of valid emission rate credits 
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by new RE generators and for the use of such credits 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 source 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 sources in order to meet the emissions 

standards representing the BSER, an increase in RE generation 

will be offset elsewhere in the interconnection by a decrease in 

other generation. Because of the need to meet the collective 

requirements, the decrease in generation resulting from that 

coordinated operation is most likely to be generation from an 

affected EGU. As discussed in section V.B., measures taken by 

affected sources that result in emission reductions from other 
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sources in the source category may appropriately be deemed 

components of a “system of emission reduction.” 

 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 intermittent nature of generation from renewable resources 

such as wind and solar units requires special consideration from 

grid operators to address possible changes in operating reserve 

requirements, renewable generation has grown quickly in recent 

years, as discussed above, and grid planners and operators have 

proven capable of addressing any consequent changes in 

requirements through ordinary processes. The EPA similarly 

believes that planners and operators will be 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.H.2, will ensure the absence of 
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adverse energy impacts. With respect to technological 

innovation, an alternative consideration for the BSER, 

incentives for expansion of renewable capacity encourage 

technological innovation in improved renewable technologies as 

well as more extensive deployment of current advanced 

technologies. For all these reasons, the measures in building 

block 3 qualify as a component of the “best system of emission 

reduction ... adequately demonstrated.” 

d. Combination of all three building blocks. The final BSER 

includes a combination of all three building blocks. For the 

reasons described below, and similar to each of the building 

blocks, the combination must be considered a “system of emission 

reduction.” Moreover, as also discussed below, the combination 

qualifies as the “best” system that is “adequately 

demonstrated.” The combination is technically feasible; it is 

capable of achieving meaningful reductions in CO2 emissions from 

affected EGUs at a reasonable cost; it also performs well 

against the other BSER factors; and its components are wellestablished. The combination of the three building blocks will 

achieve greater CO2 emission reductions at reasonable costs than 

possible combinations with fewer building blocks and will also 

perform better against other BSER factors. We therefore find the 

combination of all three building blocks to be the “best system 
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of emission reduction ... adequately demonstrated” for reducing 

CO2 emissions at affected EGUs.308 

As already discussed, each of the individual building 

blocks generally performs well with respect to the BSER factors 

identified by the statute and the D.C. Circuit. The 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 

 

308 The analysis of the interactions among building blocks 

provided above for the combination of building blocks 1 and 2, 

indicating that the addition of building block 2 would mitigate 

the potential concern about a “rebound effect” if building block 

1 were implemented in isolation, applies to the combination of 

all three building blocks as well; in fact, the addition of 

building block 3 would further mitigate that concern. The EPA 

believes that if implemented in combination, each of the three 

building blocks would achieve substantial reductions in CO2

emissions from affected EGUs at a reasonable cost. 
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block 3 to replace any emitting generation are not exhausted. 

Thus, as the system of emission reduction is expanded to include 

each of these building blocks, the emission reductions that will 

be achieved increase. 

Because the stringency and timing of emission reductions 

achievable through use of each individual building block have 

been set based on what is achievable at reasonable cost rather 

than the maximum achievable amount, the stringency of the 

combination of building blocks is also reasonable, and the 

combination provides headroom and 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 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 
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competitive relative to other, lower-emitting fossil fuel-fired 

EGUs, possibly resulting in increased generation and higher 

emissions from the affected steam EGUs in spite of their lower 

emission rates. Combining building block 1 with the other 

building blocks addresses this concern by ensuring that 

owner/operators of affected steam EGUs as a group would have 

appropriate incentives not only to improve the steam EGUs’ 

efficiency but also to reduce generation from those EGUs 

consistent with replacement of generation by lower- or nonemitting EGUs and avoidance of generation through demand-side 

energy efficiency. While combining building block 1 with either 

building block 2 or 3 should address this concern, the 

combination of all three building blocks addresses it more 

effectively by strengthening the incentives to reduce generation 

from affected steam EGUs. 

The combination of all three building blocks is also of 

reasonable cost. In general, building blocks 2 and 3 do not 

interact with one another in a manner that would cause the cost 

of deploying any of these building blocks in combination with 

the other building blocks to be more than the cost of deploying 

the respective building block in isolation to the same degree of 

stringency. The EPA recognizes that as increasing quantities of 

generation from higher-emitting EGUs are replaced, the avoided 
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cost of the generation that is being replaced by lower- or nonemitting generation decreases, but this is a consequence of the 

greater emission reductions that can be achieved by combining 

building blocks, not an indication that any individual building 

block has become more expensive because of the combined 

deployment. Moreover, the likely use of emissions trading or 

other multi-unit compliance approaches, which are inherent in 

the building blocks as discussed above, will further reduce the 

overall costs of this rule by facilitating the ability of 

individual affected EGUs to take advantage of instances where 

other affected EGUs have opportunities to reduce emissions at 

lower cost. 

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).309 However, we 

 

309 If an EGU produces less generation output, then an 

improvement in that EGU’s heat rate and rate of CO2 emissions per 
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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, the cost of CO2 emission reductions 

achievable through heat rate improvements is quite low, and that 

cost will remain reasonable even if it is substantially 

increased. Second, although under a BSER encompassing all three 

building blocks the volume of coal-fired generation will 

decrease, that decrease is unlikely to be spread uniformly among 

all coal-fired EGUs. It is more likely that some coal-fired EGUs 

will decrease their generation slightly 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 

 

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. 
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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. 

For the regulatory impacts analysis accompanying this final 

rule, the EPA has assessed the costs, benefits, and other 

impacts of deployment of the final BSER through section 111(d) 

plans. The analysis reflects the compliance flexibility under 

the rule, along with transmission and pipeline capabilities and 

constraints, fuel market and electricity dispatch dynamics, and 

seasonal electricity load requirements. As described below in 

Section X, the results indicate that compliance with standards 

of performance consistent with the final BSER is readily 

achievable with no adverse impacts on electricity system 

reliability, and that impacts on retail electricity prices are 

modest and fall within the range of price variability seen 

historically in response to changes in factors such as weather 

and fuel supply. Further, the costs tend to decline over time as 

states and regulated entities take advantage of the available 

flexibility and expand deployment of more cost-effective 

measures (notably demand-side energy efficiency). The EPA 

considers this analysis strong confirmation of the 
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reasonableness of the costs of the measures in the three 

building blocks in combination as the best system of emission 

reduction. 

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. 

h. 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. Any combination of building 
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blocks including building block 1 and at least one other 

building block would address the concern about potential 

“rebound effect” discussed above. Finally, there is no reason to 

expect any combination of building blocks to have adverse nonair energy or environmental impacts. 

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 

strike down a building block, the BSER would comprise the 

remaining building blocks. 

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 1290 lbs. per net MWh 

for affected steam EGUs and a performance rate of 780 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. 
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 Under section 111(d), states determine the standards of 

performance for individual sources. The EPA is authorizing 

states to express the standards of performance applicable to 

affected EGUs as either emission rate-based limits or mass-based 

limits. As described above, the sets of actions that sources can 

take to comply with these standards are another expression of 

the BSER, viewed through an individual-source lens. 

 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: 

 Reducing its heat rate (building block 1). 

 Directly investing in, or purchasing emission rate credits 

created as a result of, incremental generation from existing 

NGCC units (building block 2). 

 Directly investing in, or purchasing emission rate credits 

created as a result of, generation from new or up-rated RE 

generators (building block 3). 

 Reducing its utilization, coupled with direct investment in or 

purchase of emission rate credits representing building blocks 2 

and 3 as indicated above. 

 Investing in surplus emission rate reductions at other 

affected EGUs through the purchase of rate-based emission 
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credits or the use of other multi-unit compliance 

approaches (e.g., averaging). 



 A source to which a state applies a mass-based limit can 

achieve the limit through a combination of the following set of 

measures (to the extent allowed by the state plan), all of which 

are likewise components of the BSER: 

 Reducing its heat rate (building block 1). 

 Reducing its utilization and allowing its generation to be 

replaced or avoided through the routine operation of industry 

reliability planning mechanisms and market incentives. 

 Investing in surplus emission reductions at other affected EGUs 

through the purchase of mass-based emission allowances or the 

use of other multi-unit compliance approaches (e.g., aggregation 

or bubbling). 

 The EPA has determined appropriate emissions standards for 

the source category 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 
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wide ranges of measures included in the BSER also provide 

assurance that each individual affected source 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 

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 deploy each of the 

building blocks in some way. In the following subsection we 

discuss the use of measures not in the BSER that can help 

sources achieve the standards of performance. 

a. Use of BSER measures to achieve an emission rate-based 

standard. Under an emission-rate based form of performance 

standards, compliance is nominally determined through a 

comparison of the affected EGU’s emission rate to the emission 

rate standard. Because an emission rate computed solely based on 
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measured stack emissions and measured electricity generation 

will not reflect the emissions-reducing impact of BSER measures 

that reduce CO2 emissions through reductions in the quantity of 

generation rather than through reductions in the amount of CO2

emitted per unit of generation, a plan that imposes emission 

rate-based standards of performance on affected EGUs will also 

need to authorize a rate computation mechanism whereby affected 

EGUs can adjust the rate computation to account for generation 

reduction measures. 

 One mechanism that the EPA has determined to be appropriate 

is to include emission rate credits (ERCs) in the emission rate 

computations that affected EGUs perform to demonstrate 

compliance with an emission rate standard. This mechanism is 

analogous to the approach the EPA has used to reflect building 

blocks 2 and 3 in the uniform emission rates representing the 

BSER, as discussed in section VI below. We have determined that 

one viable way to specify ERCs – which we believe offers 

benefits of fungibility and ease of tracking – is to define the 

ERCs associated with building blocks 2 and 3 as units of zeroemissions generation. As summarized below and as discussed in 

greater detail in section VIII and in the Rate-based Program 

Accounting TSD for the CPP Final Rule, the existence of a 

clearly feasible path for usage of ERCs ensures that emission 
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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 incremental generation 

from an existing NGCC unit or with ERCs issued on the basis of 

incremental generation from an existing NGCC unit. The 

owner/operator of the affected EGU accomplish this either 

through 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. 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 
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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 below, the EPA sets out the minimum 

criteria that must be satisfied for generation and issuance of a 

valid ERC based upon incremental electricity generation by an 

existing NGCC unit. Those criteria generally concern ensuring 

that the physical basis for the ERC –- i.e., incremental 

generation by an existing NGCC unit and the NGCC unit CO2

emissions associated with that incremental 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. 

 As noted above, the EPA has determined that one way to 

define an ERC –- which facilitates fungibility and tracking –- 

is to denominate each ERC in the form of a single zero-emissions 

MWh. NGCC units have non-zero CO2 emission rates, but their CO2

emission rates are lower than the CO2 emission rates of affected 
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steam EGUs. Consistent with the fact that the BSER for affected 

steam EGUs reflects the opportunity to replace generation from 

affected steam EGUs with incremental generation from existing 

NGCC units at a lower, but non-zero, emission rate, incremental 

generation by an existing NGCC unit can qualify as the basis for 

issuance of ERCs, but one incremental MWh of NGCC generation 

would be insufficient to serve as the basis for an ERC worth one 

full MWh of zero-emissions generation. The specific number of 

incremental MWh that an NGCC unit would need to generate in 

order to qualify for issuance of an ERC representing one MWh of 

zero-emissions generation would depend on the magnitude of the 

difference between the NGCC unit’s actual emission rate and the 

average standard of performance for affected steam EGUs in its 

state –- e.g., the uniform emission rate representing the BSER 

for steam EGUs. Details of the computation are provided in the 

Rate-based Accounting TSD for the CPP Final Rule available in 

the docket. 

 The owner/operator of an affected steam EGU would use the 

ERCs it has acquired for compliance –- whether acquired through 

ownership of NGCC capacity, a bilateral transaction, or an 

intermediated transaction –- by adding the ERCs to its measured 

net generation when computing its CO2 emission rate for purposes 
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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 generation from new 

(i.e., post-2012) RE generating capacity, including both newly 

constructed capacity and new uprates to existing RE generating 

capacity, or with ERCs issued on the basis of such generation. 

The owner/operator of the affected EGU can accomplish this 

either through common ownership of the RE generating capacity, a 

bilateral transaction with the owner/operator of the RE 

generating capacity, or a transaction for ERCs through an 

intermediary, which could, but need not, involve an organized 

market. 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. 
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 In section VIII below, the EPA sets out the minimum 

criteria that must be satisfied for generation and issuance of a 

valid ERC based upon generation from new RE generating capacity. 

Those criteria generally concern assuring that the physical 

basis for the ERC –- i.e., generation by from qualifying new RE 

capacity –- is adequately monitored and that there is an 

adequate administrative process for tracking credits to avoid 

double-counting and to facilitate enforceability of emission 

limits. 

 The types of RE generating capacity used by the EPA to 

quantify building block 3 are zero-emitting units. Under the 

definition of ERCs described above, each MWh of incremental 

generation by qualifying new RE generating capacity therefore 

can qualify as the basis for issuance of an ERC representing a 

full zero-emissions MWh.310 Further details are provided in the 

Rate-based Program Accounting TSD for the CPP Final Rule 

available in the docket. 

 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, 

 

310

 The possible use of types of RE generating capacity that are 

not necessarily zero-emitting, such as biomass, is discussed in 

section V.A.6. and section VIII of the preamble. 
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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 or otherwise invests in incremental generation from 

existing NGCC capacity or generation from new RE generating 

capacity. If the owner/operator does not average any ERCs or 

qualifying cleaner generation into the unit’s emission rate, 

reducing the unit’s own generation will proportionately reduce 

both the numerator and denominator of the fraction and therefore 

will not affect the computed emission rate. However, if the 

owner/operator does average ERCs or qualifying cleaner 

generation into the unit’s emission rate, then a proportional 

reduction in both the numerator and the portion of the 

denominator representing the unit’s measured generation will 

amplify the effect of the acquired ERCs in the computation, with 

the result that the more the unit reduces its generation, the 

fewer ERCs will be needed to reach a given emission rate-based 
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standard of performance. All owner/operators have the ability to 

reduce generation, and as discussed above all also would be 

capable of acquiring ERCs, so all would be capable of reflecting 

reduced utilization in their emission rates for purposes of 

demonstrating compliance. 

 (5) Emissions trading or other multi-unit compliance 

approaches. To the extent allowed under the relevant section 

111(d) plans, the owner/operator of an affected EGU can invest 

in surplus emission rate reductions not needed by another 

affected EGU and average those reductions into its own emission 

rate for purposes of demonstrating compliance with its ratebased standard of performance. A multi-unit approach without 

tradable credits is possible, commonly referred to as averaging. 

Alternatively, tradable credits could be used, reflecting an 

emissions trading approach. In either case, 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 to support the 

prediction that such authorization will be forthcoming from 

virtually all states that submit plans establishing standards of 

performance for their affected EGUs. 
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 Under an emissions trading approach, the owner/operator of 

the affected EGU can acquire surplus credits through common 

ownership of another affected EGU or through a bilateral 

transaction with the other affected EGU, or the owner/operator 

of the affected EGU can acquire credits in a transaction through 

an intermediary, which could, but need not, involve an organized 

market. 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 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. 

 One possible form of tradable credit that could be traded 

among affected EGUs would be a credit denominated in the form of 

a single zero-emission MWh, which would be entirely fungible 

with the form of ERC described above by which affected EGUs 

could acquire the emissions-reducing benefits of activating 

encompassed in building blocks 2 and 3. The number of MWh that 

an affected EGU with an emission rate below its standard would 
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need to generate to serve as the basis for issuance of each 

tradable credit – or, conversely, the number of tradable credits 

that a unit with an emission rate above its standard would need 

to acquire in order to achieve compliance – would be based on 

the difference between the unit’s actual emission rate and the 

unit’s standard of performance established in the applicable 

section 111(d) plan. Details regarding these computations are 

included in the Rate-based Program Accounting for the CPP Final 

Rule available in the docket. 

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 

source to be structured as a requirement to periodically 

surrender a quantity of emission allowances equal to the 

source’s monitored mass emissions. The EPA believes that section 

111(d) encompasses the flexibility for plans to impose massbased standards in the typical manner where the standard of 

performance for each affected EGU consists of a requirement to 
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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 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. Although some action or combination of actions to 

increase lower-carbon generation or reduce electricity demand 
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somewhere in the interconnected electricity system of which the 

affected EGU is a part will be required to enable electricity 

supply and demand 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 energy efficiency required to offset a 

reduction in the affected EGU’s generation, the owner/operator 

may do so as part of whatever role it happens to play as a 

participant in the interconnected electricity system. However, 

the owner/operator will achieve the benefit that reduction in 

generation brings toward compliance with the mass-based standard 

whether it takes those additional actions itself or instead 

allows other participants in the interconnected electricity 

system to play that role. 
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 (3) Emissions trading or other multi-unit compliance 

approaches. To the extent allowed under the relevant section 

111(d) plans -- as the record indicates that it will be -- the 

owner/operator of an affected EGU can invest in surplus emission 

reductions not needed by another affected EGU and can aggregate 

those reductions with its own emissions for purposes of 

demonstrating compliance with its mass-based standard of 

performance. This could be done through either approaches using 

tradable mass-based emission allowances or other multi-unit 

compliance approaches, which in this case would consist of 

aggregation or bubbling of emission limits. In either case, 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 an emissions trading approach, the owner/operator of 

the affected EGU 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. 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 
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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. 

6. Use of non-BSER measures to achieve standards of performance 

 In addition to the BSER-related measures that affected EGUs 

can use to achieve the standards of performance set in section 

111(d) plans, there are a variety of non-BSER measures that 

could also be employed (to the extent permitted under a given 

plan). This final rule does not limit the measures that affected 

EGUs may use for achieving standards of performance to measures 

that are included in the BSER; thus, the existence of these nonBSER measures provides flexibility allowing the individual 

affected EGUs and the source category to achieve emission 

reductions consistent with application of the BSER at the levels 

of stringency reflected in this final rule even if one or more 

of the building blocks is not implemented to the degree that the 

EPA has determined to be reasonable for purposes of quantifying 

the BSER. In this way, non-BSER measures therefore provide 
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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. 

 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 
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mass-based standard, the collective reduction in emissions from 

the set of affected EGUs is reflected in the collective 

monitored emissions from the set of affected EGUs. An individual 

EGU that reduces its generation and emissions will be able to 

use the measure to help achieve its mass-based limit. Individual 

EGUs that do not reduce their generation and emissions will be 

able to use the measure, if the relevant section 111(d) plans 

provide for allowance trading, by purchasing emission allowances 

no longer needed by EGUs that have reduced their emissions. 

 Under an emission rate-based standard, non-BSER measures 

that reduce generation from affected EGUs but do not reduce an 

affected EGU’s emission rate generally can facilitate compliance 

by serving as the basis for ERCs that affected EGUs can average 

into their emission rates for purposes of demonstrating 

compliance. For some non-BSER measures, each MWh of incremental 

generation produced by the measure or each MWh of fossil fuelfired generation avoided by the measure could qualify as the 

basis for issuance of an ERC representing a full zero-emissions 

MWh, similar to building block 3. For other non-BSER measures, 

more than one MWh of incremental generation would be required to 

qualify for the basis of an ERC representing a full zeroemissions MWh, similar to building block 2. Affected EGUs could 
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use such ERCs to the extent permitted by the relevant section 

111(d) plans. 

 The remainder of this section discusses some specific types 

of non-BSER measures. The first set discussed includes measures 

that can reduce the amount of CO2 emitted per MWh of generation, 

and the second set discussed includes measures that can reduce 

CO2 emissions by reducing the amount of generation from affected 

EGUs. In some cases, considerations related to use of these 

measures for compliance is 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. 

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 

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 other measures. Another reason was that the emission 
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reduction potential was limited compared to the potential 

available from the measures that were proposed to be included in 

the BSER. However, we also noted that circumstances could exist 

where these measures could be sufficiently attractive to deploy, 

and that the measures could be used to help affected EGUs 

achieve emission limits consistent with the BSER. 

 In the final rule, the EPA has reached determinations 

consistent with the proposal with respect to these measures: 

namely, that they do not merit inclusion in the BSER, but that 

they are capable of helping affected EGUs achieve compliance 

with standards of performance and are likely to be used for that 

purpose by some units. To the extent that they are selectively 

employed, they provide flexibility for the source category as a 

whole and for individual affected EGUs to achieve emission 

limits representative of the BSER, as discussed above. Further 

discussion of these measures is also provided in the GHG 

Mitigation Measures TSD for the CPP Final Rule. 

 (1) Heat rate improvement at affected EGUs other than coalfired steam EGUs. Building block 1 reflects the opportunity to 

improve heat rate at coal-fired steam EGUs but not at other 

affected EGUs. As the EPA stated at proposal, the potential CO2

reductions available from heat rate improvements at coal-fired 

steam EGUs are much larger than the potential CO2 reductions 
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available from heat rate improvements at other types of EGUs, 

and comments offered no persuasive basis for reaching a 

different conclusion. Nevertheless, we recognize that there may 

be instances where an owner/operator finds heat rate improvement 

to be an attractive option at a particular non-coal-fired 

affected EGU, and nothing in the rule prevents the 

owner/operator from implementing such a measure and using it to 

help achieve a standard of performance. 

 (2) Carbon capture and storage at affected EGUs. Another 

approach for reducing CO2 emissions per MWh of generation from 

affected EGUs is the application of carbon capture and storage 

(CCS) technology. Consistent with the June 2014 proposal, we are 

determining that use of full or partial CCS technology should 

not be part of the BSER for existing EGUs because it would be 

more expensive than the measures determined 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 
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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. 

 (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 coalfired 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 other 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 
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from coal-fired steam EGUs (building block 2) than by combusting 

natural gas instead of coal in steam EGUs. 

 Some owner/operators are already converting some affected 

EGUs from coal to natural gas, and it is apparent that the 

measure can be attractive compared to alternatives in certain 

circumstances, such as when a unit must meet tighter unitspecific limits on emissions of non-GHG pollutants, the options 

for meeting those emission limits are costly, and retirement of 

the unit would necessitate transmission upgrades that are costly 

or cannot be completed quickly. CO2 emission reductions achieved 

in these situations are available to help achieve emission 

limits consistent with the BSER. 

 (4) Fuel switching to biomass at affected EGUs. Some 

affected EGUs may seek to reduce their CO2 emission rates by cofiring qualifying biomass with fossil fuels. As discussed in 

section VIII below, the EPA recognizes that some biomass-derived 

fuels can play an important role in CO2 emissions reduction 

strategies. The EPA expects to recognize the biogenic CO2

emissions and climate policy benefits of waste-derived and 

certain forest- and agriculture-derived industrial byproduct 

feedstocks when considering state plans, based on the 

conclusions supported by a variety of technical studies. In 

addition, the EPA expects that states’ reliance on sustainably 
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derived agriculture- and forest-derived feedstocks may also be 

an approvable element of their state plans.311 As with the other 

non-BSER measures discussed in this section, the EPA expects 

that use of biomass may be economically attractive for certain 

individual sources even though on a broader scale it would 

likely be more expensive or less achievable than the measures 

determined to be part of the BSER. A state can propose 

qualifying biomass feedstocks and the proposed treatment of 

biogenic CO2 emissions in its plan. State plans must include 

analysis supporting how proposed qualifying feedstocks or 

feedstock categories are considered appropriate as a CO2 emission 

mitigation approach as well as the proposed treatment of 

biogenic CO2 emissions (i.e., the proposed level of biogenic CO2

emissions from use of the biomass feedstock that would not be 

counted when demonstrating compliance with emission limits 

consistent with the BSER). The EPA would review the 

appropriateness and basis for such determinations in the course 

of its review of a state plan. 

 (5) Waste heat-to-energy conversion at affected EGUs. 

Certain affected EGUs in urban areas or located near industrial 

facilities with needs for thermal energy may be able capture 

 

311 For a discussion of considerations concerning biomass in 

state plans, see section VIII.G.1.a.(2)(c)(i) of the preamble. 
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some of the waste heat from their electricity generation 

processes and use it to create useful thermal output, thereby 

engaging in a form of combined heat and power (CHP) production 

sometimes referred to as topping-cycle cogeneration. While the 

set of affected EGUs in locations making this measure feasible 

may be limited, where the measure is feasible the potential CO2

emission rate improvements can be substantial, because 

conversion of a conventional EGU to CHP configuration can 

increase the efficiency with which fuel is converted to useful 

energy 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 help the unit achieve a mass-based 

standard of performance.)

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 
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reducing the amount of generation from those EGUs. As discussed 

above, under a section 111(d) plan with mass-based standards of 

performance, no special action is required to enable measures of 

this nature to help the source category as a whole and 

individual affected EGUs achieve their emission limits, because 

the CO2-reducing effects are captured in monitored stack 

emissions. However, under a section 111(d) plan with rate-based 

standards of performance, some form of crediting such as the ERC 

mechanism described earlier is necessary in order to enable 

measures of this nature to help the source category as a whole 

and individual affected EGUs achieve the emission limits. 

 (1) Demand-side energy efficiency. One of the major 

approaches available for achieving CO2 emission reductions from 

the utility power sector is demand-side energy efficiency. In 

the June 2014 proposal, the EPA identified demand-side energy 

efficiency as one of the four proposed building blocks for the 

BSER. We continue to believe that significant emission 

reductions can be achieved by the source category through use of 

such measures at reasonable costs. In fact, we believe that the 

potential emission reductions from demand-side energy efficiency 

rival those from building blocks 2 and 3 in magnitude, and that 

demand-side energy efficiency will represent an important 

component of state plans, particularly in instances where a 
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state prefers to develop a plan reflecting the state measures 

approach discussed in section VIII below. We also expect that 

many sources would be interested in including demand-side energy 

efficiency in their compliance strategies to the extent 

permitted, and received comment that it should be permitted. 

 For the reasons discussed in section V.A.3.e. above, the 

EPA has determined not to include demand-side energy in the BSER 

in this final rule. However, the final rule authorizes 

generation avoided through investments in demand-side energy 

efficiency to serve as the basis for issuance of ERCs in defined 

circumstances. In section VIII 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 demandside EE programs. Those criteria generally concern assuring that 

the physical basis for the ERC -– in this case, generation 

avoided through implementation of demand-side EE measures –- is 

adequately monitored and that there is an adequate 

administrative process for tracking credits to avoid doublecounting and to facilitate enforceability of emission limits. 

The particular considerations related to evaluation, 

measurement, and verification of demand-side EE programs are 

also discussed in section VIII. 
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Through their authority over legal requirements such as 

building codes, states have the ability to drive certain types 

of demand-side energy efficiency measures that are beyond the 

reach of private-sector entities. The EPA recognizes that, by 

definition, this type of measure is beyond the ability of 

affected EGUs to invest in either directly or through bilateral 

arrangements. However, the final rule also authorizes generation 

avoided through such state policies to serve as the basis for 

issuance of ERCs that in turn can be used by affected EGUs. The 

section 111(d) plan would need to include appropriate provisions 

for evaluating, measuring, and verifying the avoided MWh 

associated with the state policies, consistent with the criteria 

discussed in section VIII below. 

 (2) New or up-rated nuclear generating capacity. In the 

June 2014 proposal, the EPA included generation from the five 

nuclear units currently under construction as part of the 

proposed BSER. As discussed above in section V.A.3., 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 
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order to realize that result. Accordingly, a section 111(d) plan 

may rely on ERCs issued on the basis of generation from these 

units and other new nuclear units. For the same reason, a plan 

may rely on ERCs issued on the basis of generation from up-rates 

to the capacity of existing nuclear units. The plan provisions 

to accommodate ERCs for generation from new and uprated nuclear 

capacity would be similar to the plan provisions necessary to 

accommodate ERCs issued on the basis of generation from new RE 

generating capacity (i.e., building block 3), which is also 

zero-emitting. These provisions are discussed in section VIII 

below. 

 (3) Zero-emitting RE generating technologies not reflected 

in the BSER. The range of available zero-emitting renewable 

energy generating technologies is broader than the range of RE 

technologies determined to be suitable for use in quantification 

of building block 3 as an element of the BSER. Examples of 

additional zero-emitting RE technologies not included in the 

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 
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equally capable of replacing generation from affected EGUs and 

thereby reducing CO2 emissions. Further, as with any technology, 

there are likely to be certain circumstances where the costs of 

these technologies are more attractive relative to alternatives, 

making the technologies likely to be deployed to some extent. 

Indeed, distributed solar is already being widely deployed in 

much of the United States and offshore wind, while still unusual 

in this country, has been extensively deployed in some other 

parts of the world. We expect innovation in RE generating 

technologies to continue, making such technologies even more 

attractive over time. A section 111(d) plan may rely on ERCs 

issued on the basis of generation from new and uprated 

installations of these technologies. The plan provisions to 

accommodate ERCs issued on the basis of generation from these RE 

generating technologies again would be similar to the plan 

provisions necessary to accommodate ERCs issued on the basis of 

generation from other RE generating technologies (building block 

3). 

 (4) Non-zero-emitting RE generating technologies. 

Generation from new or expanded facilities that combust 

qualifying biomass or biogenic portions of municipal solid waste 

(MSW) to produce electricity can also replace generation from 
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affected EGUs and thereby reduce CO2 emissions.312 While the EPA 

believes it is reasonable to consider generation from these 

technologies to be forms of RE generation, the fact that the 

technologies produce stack emissions containing CO2 means that a 

section 111(d) plan seeking to permit use of such generation to 

serve as the basis for issuance of ERCs must include appropriate 

consideration of feedstock characteristics and climate policy 

benefits. Again, as discussed in section VIII below, the EPA 

expects to recognize the biogenic CO2 emissions and climate 

policy benefits of waste-derived feedstocks and certain forestand agriculture-derived industrial byproduct feedstocks when 

considering state plans. The EPA also expects that states’ 

reliance specifically on sustainably-derived agriculture- and 

forest-derived feedstocks may also be an approvable element of 

their state plans. The EPA and many states have recognized the 

importance of integrated waste materials management strategies 

that emphasize a hierarchy of waste prevention and all other 

productive uses of waste materials to reduce the volume of 

disposed waste materials. Because it is likely that more than 

 

312 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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one MWh of incremental generation from these technologies would 

be required as the basis qualifying for the issuance of an ERC 

worth a full MWh of zero-emitting generation, the minimum 

requirements to accommodate ERCs issued on the basis of 

generation from these technologies would be similar to the plan 

provisions necessary to accommodate ERCs issued on the basis of 

incremental generation from existing NGCC units (building block 

2), supplemented by appropriate provisions to address special 

characteristics of the feedstocks. 

 (5) Waste heat-to-electricity conversion at non-affected 

facilities. Industrial facilities that install equipment to 

capture waste heat and then use the waste heat to generate 

electricity –- a form of combined heat and power (CHP) 

production sometimes referred to as bottoming-cycle cogeneration 

–- can produce generation that replaces generation from affected 

EGUs and thereby reduces CO2 emissions. A section 111(d) plan may 

rely on ERCs issued on the basis of generation of this nature 

provided that the facility does not generate and sell sufficient 

electricity to qualify as a new EGU for purposes of section 

111(b) and is not covered under section 111(d) for another 

source category. This form of CHP can be considered zeroemitting to the extent that the waste heat would have been 

produced by the industrial process anyway. To the extent that 
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the section 111(d) plan includes appropriate provisions for 

establishing that the heat input truly is waste heat, each MWh 

of incremental generation from this form of CHP could serve as 

the basis for issuance of an ERC worth a full MWh of zeroemitting generation similar to an ERC issued on the basis of 

building block 3. In order to permit ERCs issued on the basis of 

generation from facilities where the waste heat input is 

supplemented by fossil fuel input, the plan would need to 

include appropriate provisions for establishing the number of 

incremental MWh that would be generated in order to serve as the 

basis for issuance of each ERC worth one full MWh of zeroemitting generation, similar to the plan provisions required to 

support an ERC issued on the basis of building block 2. 

 (6) Reduction in transmission and distribution line losses. 

Reductions of electricity line losses incurred from the 

transmission and distribution system between the points of 

generation and the points of consumption by end-users allow the 

same overall demand for electricity services to be met with a 

smaller overall quantity of electricity generation. Such 

reductions in generation quantities would tend to reduce 

generation by affected EGUs, thereby reducing CO2 emissions. The 

opportunity for improvement is large because, on average, line 

losses account for approximately seven percent of all 
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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. This avoided generation is 

analogous to the generation avoided through demand-side energy 

efficiency described above, and each MWh of avoided generation 

could serve as the basis for creation of an ERC worth one full 

zero-emitting MWh of generation. The section 111(d) would need 

to include appropriate provisions for quantifying and verifying 

the avoided MWh associated with the transmission and 

distribution investments. 

7. Severability. 

 The EPA intends that the components of the BSER summarized 

above be severable. It is reasonable to consider the building 

blocks severable because the building blocks do not depend on 

one another. Each building block is a feasible and demonstrated 

means of reducing CO2 emissions from the utility power sector 
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that can be implemented independently of the other building 

blocks. 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, 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,313 although less than the combination of 

all three building blocks. No combination of the building blocks 

would lead to adverse non-air environmental or energy impacts or 

impose a risk to the reliability of electricity supplies. 

 In the event that a court should strike down any individual 

building block used to compute the emissions standards and state 

goals set forth in this rule, the standards and state goals can 

be recomputed on the basis of the remaining building blocks. All 

 

313 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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of the data and procedures necessary to determine recomputed 

state goals using any combination of the building blocks are set 

forth in the Final Rule Goal Computation TSD 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) EPA’s 

basis that building blocks 2 and, 3, and 4 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 controlling the design or operation 

of the affected source itself ’s own production processes or 

methods or because they are dependent on actions by entities 

other than the affected source; (2) the EPA’s basis for 

including trading or averaging as a component of BSER; (3) the 

EPA’s basis for including reduced generation as a component of 

the BSER; (4) the EPA’s authority to determine the BSER; (5) the 

consistency between the EPA’s identification of the BSER for 

this rule for CO2 emissions from existing affected EGUs and the 

BSER for the rules the EPA is promulgating at the same time for 

CO2 emissions from new or modified affected EGUs; (6) the 
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relationship between an affected EGU’s implementation of 

building blocks 2 and 3 and CO2 emissions reductions; and (7) the 

approach to subcategorization; and (8) reasons why, contrary to 

assertions by commenters, this rule is within the EPA’s 

statutory authority and does not represent what the U.S. Supreme 

Court described as “an enormous and transformative expansion in 

[the] EPA’s regulatory authority”.314

1. Building blocks 2 and 3 as a “system of emission reduction”

a. Overview. As we explain above, the performance standards for 

emissions that we include in this rule’s emissions guidelines 

are achievable by the affected EGUs through the application of 

the BSER, which includes the three building blocks. Commenters 

object that building blocks 2 (generation shift) and 3 

(renewable energy) cannot, as a legal matter, be considered to 

be part of the BSER under CAA section 111(d)(1) and (a)(1). 

These commenters explain that in their view, under CAA section 

111, the performance standards must be based on, and therefore 

BSER must be limited to, methods for emissions control that the 

owner/operator of the affected source can integrate into the 

design or operation of the source itself, and that cannot be 

based on actions taken beyond the source or actions involving 

 

314 Util. Air Regulatory Group v. EPA, 134 S. Ct. 2427, 2444 

(2014). 
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third-party entities.315 For 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. 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 

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 

 

315 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’ 

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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broad and, under Chevron step 1, is capacious enough to include 

actions taken by the owner/operator of a stationary source 

designed to reduce emissions from that affected source, 

including actions that may occur off-site and actions that a 

third party takes pursuant to a commercial relationship with the 

owner/operator, so long as those actions enable the affected 

source to achieve its emission limitation. The measures in 

building blocks 2 and 3, which include these types of actions, 

enable the affected EGUs to achieve their emission limits due to 

the unique characteristics of the utility power sector. For 

these reasons, we envision a “system of emission reduction” – as 

defined under CAA section 111(a)(1) and applied under CAA 

section 111(d)(1) -- as a big toolbox, which includes the 

measures in building blocks 2 and 3. It should be recalled, 

however, that CAA section 111 also requires that we determine 

that these measures are “adequately demonstrated” and represent 

the “best” system of emission reduction in order to serve as the 

basis for the emission reduction requirements. 

Our Chevron step 1 interpretation that the “system of 

emission reduction” is broad enough to include the measures in 

building blocks 2 and 3 is supported by the following: the 

phrase “system of emission reduction” is consistent with the 

“catch-all” nature of CAA section 111(d)(1), which is designed 
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to cover a range of source categories and air pollutants; 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 comparisons to 

other provisions of the CAA that give the EPA similar authority 

to consider such measures, and comparisons to other provisions 

that clearly narrow the field of measures to be considered. 

Finally, we note that contrary to arguments by commenters, no 

other provisions of CAA section 111 suggest that the phrase 

“system of emission reduction” must be limited to measures that 

the source’s owner can integrate into the design or operation of 

the affected source itself.. 

To the extent the phrase “system of emission reduction” is 

ambiguous, the EPA has discretion under Chevron step 2 to 

interpret it to include building blocks 2 and 3, for the reasons 

stated above, as well as 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
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emissions. (iii) Interpreting the phrase “system of emission 

reduction” to incorporate building blocks 2 and 3 is consistent 

with (a) other provisions in the CAA, including the acid rain 

provisions in Title IV and the SIP provisions in CAA section 

110, along with the EPA’s regulations implementing the CAA SIP 

requirements concerning interstate transport and regional haze, 

each of which is based on at least some of the same measures 

included in building blocks 2 and 3; (b) prior EPA action under 

CAA section 111(d), including the 2005 Clean Air Mercury Rule, 

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. (iv) 

Most broadly, interpreting the phrase “system of emission 

reduction” to give the EPA a big toolbox that includes building 

blocks 2 and 3 to reduce emissions is consistent with Congress’s 

intention to address urgent environmental problems and to be 

precautionary in protecting public health and welfare against 

risks, as well as Congress’s expectation that American industry 
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would be able to develop the innovative solutions necessary to 

protect public health and welfare. 

b. System of emission reduction as a big toolbox under Chevron

Step 1. 

(1) Plain meaning of “system of emission reduction”. CAA section 

111(d)(1) and (a)(1) make clear that because the purpose of the 

“system of emission reduction” is to serve as the basis for the 

emission limitation, and because the emission limitation must be 

“achievable” by the source, the “system of emission reduction” 

must be of a type that allows the source to achieve its emission 

limitation. 

The term “system” is not defined in the CAA. As a result, 

that term should be given its ordinary, everyday meaning, which 

is “a set of things working together as parts of a mechanism or 

interconnecting network; a complex whole.”316 With this 

definition, the phrase “system of emission reduction” takes a 

broad meaning: a set of things that work together to reduce 

emissions. In light of its context, this phrase carries an 

important limitation: because the emission limitation must be 

 

316 Oxford Dictionary of English (3rd ed.) (published 2010, 

online version 2013) 

http://www.oxfordreference.com.mutex.gmu.edu/view/10.1093/acref/

9780199571123.001.0001/acref-9780199571123. See The American 

College Dictionary (C. L. Barnhart, ed. 1970) at [X](“an 

assemblage or combination of things or parts forming a complex 

or unitary whole”).
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achievable through the application of the system of emission 

reduction, the system must be limited to things that can be 

implemented by the sources themselves, that is, as a practical 

matter, to actions taken by the owners or operators of the 

sources. Thus, actions that the owners/operators may take to 

achieve an applicable emission limitation qualify as a system of 

emission reduction.317 In contrast, actions that the state could 

take that would have the effect of reducing emissions from the 

source category, but that are beyond the ability of the affected 

sources’ owners/operators to take or control, would not qualify 

as a system of reduction for this purpose. 

Building blocks 2 and 3 each fall within the meaning of a 

“system of emission reduction” because they consist of measures 

that the owners/operators of the affected EGUs can implement to 

achieve their emission limits. In doing so, the affected EGUs 

will achieve the overall emission reductions the EPA identifies 

in this rule. We describe these building block 2 and 3 measures 

in detail elsewhere in this rule, including the specific actions 

 

317 Some commenters read the proposed rulemaking as taking the 

position that the phrase “system of emission reduction” includes 

anything whatsoever that reduces emissions, and criticized that 

interpretation as too broad. See UARG comment. In this final 

rule, we agree that the phrase should be limited to exclude 

actions beyond the ability of the owners/operators to take. 
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that owners/operators of affected EGUs can take to implement the 

measures. 

It should be noted that, although we do not need to 

determine the overall scope of the “system of emission 

reduction,” other limitations may also apply. For example, it is 

doubtful that payments by a source to a governmental entity to 

fund some sort of pollution prevention or emission control 

program would qualify as a system of emission reduction because 

the source may not be able to assure that the governmental 

entity will take the requisite action. A change in governmental 

policy could interfere with the implementation of the government 

program and, under those circumstances, the source would be 

unable to achieve the required degree of emission limitation. 

For purposes of this final rule, however, it is not 

necessary to enumerate all of the types of methods of emission 

reduction that do or do not constitute a “system of emission 

reduction.” What is relevant is that building blocks 2 and 3 

each qualify as part of the “system of emission reduction” 

because, as noted, 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. 
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(2) Other indications that the BSER provisions are a big 

toolbox. The EPA’s plain meaning interpretation of the BSER 

provisions in CAA section 111(d)(1) and (a)(1) as a big toolbox 

that is designed to include a broad range of measures, including 

building blocks 2 and 3, is supported by several other 

indications in the CAA and the legislative history of section 

111. 

(a) “Catch-all” nature of CAA section 111(d)(1). First, the 

“catch-all” nature of CAA section 111(d)(1) supports 

interpreting BSER as a big toolbox because a wide range of 

control measures is appropriate for the wide range of source 

categories and air pollutants covered under CAA section 111(d). 

 In the 1970 CAA Amendments, the Congress established a 

regulatory regime for existing stationary sources of air 

pollutants that may be envisioned as a three-legged stool, 

designed to address “three categories of pollutants emitted from 

statutory 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.318

 

318 40 FR 53340, 53340 (Nov. 17, 1975) (EPA regulations 

implementing CAA section 111(d)). 
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Congress enacted CAA section 111(d) to cover this third category 

of air pollutants and, in this sense, the Congress designed it 

to be a “catch-all” -- it would apply to any air pollutants that 

were not otherwise regulated as toxics or NAAQS pollutants.319

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.320 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).321 In 

 

319 See Sen. Rep. No. 91-1196, p. 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.”). 

320 See Sen. Rep. No. 91-1196, p. 20 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 420. 

321 See Sen. Rep. No. 91-1196, pp. 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 
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addition, in the 1990 CAA Amendments, Congress enacted CAA 

section 129 to achieve emission reductions from a major source 

category, solid waste incinerators, and established CAA section 

111(d) as the basic mechanism for that provision. The EPA 

subsequently promulgated a number of CAA section 129/111(d) 

rulemakings.322 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) as a “catchall” provision that covers a wide range of air pollutants -- 

including ones that Congress may not have been aware of at the 

 

the provisions that became sections 109-110 (and more “as 

knowledge increases”). In particular, the Report recognized that 

in particular, relatively few air pollutants may qualify as 

hazardous air pollutants, but that other air pollutants that did 

not qualify as hazardous air pollutants would be regulated under 

what became section 111(d). 

322 See, e.g., Standards of Performance for New Stationary 

Sources and Emission Guidelines for Existing Sources: 

Hospital/Medical/Infectious Waste Incinerators, 62 Fed. Reg. 

48,348, 48359 (Sept. 15, 1997); Standards of Performance for New 

Stationary Sources and Emission Guidelines for Existing Sources: 

Commercial and Industrial Solid Waste Incineration Units, 65 

Fed. Reg. 75338, 75341 (Dec. 1, 2000). 
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time it enacted the provision –- and a wide range of industries, 

it is logical that Congress intended that the EPA have broad 

discretion in determining the basis for emission limitations 

under CAA section 111(d), and that the BSER provision, as 

applied to CAA section 111(d), be broad-based so that it could 

accommodate this diversity. 

(b) Legislative history of CAA section 111. 

(i). Breadth of “system of emission reduction.” The legislative 

history of CAA section 111(d) and the term “standard of 

performance,” which includes the phrase “best system of emission 

reduction ... adequately demonstrated,” underscores the breadth 

that the Congress intended for the basis of CAA section 111(d) 

rulemaking. The version of CAA section 111(d)(1) that the 

Congress adopted as part of the 1970 CAA Amendments read largely 

as CAA section 111(d)(1) does at present, except that it 

required states to impose “emission standards” on any existing 

source. (Congress replaced that term with “standards of 

performance” in the 1977 CAA Amendments.) The 1970 CAA 

Amendments version of CAA section 111(d)(1) neither defined 

“emission standards” nor imposed restrictions on the EPA in 

determining the basis for the emission standards. Therefore, CAA 

section 111(d)(1), as it read in 1970, allowed the EPA broad 

discretion in determining the basis for the emission standards. 
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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 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.”323 The Senate bill, S. 4358, would have 

established “Federal standards of performance for new sources,” 

which, in turn, were to “reflect the greatest degree of emission 

control which the Secretary determines to be achievable through 

application of the latest available control technology, 

processes, operating methods, or other alternatives.”324 The 

Senate Committee Report explains that “performance standards 

 

323 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. 

324 S. 4358, § 6, 1970 Legis. Hist. at 554-55 (emphasis added). 
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should be met through application of the latest available 

emission control technology or through other means of preventing 

or controlling air pollution.”325 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.326 

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. 

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.327 

 

325 S. Comm. Rep. No. 91-1196 (Sept. 17, 1970), 1970 CAA Legis. 

Hist. at 415-16 (emphasis added). 

326 Sen. Rep. No. 91-1196, pp. 15-16 (Sept. 17, 1970), 1970 CAA 

Legis. Hist. at 415-16 (emphasis added). 

327 CAA section 111(a)(1) under the 1970 CAA Amendments (emphasis 

added). 
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While the term “system” was not discussed in the Conference 

Report or discussed in either chamber during the debates over 

passage of the Conference agreement, the final text clearly 

blends the broad spirit of S. 4358 (which required the “latest 

available control technology, processes, operating methods, or 

other alternatives”) with the cost concerns identified in H.R. 

17255 (which required consideration of “economic feasibility” 

when establishing federal emission standards for new stationary 

sources). The legislative history, therefore, confirms that the 

term “system” should be given its ordinary and broad meaning. 

The 1977 CAA Amendments signaled, for the most part, an 

ideological shift in CAA section 111’s approach for new sources. 

The Amendments revised CAA section 111(a)(1) to require “all new 

sources to meet emission standards based on the reductions 

achievable through the use of the ‘best technological system of 

continuous emission reduction.’ This means that new sources may 

not comply merely by burning untreated fuel, either oil or 

coal.” 328 This change 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 

 

328 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2659. 
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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.”329 Imposing a new technological 

requirement (along with a 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.” 330 

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,”331

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 

 

329 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2659. 

330 New Stationary Sources Performance Standards; Electric 

Utility Steam Generating Units, 44 Fed. Reg. 33580, 33581-33582 

(June 11, 1979). 

331 CAA section 111(a)(1)(C) under the 1977 CAA Amendments. 
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technological) for categories of existing sources to reduce 

emissions.”332 This was intended to distinguish existing source 

standards from new source standards, for which “the requirement 

for [BSER] has been more narrowly redefined as best 

technological system of continuous emission reduction.”333

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.” Further, nothing in the 1990 CAA Amendments or 

their legislative history indicates that Congress intended to 

impose new limits on the types of systems of emission reduction 

that could be considered under CAA section 111(d)(1) and (a)(1). 

In this manner, the 1990 CAA Amendments further reinforce the 

breadth and flexibility of the “system of emission reduction.” 

For these reasons, the 1970, 1977, and 1990 legislative 

history confirms the breadth of the term, “system of emission 

 

332 H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. at 

2662 (emphasis added). Congress also endorsed the EPA’s practice 

of establishing “emission guidelines” under CAA section 111(d). 

See H.R. Rep. No. 95-294 (May 12, 1977), 1977 CAA Legis. Hist. 

at 2662 (“The Administrator would establish guidelines as to 

what the best system for each such category of existing sources 

is. However, the state would be responsible for determining the 

applicability of such guidelines to any particular source or 

sources.”). 

333 Sen. Muskie, Sen. Consideration of the H.R. Conf. Rep. No. 

95-564 (Aug. 4, 1977), 1977 CAA Legis. Hist. at 353. 
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reduction,” and supports 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 the “system of 

emission reduction” must not include actions taken by entities 

other than the affected sources.334

 

334 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 
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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.”335 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 

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 

 

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.”). 

335 1977 CAA Amendments, § 109, 91 Stat. at 700; see also CAA 

section 111(a)(7). 
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refining, oil desulfurization at the refinery”).336 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 part of the best system of emission 

reduction for sulfur dioxide reductions promulgated under the 

1970 CAA Amendments), and in fact, the EPA’s regulations 

promulgated under the 1990 CAA Amendments have continued to 

 

336 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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impose standards of performance that are based on third-party 

coal cleaning.337

(c) Consistency of a broad interpretation of CAA section 111 

with the structure of CAA. Interpreting CAA section 111(d)(1) 

and (a)(1) to grant broad authority to the EPA to determine the 

basis for the standards of performance is in keeping with how 

Congress structured related provisions of the CAA, particularly 

in the 1970 CAA Amendments, when Congress added CAA section 111 

in much the same form that it reads today. 

 In the 1970 CAA Amendments, for the most part, and 

particularly for stationary source provisions, Congress painted 

with broad brush strokes, giving broad authority to the EPA or 

the states. That is, Congress established general requirements 

that were intended to produce stringent results, but gave the 

EPA or the states great discretion in fashioning the types of 

measures to achieve those results. For example, under CAA 

section 109, Congress authorized the EPA to promulgate national 

ambient air quality standards (NAAQS) for air pollutants, and 

Congress established general criteria and procedural 

requirements, but left to the EPA discretion to identify the air 

 

337 40 C.F.R. § 60.49b(n)(4); see also Amendments to New Source 

Performance Standards (NSPS) for Electric Utility Steam 

Generating Units and Industrial-Commercial-Institutional Steam 

Generating Units; Final Rule, 72 Fed. Reg. 32742 (June 13, 

2007). 
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pollutants and select the standards. Under CAA section 110, 

Congress required the states to submit to the EPA state 

implementation plans (SIPs), required that the plans attain the 

NAAQS by a date certain, and established procedural 

requirements, but allowed the states broad discretion in 

determining the substantive requirements of the SIPs. Under CAA 

section 111(b), Congress directed the EPA to list source 

categories that endanger public health or welfare, and 

established procedural requirements, but did not include other 

substantive requirements, and instead, gave the EPA broad 

discretion to determine the criteria for endangerment. Under CAA 

section 112, Congress required the EPA to regulate certain air 

pollutants and to set “emission standards” that meet general 

criteria, and established procedural requirements, but did not 

include other substantive requirements and instead, gave the EPA 

broad discretion in identifying the types of pollutants and in 
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determining the standards.338 By and large, Congress left these 

provisions intact in the 1977 CAA Amendments.339340

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 section 111(d) requirements are broadly 

phrased, include procedural requirements, 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 

 

338 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. 

339 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. 

340 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, as U.S. Supreme Court Associate Justice Kennedy has 

noted: Congress "usually does not legislate by specifying 

examples, but by identifying broad and general principles that 

must be applied to particular factual instances."341

(3) Comments and responses. Some 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. 

First, some commenters state that under CAA section 111, 

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 

 

341 Pub. Citizen v. U.S. Dept. of Justice, 491 U.S. 440, 475 

(1989) (Kennedy, J., concurring). 
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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 their terms limit 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, the affected sources subject to this rule 

are fully able to meet their emission standards by undertaking 

the measures described in building blocks 2 and 3. Moreover, as 

discussed, the measures in building blocks 2 and 3 are highly 

effective in achieving CO2 emission reductions from these 

affected EGUs, given the unique characteristics of the industry. 

This reinforces the conclusion that the term “system of emission 

reduction” is broad enough to include these measures. 

The broad nature of CAA section 111(d)(1) and (a)(1) is 

also confirmed by comparing it to CAA provisions that explicitly 

require controls on the design or operations of the affected 

sources. An example includes the requirement under CAA section 

407(b)(2) that the EPA base the NOx emission limits for certain 

types of boilers “on the degree of reduction achievable through 

the retrofit application of the best system of continuous 
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emission reduction” and further requires the EPA to revise 

previously promulgated emission limits for certain types of 

boilers “to be more stringent if the [EPA] determines that more 

effective low NOx burner technology is available.” (Emphasis 

added.) These narrower specifications for the basis of these 

Title IV emissions limits -- which were added in the 1990 CAA 

Amendments, at the same time that Congress revised the 

provisions of CAA section 111(a)(1) establishing the basis for 

controls under CAA section 111(d)(1) -- make clear that Congress 

knew how to constrain the basis for emission limits to measures 

that are integrated into the design or operation of the affected 

source, and that its choice to base CAA section 111(d)(1) and 

(a)(1) standards of performance on a “system of emission 

reduction” indicates Congress’ intent to authorize a broader 

basis for those standards. 

Commenters also argue that other provisions in CAA section 

111 indicate that Congress intended that CAA section 111(d)(1) 

and (a)(1) be limited to measures that are integrated into the 

source’s design or operations. These comments are 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 
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done so expressly, as it did for the above-discussed Title IV 

NOx requirements. Third, the interpretations that commenters 

offer for these various provisions are not persuasive. 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), 

which is stationary sources, as opposed to other types of 

sources (such as mobile sources), the emissions from which are 

addressed under other CAA provisions (such as CAA Title II).342

 

342 This purpose is made apparent by the terms of CAA section 

111(a)(3), which contains two sentences. The first sentence 

provides, “The term ‘stationary source’ mans any building, 

structure, facility, or installation which emits or may emit any 

air pollutant.” The second sentence provides: Nothing in 

subchapter II of this chapter relating to nonroad engines shall 
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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. 

In addition, 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 are able to take should be considered in 

determining the appropriate standards for the source’s 

emissions. 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.”343 The same is necessarily true for existing sources. 

This supports the EPA’s view that the basis for whether a 

 

be construed to apply to stationary internal combustion 

engines.” This second sentence makes clear that stationary 

internal combustion engines are to be regulated under section 

111, and not Title II (relating to mobile sources), which 

confirms that the purpose of the definition of stationary source 

is jurisdictional in nature -- to identify the emissions that 

are to be regulated under section 111, as opposed to other CAA 

provisions. 

343 CAA section 111(e) provides: (“[I]t shall be unlawful for any 

owner or operator of any new source to operate such source in 

violation of any [applicable] standard of performance.”) 
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control measure qualifies as a “system of emission reduction” 

under CAA section 111(d)(1) and (a)(1) is whether it is 

something that the owner/operator can implement in order to 

achieve the emissions standard assigned to the source – if so, 

the control measure should qualify as a “system of emission 

reduction” – and not whether the control measure is integrated 

into the source’s own design or operation. 

Commenters also argue that CAA section 111(h), which 

authorizes “design, equipment, work practice or operational 

standard[s]” (together, “design standards”) only when a source’s 

emissions are not emitted through a conveyance or cannot be 

measured, makes clear that CAA section 111 standards of 

performance must be based on measures integrated into a source’s 

own design or operations. We disagree. CAA section 111(h) 

concerns the relatively rare situation in which an emissions 

standard, which entails a numerical limit on emissions, is not

appropriate because emissions cannot be measured, due either to 

the nature of the pollutant (i.e., the pollutant is not emitted 

through a conveyance) or the nature of the source category 

(i.e., the source category is not able to conduct measurements). 

CAA section 111(h) provides that a design standard is 

appropriate under those circumstances, but only under those 

circumstances. When an emissions standard is appropriate, 
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including in the present rule, CAA section 111(h) is silent on 

which system of emissions reduction – whether limited to a 

source’s own design or operations -- may form the basis of the 

emissions standard. 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 renewable energy, as 

indicated by Congress’s inclusion of those measures in Title IV 

(relating to acid rain), so that the fact that Congress did not 

explicitly include these measures in the BSER provisions of CAA 

section 111(d)(1) and (a)(1) indicates that Congress did not 

intend that they be included as part of the BSER, and instead 

intended that the BSER be limited to measures integrated into 

the sources’ design or operations. This argument misses the 
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mark. The provisions of CAA section 111(d)(1) and (a)(1) do not 

explicitly include any specific control measures – neither 

renewable energy measures (like the ones Congress expressly 

included in Title IV), nor measures that are integrated into the 

sources’ design or operations (like the NOx control measures 

Congress also included in Title IV). 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 CAA section 111(d)(1) and (a)(1) as a 

big toolbox that affords the EPA a broad range of measures to 

choose from in determining the BSER.344

c. Chevron step 2 deference to interpret BSER to include the 

building blocks. Under the familiar Chevron step 2 analysis, if 

the plain meaning of the BSER provision under CAA section (a)(1) 

(and as applied under CAA section 111(d)(1)) does not answer the 

question of whether the phrase “system of emission reduction” 

includes the measures in building blocks 2 and 3, then the EPA’s 

interpretation that the provision does include those building 

blocks must be given deference as long as it is a reasonable 

 

344 It should also be noted that Title IV is limited to one type 

of source – 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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construction of the statute. In its 2014 decision upholding 

CSAPR, the U.S. Supreme Court re-affirmed Chevron deference for 

carrying out the provisions of the CAA, noting: “We routinely 

accord dispositive effect to an agency’s reasonable 

interpretation of ambiguous statutory language.”345 Moreover, in 

its 2011 decision holding that the CAA displaces the federal 

common law claim of nuisance, the U.S. Supreme Court generally 

recognized the breadth of CAA section 111, noting that “Congress 

delegated to the EPA the decision whether and how to regulate 

carbon-dioxide emissions from power plants....”346 

 Our interpretation that a “system of emission reduction” 

for the affected EGUs may include building blocks 2 and 3 is a 

reasonable construction of the statute for the reasons described 

above and in this section below. 

(1) Consistency of building blocks 2 and 3 with the structure of 

the utility power sector. 

(a) Integration of the utility power system. Certain 

characteristics of the utility power sector are of central 

importance for why the measures of building blocks 2 and 3 

qualify as part of the system of emission reduction. As 

discussed in detail above, electricity is fungible and the 

 

345 EPA v. EME Homer City, 134 S. Ct. 1584, 1603 (2014). 

346 American Electric Power v. Connecticut, 131 S. Ct. 2527, 2538 

(2011) (“AEP”). 
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utility power sector is highly integrated, so much so that it 

has been likened to a big machine. Specifically, the utility 

power sector is characterized by a physical interconnection 

between electricity generators themselves, and between those 

generators and electricity users. Because of the physical 

properties of electricity and the unavailability 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 
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institutional actors, to safeguard reliability and to assure 

least cost service. 

Congress,347 the Courts,348 the EPA in its regulatory 

actions,349 and states in their regulatory actions350 have 

recognized the integrated nature of the utility power sector. 

(b) Significance of integrated utility sector for 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 leads to the instantaneous increase in generation from 

other generators. This allows for locational flexibility across 

 

347 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 Sen. Rep. No. 101-228, pp. 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). 

348New York v. Federal Energy Regulatory Commission, 535 U.S. 1, 

at 7 (2002) (citing Brief for Respondent FERC 4-5). 

349 “Stack Heights Emissions Balancing Policy,” 53 Fed. Reg. 480, 

482 (Jan. 7, 1988). 

350 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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the sector in meeting demand for electricity services. The 

institutions that coordinate planning and operations routinely 

use this flexibility to economically meet demand for electricity 

services 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 

generation, and thereby lower emissions. In addition, fossil 
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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 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 CO2.351

(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 emissions.352 This is a strong indicator that these 

 

351 See UARG v. EPA, 134 S. Ct. 2427, 2441 (2014). 

352 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, 
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measures should be considered part of a “system of emission 

reduction” for CO2 emissions from these sources. The requirement 

that the “system of emission reduction” be “adequately 

demonstrated” indicates that the implementation of control 

mechanisms or other actions that the sources are already taking 

to reduce their emissions are of particular relevance in 

establishing the emission reduction requirements of CAA section 

111(d)(1) and (a)(1). As a result, such measures are a logical 

starting point for consideration as a “system of emission 

reduction” under CAA section 111. 

(3) Reliance in CAA Title IV on building block measures. Some of 

the building block 2 and 3 approaches to reducing emissions in 

the utility power sector were also well recognized at the time 

that Congress adopted the 1970 CAA Amendments.353 Over time, 

these techniques have become more established within the 

industry, and by the 1990 CAA Amendments, Congress expressly 

based the Title IV acid rain controls for existing fossil fuelfired EGUs on the same measures that are in those building 

 

http://austinenergy.com/wps/portal/ae/about/environment/austinclimate-protectionplan/!ut/p/a0/04_Sj9CPykssy0xPLMnMz0vMAfGjzOINjCyMPJwNjDzdzY0sDB

zdnZ28TcP8DAMMDPQLsh0VAU4fG7s!/. 

353 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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blocks. This provides an important indication that Congress not 

only viewed such measures as effective emission control 

techniques but that these same measures were already in use by 

the industry. 

(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 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 coal-fired power plants must have allowances 

for their sulfur dioxide emissions. 

Title IV includes several signals that it is especially 

relevant for interpreting and implementing CAA section 111(d) 

for purposes of this rule. Title IV applies to most of the same 

sources that this rule applies to -- existing coal-fired EGUs 

and other utility boilers, as well as NGCC units. In addition, 

Congress added Title IV in the 1990 CAA Amendments at the same 

time that Congress largely reinstated the 1970-vintage reading 

of section 111(a)(1) to adopt the currently applicable 
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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 

version of section 111(a)(1) would be reinstated.354

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.355 While 

 

354 1990 CAA Amendments, § 403, 104 Stat. at 2631 (requiring new 

units to hold allowances for each ton of sulfur dioxide 

emitted). Congress believed that mandating a technological 

standard through the percentage reduction requirement in 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. 

355 1990 CAA Amendments, § 406, 104 Stat. at 2632-33; see also

Sen. Rep. No. 101-228, at 282 (industrial source emissions 

totaled 5.6 million tons of SO2 in 1985). 
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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.”356 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 

111(d).357 Together, these signals suggest that it is reasonable 

for the EPA to consider Title IV when interpreting and 

implementing CAA section 111. 

For present purposes, the essential features of Title IV 

are that it regulates sulfur dioxide emissions from coal-fired 

EGUs by adopting a nationwide cap of 8.90 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 (8.90 million tons) and the overall 

structure of the approach (a cap-and-trade system) on Congress’s 

 

356 Sen. Rep. No. 101-228, at 345 (Dec. 20, 1989). 

357 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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recognition that the affected EGUs had a set of tools available 

to them to reduce their emissions, including through a shift to 

lower emitting generation and use of renewable energy, along 

with add-on controls and other measures. Thus, Title IV provides 

a close analogy to CAA section 111: generation shift and 

renewable energy were part of Congress’s basis for the Title IV 

emissions requirements, and that is analogous to building blocks 

2 and 3 serving as part of the “system of emission reduction” 

that is the EPA’s basis for the section 111(d) emission 

guidelines. For this reason, the fact that in Title IV, Congress 

relied on generation shift and renewable energy as the basis for 

the SO2 emission limitations for affected EGUs strongly supports 

interpreting CAA section 111(d)(1) and (a)(1) to include use of 

those same measures as part of the “system of emission 

reduction” as the basis for CO2 emission limitations for those 

same sources. 

(b) Title IV provisions. Several provisions of Title IV make 

explicit Congress’s reliance on some of the same measures as are 

in building blocks 2 and 3. Title IV begins with a statement of 

congressional “findings,” including the following: 

§401(a). Findings 

The Congress finds that – 

* * * * 
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(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 

the purpose of this subchapter to encourage energy 

conservation, use of renewable and clean alternative 

technologies, and pollution prevention as a long-range 

strategy, consistent with the provisions of this 

subchapter, for reducing air pollution and other 

adverse impacts of energy production and use. 

(Emphasis added). By its terms, this statement of Title IV’s 

purposes explicitly embraces the use of renewable energy. 

Moreover, the legislative history makes clear that the reference 

in the “findings” section quoted above to “strategies and 

technologies” includes generation shift to lower-emitting 

generation. Specifically, the Senate Report stated that an 

“allowance system”358 would encourage such “technologies and 

strategies” as – 

 

358 See Sen. Rep. No. 101-228, at 320 (Dec. 20, 1989).
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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.”359 

Congress’s reliance on generation shifting and renewable energy 

to reduce acid rain precursors from affected EGUs in Title IV 

strongly supports the EPA’s authority to identify those same 

measures as part of the CAA section 111 “system of emission 

reduction” to reduce CO2 emissions from those same sources. 

 In addition, Title IV includes other provisions expressly 

concerning renewable energy. In CAA section 404(f) and (g), 

Congress set aside a special pool of allowances to encourage use 

of renewable energy. In order to obtain a special allowance, an 

electric utility needed to pay for qualifying renewable energy 

sources “directly or through purchase from another person.” 

These measures confirm Congress’s recognition that renewable 

energy was available to the industry, was desirable to encourage 

from a policy perspective, and was appropriate to consider in 

determining the amount of pollution reduction the law should 

require. 

(c) Title IV legislative history. Numerous statements in the 

legislative history confirm that Congress based the Title IV 

 

359 See Sen. Rep. No. 101-228, at 316 (Dec. 20, 1989) (emphasis 

added). 
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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 renewable 

energy. 

For example, the Senate Committee Report360 and Senator 

Baucus,361 a member of the Senate Committee on Environment and 

Public Works and Chairman of the House and Senate Clean Air 

Conferees, both emphasized that affected EGUs could rely on, 

among other things, “least-emissions dispatching in order to 

maximize emissions reductions.” Similarly, statements supporting 

the renewable energy reserve were included in the legislative 

history on the House side. 

We believe that this provision of the bill will 

establish a balanced and workable approach that will 

provide certainty for utility companies that are 

considering conservation and renewables, while at the 

same time strengthening the environmental goals of 

this legislation.362 

 

360 Sen. Rep. to accompany S. 1630, Sen. Rep. 101-228 (Dec. 20, 

1989), 1990 CAA Legis. Hist. at 8656 

361 Sen. Debates on Conf. Rep. to accompany S. 1630, H. Rep. 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). 

362 H.R. Rep. No. 101-490, pp. 368-69; 674-76 (May 17, 1990) 

(additional views of of Reps. Markey and Moorhead) (“We believe 

that H.R. 3030, as amended, will create a strong and effective 

incentive for utilities to immediately pursue energy 

conservation and renewable energy sources as key components of 

their acid rain control strategies.”); see also Rep. Collins, H. 

Debates on H.R. Conf. Rep. No. 101-952 (Oct. 26, 1990), 1990 CAA 

Legis. Hist. at 1307 (“The bottom line is that our Nation's 
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Congress’s reliance, in adopting Title IV, on generation 

shifting and renewable energy as part of the basis for the 

emission standards contrasts with circumstances in which 

emissions standards were established based on add-on controls, 

but other measures – such as renewables – were seen as a 

compliance alternative. Examples of the latter are two of the 

air pollutant transport rules that the EPA promulgated after the 

1990 CAA Amendments: the NOx SIP Call (1998) and the Clean Air 

Interstate Rule (CAIR) (2005). For each of those rules, the EPA 

established the emission standards and requirements in large 

part on the basis of add-on controls, but authorized and 

encouraged the implementation of renewable energy measures as 

compliance measures.363 

(4) Reliance on renewable energy measures to reduce carbon 

dioxide. The Title IV legislative history also makes clear that 

Congress viewed renewable energy measures as a means to reduce 

 

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.”). 

363 CAIR: 70 Fed. Reg. 25,162, 25, 165, 25,256, 25, 279 (May 12, 

2005) (allowing use of allowance set-asides for renewables and 

energy efficiency); NOx SIP Call: 63 Fed. Reg. 57,356, 57,362, 

57438 (Oct. 27, 1998) (authorizing SIPs to rely on renewables 

and energy efficiency to meet the state budgets). 
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carbon dioxide for the purpose of mitigating climate change. By 

the time of the 1990 CAA Amendments, Congress had long been 

aware that emissions of carbon dioxide and other greenhouse 

gases put upward pressure on world temperatures and threatened 

to change the climate in destructive ways. In 1967, President 

Lyndon Johnson sent a letter to Congress recognizing that carbon 

dioxide was changing the composition of the atmosphere.364 The 

record for the 1970 CAA Amendments include hearings365 and a 

report by the National Academy of Sciences noting that carbon 

dioxide emissions could heat the atmosphere.366 A 1976 report 

noted the phenomenon was included in the record for the 1977 CAA 

 

364 “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.”). 

365 Administration Testimony, House Hearing (Mar. 16, 1970), 1970 

CAA Legis. Hist. at 1381 (testimony of Charles Johnson, Jr., 

Administrator of the Consumer Protection and Environmental 

Health Service, 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”). 

366 1970 CAA Legis. Hist. at 244, 257 Sen. Debate on S. 4358 

(Sept. 21, 1970) (statement of Sen. Boggs) (replicating Chapter 

IV of the Council on Environmental Quality’s first annual 

report, which states, “the addition of particulates and carbon 

dioxide in the atmosphere could have dramatic and long-term 

effects on world climate.”) 
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Amendments.367 A 1977 Report by the National Academy of Sciences 

warned that average temperatures would rise due to the burning 

of fossil fuel.368 By the time of the 1990 CAA Amendments, the 

dangers had become more clearly evident. Senate hearings 

beginning in 1988 had presented testimony from Dr. James E. 

Hansen of the National Aeronautics and Space Administration and 

other scientists that described the dangers of climate change 

caused by anthropogenic carbon dioxide and other greenhouse gas 

emissions and asserted that as a result of those emissions, the 

climate was in fact already changing.369 

 

367 122 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”). 

368 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). 

369 Sen. Rep. No. 101-228, p. 322 (Dec. 20, 1989), at 1990 Leg. 

Hist. at 8662 (“In the last several years, the Committee has 

received extensive scientific testimony that increases in the 

human-caused emissions of carbon dioxide and other greenhouse 

gases will lead to catastrophic shocks in the global climate 

system.”); History, Jurisdiction, and a Summary of Activities of 

the Committee on Energy and Natural Resources During the 100th
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 In enacting the 1990 CAA Amendments, Congress identified 

reductions in carbon dioxide emissions as an important cobenefit of the reductions in coal use and stressed that the 

renewable energy measures would achieve those reductions. 

Senator Fowler, the author of the provision that established a 

renewable energy technology reserve within the allowance system, 

noted that renewable energy technologies, “can greatly reduce 

emissions of ... global warming gases. That makes them a potent 

weapon against catastrophic climate change....”370 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. 

(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 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. 

 

Congress, Sen. Rep. No. 101-138, 5 (Sept. 1989); “Global Warming 

Has Begun, Expert Tells Senate,” New York Times, June 24, 1988 

http://www.nytimes.com/1988/06/24/us/global-warming-has-begunexpert-tells-senate.html. 

370 Sen. Fowler, Sen. Debate on S. 1630 (Apr. 3, 1990), 1990 CAA 

Legis. Hist. at 7106. 
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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).371 The EPA 

established a nationwide cap-and-trade program that took effect 

in two phases: In 2010, the cap was set at 38 tons per year, and 

in 2018, the cap was lowered to 15 tons per year. The EPA 

expected, on the basis of modeling, that sources would achieve 

the second phase, 15-ton per year cap cost-effectively by 

choosing among a set of measures that included shifting 

generation to lower-emitting units.372 CAMR was vacated by the 

D.C. Circuit on other grounds,373 but it provides a precedent for 

relying 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),374 in which it set statewide emission budgets for 

 

371 70 FR 28606 (May 18, 2005) (“Under the CAMR scenario modeled 

by EPA, units [were] projected to meet their SO2 and NOx

requirements and take additional steps to address the remaining 

[mercury] reduction requirements under CAA section 111, 

including adding [mercury]-specific control technologies (model 

applies [activated carbon injection]), additional scrubbers and 

[selective catalytic reduction], dispatch changes, and coal 

switching.”). 

372 70 FR 28606, 28619 (May 18, 2005). 

373 New Jersey v. EPA, 517 F.3d 574, 583-84 (D.C. Cir. 2008),

cert. denied sub nom. Util. Air Reg. Grp. v. New Jersey, 555 

U.S. 1169 (2009) 

374 76 Fed. Reg. 48208 (Aug. 8, 2011). 
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NOx, SO2, and particulate matter emitted by fossil fuel-fired 

EGUs, and based those standards in part on shifts to lower 

emitting generation. CSAPR established state-wide emissions 

budgets based on a range of cost-effective actions that EGUs 

could take, and set the stringency of the deadlines for some 

required reductions in part because of the availability of 

“increased dispatch of lower-emitting generation which can be 

achieved by 2012.”375 The EPA developed a federal implementation 

plan (FIP) that established a trading program to meet the statewide emission budgets set by CSAPR. The EPA projected that 

sources would meet their emission reduction obligations by 

implementing a range of emission control approaches, including 

the operation of add-on controls, switches to lower-emitting 

coal, and “changes in dispatch and generation shifting from 

 

375 76 Fed. Reg. at 48452. 
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higher emitting units to lower emitting units.”376 The U.S. 

Supreme Court upheld CSAPR in EME Homer v. EPA.377

 With respect to renewable energy, in 2004, the EPA provided 

guidance to states for adopting attainment SIPs under CAA 

section 110 that include renewable energy measures.378 Some 

states have done so. For example, Connecticut included in its 

SIP reductions from solar photovoltaic installations.379 In 2012, 

 

376 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 

Interstat1e Rule (CAIR) (2005). For both of those rules, the EPA 

established the emission standards on the basis of add-on 

controls and the availability of trading, but authorized and 

encouraged the implementation of renewable energy and demandside energy efficiency measures. CAIR: 70 Fed. Reg. 25162, 

25165, 25256, 25279 (May 12, 2005) (allowing use of allowance 

set-asides for renewables and energy efficiency); NOx SIP Call: 

63 Fed. Reg. 57356, 57362, 57436, 57438, 57449 (Oct. 27, 1998) 

(authorizing and encouraging SIPs to rely on renewables and 

energy efficiency to meet the state budgets). 

377 134 S. Ct. 1584 (2014). 

378See, e.g., Guidance on SIP Credits for Emission Reductions 

from Electric-Sector Energy Efficiency and Renewable Energy 

Measures (Aug. 2004), 

http://www.epa.gov/ttn/oarpg/t1/memoranda/ereseerem_gd.pdf; 

Incorporating Emerging and Voluntary Measures in a State 

Implementation Plan (SIP) (Sept. 2004), 

http://www.epa.gov/ttn/oarpg/t1/memoranda/evm_ievm_g.pdf. 379 CT 1997 8-hour ozone SIP Web site, 

http://www.ct.gov/deep/cwp/view.asp?a=2684&q=385886&depNav_GID=1

619 (see Attainment Demonstration TSD, Chapter 8 at 31, 

http://www.ct.gov/deep/lib/deep/air/ 

regulations/proposed_and_reports/section_8.pdf). 
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the EPA provided additional guidance on this topic.380 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 renewable energy in a SIP and to 

provide real-world examples and lessons learned through those 

states’ case studies.381

(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, virtually all pollution 

control requirements require the affected sources to depend in 

one way or another on other entities, such as control technology 

manufacturers. Second, the EPA has promulgated numerous 

regulatory actions that are based on emissions trading or 

 

380 “Roadmap for Incorporating EE/RE Policies and Programs into 

SIPs/TIPs” (July 2012), 

http://epa.gov/airquality/eere/manual.html.

381 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-repttoepa-ee-in-naaqs-sip-roadmap-case-studies-20140522.pdf. 
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averaging, in which many sources meet their emission limitation 

requirements by purchasing allowances or emission reduction 

credits from other sources that reduce emissions. 

(a) Third party transactions. To reiterate, commenters’ 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 install 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 
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install the controls needed by the affected EGUs.382 In addition, 

EGU owners and operators may be dependent on the actions of 

third-parties to finance the controls and third-party regulators 

to assure the mechanism for repaying that financing. However, 

this dependence does not mean that the emission limit based on 

that equipment is not achievable. Rather, the fact that the 

owner or operator of the affected source can engage in a market 

transaction 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 

to implement the measures in building blocks 2 and 3 are 

comparable to the market transactions that affected EGUs engage 

 

382 70 Fed. Reg. 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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in as part of their normal course of business, which include, 

among many examples, transactions with RTOs/ISOs or balancing 

authorities, entities in organized markets. 

(b) Emissions trading and averaging. Additional precedent 

that the “system of emission reduction” may include the measures 

in building blocks 2 and 3 and is not limited to measures that a 

source can integrate into its own design or operations, without 

being dependent on other entities, is found in the many rules 

that Congress has enacted or that the EPA has promulgated that 

allow EGUs and other sources to meet their emission limits by 

trading with other sources. In a trading rule, the EPA 

authorizes a source to meet its emission limit by purchasing 

allowances or emission reduction credits generated from other 

sources, typically ones that implement controls that reduce 

their emissions to the point where they are able to sell 

allowances or emission reduction credits. As a result, the 

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 on their own design or operations, but rather 

by purchasing allowances or emission reduction credits. These 
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affected sources, therefore, are dependent on the actions of 

other entities, which are the ones that choose to meet their 

emission limits by implementing emission controls, which permits 

them to sell allowances or emission reduction credits. Trading 

programs have been commonplace under the CAA, particularly for 

EGUs, for decades. The rest of this subsection briefly describes 

some of the main trading programs, focusing on the ones that 

primarily involve EGUs. For the reasons just described, these 

trading rules refute commenters’ arguments for limiting the 

scope of the “system of emission reduction.” 

In the 1990 CAA Amendments, Congress enacted the Acid Rain 

Program, as Title IV of the CAA. The Acid Rain Program applied 

to new and existing electric generating units in two phases. 

Phase II, which started in the year 2000, applies to more than 

2000 fossil fuel-fired EGUs across the continental U.S., and 

imposes an annual cap on SO2 emissions of 8.90 million tons, 

which was designed to achieve overall reductions of ten million 

tons of SO2 emissions or approximately a 50 percent reduction 

from 1980 emission levels. Under the program each affected EGU 

must surrender one allowance for each ton of SO2 that it emits. 

Each affected EGU is allocated a number of allowances for free. 

An affected EGU that implements controls may reduce its 

emissions to the point where it may have more allowances than 
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tons of emissions, in which case it can sell the allowances it 

does not need for its own emissions. An affected EGU that does 

not implement controls may not have enough allowances for its 

emissions and may therefore need to buy some. 

In enacting the program, Congress explicitly recognized 

that some sources would comply by purchasing allowances instead 

of implementing controls. Indeed, the purpose of the program was 

to achieve emission reductions by focusing controls on the 

sources for which controls were most cost-effective, and allow 

other sources to avoid implementing controls directly, and 

instead to purchase allowances, which had the effect of 

defraying part of the costs of controls for the sources that did 

implement controls.383 Prior to the development of the concept of 

trading, legislative efforts to reduce SO2 from fossil fuel-fired 

EGUs had failed because the cost of implementing controls were 

considered too expensive for some of the EGUs. Trading solved 

that problem. 

In addition, in enacting the trading program, Congress 

recognized that the power sector was particularly well-suited to 

 

383 Sen. Rep. No. 101-228, p. 303 (Dec. 20, 1989). 
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implement a trading program because of the highly transactional 

nature of the industry.384

The EPA has promulgated a series of rulemakings that apply 

to EGUs and that are based on the acid rain program. The EPA has 

promulgated several of these rules under CAA section 

110(a)(2)(D)(i)(I), the “good neighbor provision,” which 

requires an upwind state to include in its SIP measures to 

reduce emissions from its sources that adversely affect air 

quality in a downwind state. In 1998, the EPA promulgated the 

first of these transport rules, originally called the NOx SIP 

Call, and currently called the NOx Budget Trading Program. This 

rule set NOx emission budgets for certain states, and based each 

state’s budget on the cumulative emissions reductions that could 

be achieved primarily by the fossil fuel-fired EGUs in that 

state by implementing “highly cost-effective controls.” For 

 

384 See Sen. Rep. No. 101-228, pp. 319-20 (Dec. 20, 1989) (“In 

the management of the power they produce and deliver, utilities 

already engage in power-pooling arrangements to ensure maximum 

flexibility and efficiency in supplying power. Allowance-pooling 

could easily track power-pooling activities. At the same time, 

utilities have substantial experience in making long-term power 

and capacity sales to other utilities and could to [sic] the 

same with allowances, enabling those with up-front capital costs 

to receive revenues at the time they are incurring their 

expenses. In fact, a utility seeking to obtain allowances in 

lieu of making on-site reductions in order to meet compliance 

could underwrite directly a portion of the control technology or 

other costs incurred by the utility from whom it was to obtain 

the additional allowances.”). 
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EGUs, the emission rate was 0.15 lb/MMBtu for both oil/gas-fired 

EGUs and coal-fired EGUs. The EPA concluded that while it might 

be less cost-effective for some individual EGUs to meet that 

emission rate through installing on-site controls, those EGUs 

could purchase allowances through a trading program, so that 

overall the emission rate remained highly cost-effective.385 The 

EPA explained -- 

In this rulemaking, EPA has chosen to focus on an 

average cost-effectiveness measure in identifying 

highly cost-effective control options for several 

reasons. Since EPA's determination for the core group 

of sources is based on the adoption of a broad-based 

trading program, average cost-effectiveness serves as 

an adequate measure across sources because sources 

with high marginal costs will be able to take 

advantage of this program to lower their costs.386

In 2005, the EPA promulgated an expanded and more stringent 

transport rule, the CAIR, which regulated SO2 as well as NOx

emissions from fossil fuel-fired EGUs through a tradable 

allowance system. Similar to the NOx SIP Call, the state budgets 

set by CAIR were based on cost-effective controls on EGUs. The 

EPA’s evaluation of the cost impacts of CAIR assumed that EGUs 

would be participating in an interstate trading program.387 The 

EPA explained that -- 

In modeling the CAIR with the IPM, EPA assumes 

interstate emissions trading. While EPA is not 

 

385 63 Fed. Reg. 57356, 57399, 57413, 57457 (Oct. 27, 1998). 

386 63 FR at 57399 (emphasis added). 

387 70 Fed. Reg. 25162, 25196 (May 12, 2005). 
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requiring states to participate in an interstate 

trading program for EGUs, we believe it is reasonable 

to evaluate control costs assuming states choose to 

participate in such a program since that will result 

in less expensive reductions.388 

In 2011, the EPA promulgated the CSAPR, which regulated 

interstate transport of SO2, NOx, and particulate matter 

emissions from fossil fuel-fired EGUs through a tradable 

allowance system.389 Here, again, the EPA concluded that -- 

the preferred trading remedy will allow source owners 

to choose among several compliance options to achieve 

required emission reductions in the most cost 

effective manner, such as installing controls, 

changing fuels, reducing utilization, buying 

allowances, or any combination of these actions.390

As with the previous two interstate transport programs, the EPA 

in CSAPR recognized that interstate trading was a particularly 

well-suited mechanism for addressing emissions from EGUs because 

of “the power sector’s ability to operate as an integrated, 

interstate system and to promote reliability.”391

In fact, the Acid Rain Program and the transport rules have 

resulted in large numbers of fossil fuel-fired EGUs purchasing 

allowances instead of implementing controls. For example, SO2

control options available to sources include switching to low 

 

388 70 Fed. Reg. at 25196. 

389 76 Fed. Reg. 48208 (Aug. 8, 2011). 

390 76 Fed. Reg. at 48272. 

391 76 Fed. Reg. at 48272. 
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sulfur coal, employing various types of flue gas desulfurization 

(FGDs), or utilizing fluidized bed limestone units, as well as 

purchasing allowances. As Table 5, below, shows, as of 2012, 

more than half the coal-fired EGUs in the ARP and CAIR annual SO2

program, which EGUs generate 33 percent of the electricity from 

coal-fired units in those programs, comply with their ARP and 

CAIR SO2 emission limits simply by holding allowances – many of 

which are purchased from other entities – and without 

implementing controls. 

Table 5. SO2 Controls in 2012 on Coal-Fired Units in the ARP and 

CAIR Annual SO2 Program392

SOx Control 

Type 

Number of 

Units 

Share of Units Share of MWh 

Generation 

FGD 468 44% 66% 

Other 43 49% 1% 

Uncontrolled 545 52% 33% 

Source: EPA, 2013 

By the same token, in 2005, the EPA promulgated rulemaking 

under CAA section 111(d) to control mercury emissions from 

affected EGUs: The CAMR. The rule promulgated a two-phase, 

nationwide, interstate, allowance-based cap-and-trade program 

for mercury. The EPA specified budgets for each state, based on 

 

392 http://epa.gov/airmarkets/progress/ARPCAIR12.html 
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the sum of allowances allocated to each existing EGU located in 

the state. The number of allowances allocated to a particular 

EGU were based on the EGU’s pro rata share of the overall 

national cap on mercury emissions. In the first phase, the cap 

was 38 tons per year, and in the second phase, the cap was 

reduced to 15 tons per year. The EPA recognized that in the 

second phase, not all sources could cost-effectively install 

pollution control technology, but that the trading program would 

allow some sources to meet their requirements by “buying 

allowances.”393 

The EPA’s regional haze rules provide another example of a 

trading program in which sources – primarily, fossil fuel-fired 

EGUs – choose to meet their emission limits by purchasing 

allowances from other sources in lieu of implementing controls. 

CAA section 169A required the EPA to promulgate regulations to 

assure reasonable progress toward meeting the national 

visibility goal. CAA section 169A(b)(2) required the EPA to 

include in its regulations a requirement that states revise 

their SIPs to include “emission limitations, schedules of 

compliance and other measures as may be necessary to make 

reasonable progress toward the national goal,” including a 

requirement that certain older stationary sources “procure, 

 

393 70 Fed. Reg. 28606, 28619 (May 18, 2005). 
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install, and operate ... the best available retrofit 

technology,” more commonly known as BART. A 1993 Ninth Circuit 

decision held that the EPA could decide “not to adopt the 

emission control limits indicated by BART analysis, but instead 

to adopt an emission limitations standard that would produce 

greater visibility improvement at a lower cost.”394 

In 1999, the EPA promulgated the Regional Haze Rule, which 

allowed states to adopt trading programs or other alternatives 

in lieu of requiring retrofit controls at sources subject to 

BART.395 Specifically, the Regional Haze Rule provides: 

A state may opt to implement or require participation in 

an emissions trading program or other alternative 

measure rather than to require sources subject to BART 

to install, operate, and maintain BART.396

In a challenge to revisions to the Regional Haze Rule in 2003, 

the D.C. Circuit held that the EPA had reasonably interpreted 

section 169A(b)(2) as permitting alternatives to BART, including 

trading programs, so long as they achieve greater reasonable 

progress than would the installation of retrofit controls.397 The 

 

394 Central Arizona Water District v. EPA, 990 F.2d 1531, 1543 

(9th Cir. 1993). 

395 64 FR 35,714 (July 1, 1999) (codified at 40 C.F.R. 51.308-

309). 

396 40 CFR 51.308(e)(2). 

397 Ctr. for Econ. Dev. v. EPA, 398 F.3d 653, 660 (D.C. Cir. 

2005). 
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EPA has since approved several regional haze trading programs in 

lieu of BART.398 

(7) Consistency with the pollution prevention goals of the 

CAA. Interpreting the term “system of emission reduction” 

broadly to include the building blocks is also consistent with a 

primary purpose of the CAA, which is to encourage pollution 

prevention. CAA section 101(c) states that “[a] primary goal of 

[the CAA] is to encourage or otherwise promote reasonable 

federal, state, and local governmental actions, consistent with 

the provisions of this chapter, for pollution prevention.” 

Indeed, in the U.S. Code, in which the CAA is codified as 

chapter 85, the CAA is entitled, “Air Pollution Prevention and 

Control.” 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.399 

 

398 See, e.g., 77 FR 33,642 (June 7, 2012) (codified at 40 C.F.R. 

§ 51.308(e)(4)) (authorizing eastern states to rely on CSAPR in 

lieu of BART). 

399 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 
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The measures in building blocks 2 and 3 qualify as 

“pollution prevention” measures because they are “any measures” 

that “reduc[e] or eliminate[e] ... the amount of pollutants 

produced or created at the [fossil fuel-fired affected] 

source[s].” In light of one of 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. 

(8) Additional considerations. Interpreting CAA section 

111(d)(1) and (a)(1) to include building blocks 2 and 3 is 

consistent with the spirit of the CAA, including Congress’s 

intention to address urgent and severe environmental problems; 

to be precautionary in protecting public health and welfare 

against risks; and to promote technological advancement, based 

on the expectation that American industry could be able to come 

up with innovative solutions to those environmental problems. 

The 1970 CAA Amendments were designed to address urgent and 

severe problems, and authorized stringent remedies that were 

necessary to address those problems. Congress viewed the air 

 

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.” 
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pollution problem in 1970 as a crisis,400 and 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 ambient air quality 

standards to protect public health with an ample margin of 

safety, and required states to develop plans to assure that 

their air quality areas would meet those standards by no later 

than five years. Congress also required the EPA to establish 

 

400 1970 was a significant year in environmental legislation, but 

it was also marked as “a year of environmental concern.” Sen. 

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

Hist. at 223. By mid-1970, Congress recognized that “[o]ver 200 

million tons of contaminants [were] spilled into the air each 

year in America.... And each year these 200 million tons of 

pollutants endanger the health of [the American] people.” Id. at 

224. “Cities up and down the east coast were living under clouds 

of smog and daily air pollution alerts.” Sen. Muskie, Sen. 

Consideration of the Conference Rep. (Dec. 18, 1970), 1970 CAA 

Legis. Hist. at 124. Put simply, America faced an “environmental 

crisis.” Sen. Muskie, Sen. Debate on S. 4358 (Sept. 21, 1970), 

1970 CAA Legis. Hist. at 224. The conference agreement, it was 

reported, “faces the air pollution crisis with urgency and in 

candor. It makes hard choices, provides just remedies, requires 

stiff penalties.” Sen. Muskie, Sen. Consideration of the 

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

“[I]t represents [Congress’] best efforts to act with the 

knowledge available ... in an affirmative but constructive 

manner.” Id. at 150. 
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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.”401 

Addressing CO2 emissions from the utility power sector as 

the EPA does in this rule is consistent with Congress’s 

recognition of the need to effectively address severe and urgent 

public health threats from air pollution. Moreover, this rule is 

consistent with the comprehensive approach of the CAA. Congress 

was clear that “the [CAA] is the comprehensive vehicle for 

 

401 S. Committee Rep. to accompany S. 4358 (Sept. 17, 1970), 1970 

CAA Legis. Hist. at 420 (discussing section 114 of the Senate 

Committee bill, which was the basis for CAA section 111(d)). 

Note that in the 1977 CAA Amendments, the House Committee Report 

made a similar statement. House Comm. Rep. 95-294, at 41, Leg. 

Hist. vol. 4 at 2509 (discussing a provision in the House 

Committee bill that became CAA section 122, requiring EPA to 

study and then take action to regulate radioactive air 

pollutants and three other air pollutants). 
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protection of the Nation’s health from air pollution.”402 The 

building blocks are the methods available for meaningfully 

addressing CO2 emissions from existing affected EGUs on an 

industry-wide basis. 

This final rule is also consistent with the precautionary 

nature of the CAA. For example, the CAA authorizes the EPA to 

regulate air pollutants as soon as the EPA can determine that 

those pollutants pose a risk of harm, and not to wait until the 

EPA can prove that those pollutants actually cause harm.403

Similarly, as discussed next, the CAA generally is technologyforcing. The precautionary nature of the CAA extends to the 

present rule, in which the EPA regulates on the basis of 

building blocks 2 and 3, because the range of available and 

cost-effective measures in those building blocks achieves more 

pollution reduction than building block 1 alone. Indeed, add-on 

controls are not as cost-effective on an industry-wide basis, 

and while the costs of the add-on controls can be expected to be 

reduced over time, it is not consonant with the precautionary 

spirit of the CAA to wait. 

 

402 House Comm. Rep. 95-294, at 41, Leg. Hist. vol. 4 at 2509 

403 See 1977 House Comm. Rep. 95-294 at 49, 4 Leg. Hist. at 2516 

(describing the CAA as being designed to have a “preventive or 

precautionary nature..., i.e., to assure that regulatory action 

can effectively prevent harm before it occurs; to emphasize the 

predominant value of protection of public health”). 
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This final rule is also consistent with the purpose of CAA 

section 111 to advance technology. The legislative history and 

caselaw 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)404; (ii) the expanded use of the best 

demonstrated technology;405 and (iii) the development of emerging 

technology.406 This rule is consistent with the second of those 

ways – it expands the use of the measures in building blocks 2 

and 3, which are already established and provide the most 

reductions at the least 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, 

 

404 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”). 

405 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”). 

406 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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just described, that section CAA 111 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 

man on the moon a year earlier 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.407 

 

407 Sen. Muskie, Sen. 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 
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Commenters have stated that the proposed rule “would 

transform section 111 into something untethered to its statutory 

language and unrecognizable to the Congress that created it.”408

On the contrary, we believe that this rule would be instantly 

recognizable to the Congresses that created and amended CAA 

section 111. This final rule would be recognizable to the 

Congress that adopted CAA section 111 in 1970 as part of a 

stringent, comprehensive, law to address the air pollution 

crisis, that challenged industry to meet that crisis with the 

same creative energy that won World War II, and that gave 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 

 

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.”) 

408 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 Regulatory Group v. EPA, 134 S. Ct. 2427, 

2444 (2014). 
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(dispatch shifts and renewable energy), and that recognized that 

those measures (renewable energy) would also reduce carbon 

dioxide and thereby address the dangers of climate change. 

(9) Response to comments concerning building blocks 2 and 3 as 

precedents. Commenters 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.409 For example, commenters asserted that the EPA could 

“develop standards of performance for tailpipe emissions from 

motor vehicles” by “requiring car owners to shift some of their 

travel to buses,” which the commenters considered analogous to 

building block 2; “or by requiring there to be more electric 

vehicle purchases,” which the commenters considered analogous to 

building block 3.410

As discussed above, the emission limits in the CAA section 

111(d) emission guidelines that this rule promulgates are based 

on the EPA’s determination, for the affected EGUs, of the 

“system of emission reduction” that is the “best,” taking into 

account “cost” and other factors, and that is “adequately 

demonstrated.” Those components include certain interpretations 

 

409 Most of the commenters’ concerns over what they viewed as the 

precedential effects of the building blocks concerned building 

block 4. Because the EPA is not finalizing building block 4 as 

part of the BSER, it is not necessary to address those concerns. 

410 UARG comment at 2-3. 
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and applications. For example, because the affected EGUs must be 

able to achieve their emission standards through application of 

the BSER, the BSER must be something that the EGUs themselves 

can implement. The affected sources that are the subject of the 

emission guidelines can employ the BSER to achieve the emission 

limits that the guidelines prescribe. 

For the reasons discussed, building blocks 2 and 3 meet the 

definition of the BSER, as it has been interpreted and applied. 

As a result, they qualify as part of the basis for the emission 

limits in the emission guidelines promulgated in this rule. 

Moreover, as also discussed, the affected EGUs may meet those 

limits by implementing the BSER, including the measures in 

building blocks 2 and 3. Commenters’ concerns over precedential 

impact cannot be taken to mean that the building blocks should 

not be considered to meet the requirements of the BSER or that 

the affected EGUs cannot be considered to meet the emission 

limits by implementing those measures. 

Moreover, the application of building blocks 2 and 3 to 

affected EGUs has a number of unique characteristics that 

significantly limit their precedential impact. Building blocks 2 

and 3 entail the production of the same amount of the same 

product -- electricity, a highly substitutable product that can 

be produced using a variety of generation processes -- through 
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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 no capacity for substantial amounts of 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. 

Because of these characteristics, the electricity sector 

has a long and well-established history of substituting one type 

of generation for another. This has occurred for various 

reasons, including environmental reasons. As a result, at 

present, there is a well-established network of business 

relationships and past practices that supports building blocks 2 

and 3. As noted elsewhere, a large segment of steam generators 
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already have business relationships with existing NGCC units, 

and a large segment of all fossil fuel-fired EGUs already own, 

co-own, or have invested in renewable energy. 

Many of these characteristics are unique to the utility 

power sector. Moreover, this complex of characteristics, ranging 

from the physical properties of electricity and the integrated 

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.. 

 Because many of these individual characteristics, and their 

inherent complexity, are unique to the utility power sector, 

building blocks 2 and 3 as applied to fossil fuel-fired EGUs 

will have a limited precedent for other industries and other 

types of rulemakings. For example, the commenter’s examples 

noted above are inapposite for several reasons. Title II 

standards are based on “the application of technology which the 

Administrator determines will be available for the model 

year...,” which is a narrower standard than the “best system of 
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emission reduction ... adequately demonstrated.” Moreover, the 

examples appear to be premised on government action (i.e., that 

a government would “require[e] car owners to shift some of their 

travel 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. 

2. Legal justification for including emissions trading within 

the BSER. This section provides the legal justification for 

including trading or averaging within the BSER.411 

a. Background information. Emission trading may take one of two 

forms, depending on the form of the emission limitation to which 

the sources are subject. If the emission limitation is an 

emission rate (expressed, for example, in pounds of CO2 per MWh), 

then trading takes the form of buying or selling emission 

reduction credits (ERCs) that an affected EGU may generate if 

its actual emission rate is lower than its allowed emission 

rate. If the emission limitation is a mass-based limit 

(expressed, for example, in the form of a requirement that 

affected EGUs retire one allowance per ton of CO2 emissions), 

then trading takes the form of buying or selling allowances.412 

 

411 For convenience, in this section, references to “trading” 

include both trading and averaging. 

412 It should be noted that for affected EGUs subject to an 

emission rate, the BSER also includes purchase of ERCs from (i) 
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 (b) Emission trading within the BSER. Emissions trading, as 

applied in this rule, is within the “system of emission 

reduction” that is the “best” because it may operate in 

conjunction with the other types of emission reduction measures 

that are part of the BSER -- the building blocks -- to assure 

that the costs of those measures are lower and are allocated 

among the affected sources. In this final rule, the EPA has 

determined that the affected sources, taken as a whole, are able 

to implement building blocks 1, 2 and 3, and achieve the 

expected level of emission reduction. The EPA recognizes that it 

is not optimally efficient for each affected EGU to attempt to 

implement the measures in each building. Some affected EGUs are 

likely to be able to implement the control measures more costeffectively than other EGUs. Moreover, some EGUs may find it 

more cost-effective to implement other, non-BSER measures to 

reduce emissions, such as demand-side energy efficiency measures 

or co-firing. In addition, some sources may find it advantageous 

to retire. The EPA expects that through any of these avenues, 

some sources will reduce their emissions by more than they are 

 

existing NGCC units that increase their generation and (ii) 

renewable energy providers for new renewable energy, but 

although these ERCs may also be bought and sold, they are not 

covered by this present discussion of emission trading. Rather, 

this present discussion is focused on the trading of ERCs 

generated by an affected EGU whose actual emission rate is below 

its allowed emission rate, as well as allowances. 
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required, which would enable them to sell ERCs or allowances 

they no longer need to other affected EGUs whose control costs 

are higher and who would find it advantageous instead to 

purchase the ERCs or allowances. 

In this manner, the opportunity to trade creates incentives 

that have the effect of focusing controls on the sources for 

which those controls are the most cost-effective.413 The fact 

that emissions trading reduces overall costs is an important 

reason why it must be considered within the “system of emission 

reduction” that is the “best.” In addition, the inclusion of 

trading is feasible and has no adverse impacts on energy 

considerations for the individual affected EGUs or on a 

nationwide basis, nor does it result in emissions of non-air 

quality pollutants. Moreover, trading is especially effective 

for reducing CO2 emissions, due to the ubiquitous nature of CO2 

as a pollutant. 

Of particular importance, a trading program offers an 

affected EGU additional options for achieving its emission rate: 

In addition to implementing control measures to reduce its 

 

413 In enacting the cap-and-trade provisions of the Title IV Acid 

Rain Program in the 1990 CAA Amendments, Congress explicitly 

recognized that trading reduces overall program costs through 

the mechanism described in the text accompanying this footnote. 

The legislative history explained that the trading program was 

estimated to reduce overall costs by at least 20 percent. Sen. 

Rep. No. 101-228, p. 303 (Dec. 20, 1989).
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emissions, the source can purchase ERCs or allowances from other 

affected sources. Because under section 111(a)(1), a standard of 

performance is defined, in general, as an emission standard that 

reflects emission limits achievable through the application of 

the BSER, the fact that a source can rely on trading -- 

specifically, the acquisition of credits or allowances -- to 

achieve its emission limits, supports treating trading within 

the BSER. 

Trading is well-established, particularly for fossil fuelfired EGUs. As we discuss next, for the past 25 years, Congress 

and the EPA have adopted successful emissions trading programs 

for different air pollutants for these sources. Because trading 

is so well-established, it is reasonable to expect that states 

will allow trading as part of the emission standards they may 

adopt for their CAA section 111(d) state plans. 

Congress enacted the Acid Rain Program in Title IV of the 

1990 CAA Amendments as a nationwide cap–and-trade program for 

fossil fuel-fired EGUs to reduce SO2 emissions. In doing so, 

Congress expressed its understanding that emission trading would 

lower overall costs and assure that all the EGUs subject to the 

requirements would have a mechanism for achieving their emission 

limits. CAA section 401(b) provides: 

It is the intent of this subchapter to effectuate such 

reductions by requiring compliance by affected sources 
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with prescribed emission limitations by specified 

deadlines, which limitations may be met through 

alternative methods of compliance provided by an 

emission allocation and transfer system. 

The legislative history elaborates: 

[T]hrough a system of marketable allowances, the 

reduction programs established by the title maximize 

the range of choices sources have for complying with 

their emissions limitation requirements. An individual 

source may emit more than required if another source 

emits less than it, the latter, is permitted to emit. 

Through this flexibility, the bill minimizes costs and 

maximizes flexibility and efficiency. The EPA 

estimates that this added flexibility could reduce the 

total costs of the program by at least 20 percent. 

On a regional basis, this may allow areas with 

substantial reduction obligations and total costs to 

lower their net costs by producing and selling ‘extra’ 

reductions (i.e., reductions beyond those they are 

required to achieve) to sources seeking to emit more 

than is permitted. At the same time, areas facing 

growth in the energy demand or units with high 

emissions control cost on a per ton basis find that 

purchasing excess emissions reductions from plants in 

other areas, rather than making on-site reductions, 

enables them to comply with their emissions 

limitations at a significantly lower cost. 

Allowing sources to market ‘extra’ emissions 

reductions should also yield important environmental 

benefits as sources will have strong incentives to 

make greater-than-required reductions earlier than 

required. Since sources will enjoy maximum flexibility 

in responding to those incentives, this approach 

should also stimulate innovation in pollution-control 

technology and practices.414

Similarly, in CSAPR, the EPA addressed interstate transport 

of SO2, NOx, and particulate matter emitted by fossil fuel-fired 

 

414 Sen. Rep. No. 101-228, p. 303 (Dec. 20, 1989).
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EGUs by promulgating a tradable allowance system, and stated as 

follows: 

[T]his [trading] approach provides the most 

flexibility for sources while meeting the [CAA] 

requirements and protecting public health... EPA 

believes that the preferred trading remedy will allow 

source owners to choose among several compliance 

options to achieve required emission reductions in the 

most cost effective manner, such as installing 

controls, changing fuels, reducing utilization, buying 

allowances, or any combination of these actions.415 

As described above in this section, CSAPR is merely the most 

recent in a line of EPA interstate transport rules that took 

into account trading as a method for EGUs to reduce emissions. 

For example, the NOX SIP Call set state budgets based on a 

uniform emission standard for EGUs in part because those 

standards were “based on the adoption of a broad-based trading 

program” that would allow sources with higher marginal costs to 

more cost-effectively comply.416 Similarly, in CAIR, the EPA set 

state budgets based on cost-effective controls on EGUs and, in 

evaluating the cost impacts, “assume[d] interstate emissions 

trading” because of the reasonable likelihood that states and 

EGUs would use trading as the way to meet emission 

requirements.417 

 

415 76 Fed. Reg. at 48272. 

416 63 Fed. Reg. 57356, 57399 (Oct. 27, 1998). 

417 70 Fed. Reg. 25162, 25196 (May 12, 2005). 
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By the same token, in the 2005 rulemaking the EPA 

promulgated under CAA section 111(d) to control mercury 

emissions from affected EGUs -- the CAMR -- the EPA identified a 

nationwide cap-and-trade program as part of the BSER, along with 

add-on controls to reduce mercury emissions. The EPA projected 

that with a cap-and-trade program, mercury reductions would 

“result from units that are most cost effective to control, 

which enables those units that are not cost effective to use 

other approaches for compliance including buying allowances, 

switching fuels, or making dispatch changes.”418 This program 

enabled the EPA to set the cap’s stringency at a level 

commensurate with widespread compliance, whereas if the cap were 

based solely on the installation of control technologies, the 

cap would not be cost-effective for the source category.419 

In establishing the Title IV trading program, Congress 

recognized that fossil fuel-fired EGUs are well-suited to engage 

in emission trading: “[B]y their business nature,” Congress 

explained, “utilities appear to be well-suited to create, and to 

 

418 70 Fed. Reg. 28606, 28619 (May 18, 2005). 

419 In addition, in a 1995 rulemaking for municipal solid waste 

incinerators, the EPA also authorized states to allow large 

municipal waste combustors to average their emission rates and 

trade NOx emission credits. “Standards of Performance for New 

Stationary Sources and Emission Guidelines for Existing Sources; 

Municipal Waste Combustors,” 60 Fed. Reg. 65,387 at 28616-24, 

(Dec. 19, 1995). 
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take advantage of, an active market in emissions allowances.”420

In fact, Congress added, “utilities already engage in powerpooling arrangements to ensure maximum flexibility and 

efficiency in supplying power.”421 Moreover, Congress added, the 

allowance system enabled parties to “transfer between them and 

among themselves pursuant to a wide variety of commercial 

agreements such as under leases, sales agreements and exchanges 

between emissions and electric power or capacity.”422

The Energy Information Agency of the Department of Energy, 

in its annual report on electric power for the year 2000, noted 

that allowance purchases were one of the means by which the EGUs 

achieved their Title IV emission limits: 

On January 1, 2000, the electric industry came under 

Phase II regulations of the [CAA] Amendments of 1990. 

This Act was primarily designed to reduce power plant 

emissions, specifically sulfur dioxide and nitrogen 

oxides. Phase I, which began on January 1, 1995, 

affected 435 generating units and allowed the release 

of 2.5 pounds of sulfur dioxide per each million Btu 

of fuel consumed. Under Phase II, coverage increased 

to more than 2,000 units, while restrictions on 

emissions were set at 1.2 pounds of sulfur dioxide per 

million Btu of fuel consumed. Since 1995, some 

generators have over complied with Phase I in order to 

create excess allowances. This has allowed them to 

delay enacting additional strategies that would be 

necessary for compliance with Phase II. Strategies 

that are being used for compliance include fuel 

switching/ blending, co-firing with natural gas, 

 

420 Sen. Rep. No. 101-228, at 319 (Dec. 20, 1989). 

421 Sen. Rep. No. 101-228, at 319 (Dec. 20, 1989). 

422 Sen. Rep. No. 101-228, at 320 (Dec. 20, 1989). 
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allowance acquisitions, scrubbers, repowering, and 

plant retirements.423

In addition, beginning in 1998, the EPA has promulgated 

allowance trading programs in a series of rulemakings to reduce 

interstate transport in the eastern part of the U.S. of SO2, NOx, 

and particulate matter emissions from fossil fuel-fired EGUs in 

upwind states that jeopardize the ability of downwind states to 

attain and maintain the NAAQS.424 States and the EPA have 

implemented those requirements through SIPs and FIPs under CAA 

section 110. 

In addition, states have adopted allowance-based trading 

programs to control CO2 emissions from fossil fired EGUs.425 These 

programs have established the structural components of a trading 

program, including mechanisms to allocate allowances and track 

their ownership and use, and have operated trading programs, and 

have thereby demonstrated that a trading program for CO2

emissions from fossil fuel-fired EGUs can operate effectively. 

 

423 EIA, “Electric Power Annual 2000,” vol. 1 (August 2001) 13 

http://www.eia.gov/electricity/annual/archive/vol1/0348001.pdf

(emphasis added, citations omitted). 

424 For the NOx SIP Call, see 63 Fed. Reg. 57,356, XXXXX (Oct. 27, 

1998). For CAIR, see 70 Fed. Reg. 25,162, XXXXX (May 12, 2005) 

(Clean Air Interstate Rule); For CSAPR, see 76 Fed. Reg. 48,208 

XXXX (Aug. 8, 2011) (Cross-State Air Pollution Rule). 

425 The RGGI program regulates CO2 from fossil fuel-fired EGUs. 

The California AB32 program regulates CO2 from fossil fuel-fired 

EGUs and other sources. 
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It should also be noted that states have adopted other 

emission trading programs -- both rate-based trading programs 

and allowance trading programs -- that control a range of 

emissions from a range of sources. In some cases, these state 

programs have been included as part of SIPs and the EPA has 

approved them. For example, the South Coast Air Quality 

Management District adopted the Regional Clean Air Incentives 

Market (RECLAIM) program in October 1993 to establish a NOx and 

SOx emissions cap-and-trade program in the South Coast air basin. 

RECLAIM, which is codified in SCAQMD Regulation XX (Rules 2000 

through 2020), generally applies to stationary sources that emit 

4 tons or more per year of NOx or SOx in the year 1990 or 

subsequent years and establishes emissions caps for NOx and SOx

that decline over time. The program was designed to provide 

sources with incentives to reduce emissions and advance 

pollution control technologies by giving sources added 

flexibility in meeting emission reduction requirements.426 The 

EPA approved RECLAIM as a discretionary Economic Incentive 

 

426 See http://www.aqmd.gov/home/programs/business/businessdetail?title=reclaim. 
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program in June, 1998.427 The EPA has issued comprehensive 

guidance to states for adopting emission trading programs.428 

3. Reduced generation and 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, viewing the 

BSER through either the source-category perspective or the 

source-specific perspective, we are determining the BSER as the 

measures included in building block 1, as well as the set of 

measures included in building blocks 2 and 3, which incorporate 

reduced generation, along with the purchase of emission 

reduction credits or allowances. Reduced generation qualifies as 

part of the BSER because of the unique characteristics of this 

industry, which tie it closely to the measures in building 

blocks 2 and 3. The amount of generation from the increased 

utilization of NGCC units would determine a portion of the 

 

427 63 FR 32621 (June 15, 1998). 

428 Environmental Protection Agency, Office of Air and Radiation, 

“Improving Air Quality with Economic Incentive Programs,” EPA452/R-01-001 (2001). 

http://www.epa.gov/airquality/advance/pdfs/eipfin.pdf 
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amount of the generation reduction component of the BSER for 

affected fossil fuel-fired steam EGUs, and the amount of 

generation from the use of expanded renewable energy generating 

capacity that could be provided, would determine a portion of 

the amount of the generation reduction component of the BSER for 

all affected EGUs. This section discusses why reduced generation 

is a part of the BSER under this formulation. 

a. Background. As noted, for both rate-based and allowance-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 (e.g., a limit on amount of pounds of CO2 per 

MWh) by acquiring, through one means or another, credits from 

lower- or zero-emitting generation (building blocks 2 or 3, 

respectively) to reduce its actual emission rate. 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.429 Under these circumstances, the affected EGU 

would in effect replace part of its higher emitting generation 

with lower- or zero-emitting generation. On the other hand, an 

 

429 An affected EGU that is subject to an emission rate, e.g., 

pounds of CO2 per MWh generated, cannot achieve that rate simply 

by reducing its generation (unless it shuts down, in which case 

it would achieve a zero emission rate). This is because although 

reducing generation results in fewer emissions, it does not, by 

itself, result in fewer emissions per MWh generated. 
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affected EGU that is subject to an allowance requirement -- 

under which it must hold enough allowances to cover its 

emissions (e.g., one allowance for each ton of emissions in any 

year) -- may comply in part by reducing its generation and, 

thus, its emissions. Therefore, one type of action that an 

affected EGU may take to achieve either of these emission limits 

is to reduce its generation. 

Reduced generation is part of the BSER for affected EGUs 

for the following reasons, which generally must be understood 

against the backdrop of the integrated power sector: First, it 

is part of a “system of emission reduction” within the meaning 

of the BSER provisions because it is an action within the 

control of an affected EGU that reduces emissions. Indeed, it is 

a commonly used method for fossil fuel-fired EGUs to meet CAA 

obligations. Both Congress and the EPA have relied on it in 

establishing other CAA obligations, and there are wellestablished mechanisms for implementing it. Second, it meets the 

other components of the definition of BSER because it is 

feasible, results in fewer emissions, is of reasonable cost, 

does not have adverse implications for energy or non-air quality 

pollutants, and is adequately demonstrated. Third, in the 

context of this rule, it would lead to cleaner forms of 
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generation and would not result in adverse impacts on the 

utility power sector. 

b. System of emission reduction. Reduced generation is part of 

the “system of emission reduction” under CAA section 111(d)(1) 

and (a)(1) for this industry. Reduced generation is encompassed 

by the terms of the phrase “system of emission reduction” in CAA 

section 111(a)(1), as a matter of Chevron step 1, because, in 

accordance with the above-discussed definition of “system,” 

reduced generation is a “set of things” == which include reduced 

use of generating equipment and therefore reduced fuel input == 

that the affected EGU may itself take to reduce its CO2

emissions. If that phrase is not considered clear by its terms, 

then, under Chevron step 2, it may reasonably be interpreted to 

include reduced generation. As noted above, to achieve its 

emission standard, an affected EGU subject to an emission rate 

must combine reduced generation with the acquisition of 

sufficient emission reduction credits (so that it is, in effect, 

replacing its higher emitting generation with low- or zeroemitting generation), and an affected EGU subject to an 

allowance requirement must acquire sufficient allowances to 

cover its remaining emissions. 

 Reduced generation in the amounts contemplated in this rule 

reduces emissions from the affected sources, but because of the 
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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 constantly 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 system -- 

generation, transmission and distribution -- coordinate to 

deliver electricity from the point of generation to the point of 

consumption. This interconnectedness is a fundamental aspect of 

the nation’s electricity system, requiring a complicated 

integration of all components of the system to balance supply 

and demand and a federal, state and local regulatory network to 

oversee the physically interconnected network. Electricity from 

a diverse set of generation resources such as natural gas, 

nuclear, coal and renewables is distributed over high-voltage 
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transmission lines. The system is planned and designed 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 such as coal, nuclear, renewables and natural gas, as well 

as demand-side resources. If generation is reduced from one 

generator, safeguards are in place to ensure that adequate 

supply is still available to meet demand. 

Both Congress and the EPA have recognized reduced 

generation as one of the measures that fossil fuel-fired EGUs 

may implement to reduce their emissions of air pollutants and 

thereby achieve emission limits. Congress, in enacting the 

allowance requirements in CAA Title IV, under which fossil fuelfired EGUs must hold an allowance for each ton of SO2 emitted, 

explicitly recognized that fossil fuel-fired EGUs could meet 

this requirement by reducing their generation. In fact, Congress 

anticipated that fossil fuel-fired EGUs may choose to comply 

with the SO2 emission limits by reducing utilization, and 

included provisions that specifically addressed reduced 

utilization. For example, CAA section 408(c)(1)(B) includes 

requirements for an owner or operator of an EGU that meets the 
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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 the EGUs were 

expected to rely on to achieve their emission limitations. One 

example is includes 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.430 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.”431 Both the statutory factors and 

the regulatory definition resemble the definition of the BSER 

under CAA section 111(a)(1). In their regional haze SIPs, 

 

430 CAA section 169A(g)(2). 

431 40 C.F.R. § 51.301. 
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several states determined that BART included reduced generation, 

in the form of either capacity limitations or plant closures. 

For example, the State of Oklahoma determined that BART for the 

SO2 emissions from two coal-fired boilers at a power plant 

contained several elements, including “interim emission limits, 

the installation of Dry Sorbent Injection (DSI) and a fabric 

filter baghouse, phased reductions in capacity utilization, and 

enforceable deadlines by which [the boilers] must be shut down 

entirely.”432 Similarly, the State of New York determined that 

BART for the NOX emissions from two coal-fired boilers that 

served as peaking units was caps on baseline emissions rates and 

annual capacity factors of 5 percent and 10 percent, 

respectively.433 

There have been numerous other instances in which fossil 

fuel-fired EGUs have reduced their generation, or placed limits 

on their generation, in order to achieve, or obviate, emission 

standards. In fact, it is common for these EGUs to 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 

 

432 78 FR 51,686, 51,690 (Aug. 21, 2013) (emphases added). 

433 77 Fed. Reg. 24,794, 24,810 (Apr. 25, 2012). 
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Title V programs (including Title V fees), and avoiding 

triggering HAPs requirements. Such restrictions may also be 

taken to limit emissions of pollutants, such as limiting 

emissions of criteria pollutants for attainment purposes. 

More specifically, EPA’s regulations for a number of air 

programs expressly recognize that certain sources may take 

enforceable limits on hours of operation in order to avoid 

triggering CAA obligations that would otherwise apply to the 

source. Stationary sources that emit or have the potential to 

emit a pollutant at a level that is equal to or greater than 

specified thresholds are subject to major source requirements.434

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. 435

 

434 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). 

435 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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Such synthetic minor limits may be based on restrictions on the 

hours of operation, as provided in EPA’s regulations defining 

“potential to emit,” as well as on air pollution control 

equipment. “Potential to emit” is defined, for instance, in the 

regulations for the PSD program for permits issued under federal 

authority as: “the maximum capacity of a stationary source to 

emit a pollutant under its physical and operational design. Any 

physical or operational limitation on the capacity of the source 

to emit a pollutant, including air pollution control equipment 

and restrictions on hours of operation ... shall be treated as 

part of its design if the limitation or the effect it would have 

on emissions is federally enforceable,”436 or “legally and 

practicably enforceable by a state or local air pollution 

control agency." 437 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.”438 These 

 

436 40 CFR 52.21(b)(4)(emphasis added). 

437 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. 

438 See 40 CFR 51.166(b)(4) (addressing SIP approved PSD 

programs), 51.165(a)(1)(iii) (addressing SIP approved NNSR 
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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.439 

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, nitrogen oxides and sulfur dioxide below the 

PSD threshold of 250 tpy.440 As another example, Sunbury 

 

programs), 70.2 (addressing title V operating permit programs), 

and 63.2 (addressing hazardous air pollutants). 

439 See, e.g., 52.21(b)(4). 

440 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 
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Generation LP in Pennsylvania obtained a minor new source 

preconstruction permit, called a plan approval, for a repowering 

project from the Pennsylvania Department of Environmental 

Protection in 2013 that limited the hours of operation of three 

combined cycle combustion turbines that were planned for 

construction in order to remain below the significance threshold 

for GHGs.441 

There are several ways that an affected EGU may implement 

reduced utilization. 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 

 

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.”). 

441 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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impacts, which requires it to raise its bid price, so that the 

EGU is dispatched less]. 

c. Other BSER requirements and considerations. Reduced 

generation meets the criteria to be considered part of the 

“best” system of emission reduction that is “adequately 

demonstrated.” It is a feasible method of emission control 

because an affected EGU may reduce its generation by operating 

fewer hours, and may implement reduced generation through the 

methods just described. In addition, reduced generation results 

in fewer emissions, is of reasonable cost, and does not have 

adverse implications for energy use at the affected EGUs or 

result in non-air quality pollutants. 

Furthermore, reduced generation as a means for fossil fuelfired EGUs to reduce emissions is adequately demonstrated. As 

noted above, Congress recognized its use in enacting Title IV, 

the EPA has established emission limits in other rulemakings 

based in part these EGUs’ ability to achieve those limits by 

reducing generation, and in numerous instances, these EGUs have 

accepted limits on their generation in permits. 

At the levels proposed, these measures can be substituted for 

generation at affected EGUs at reasonable cost. The NGCC 

capacity necessary to accomplish the levels of generation 

reduction proposed for building block 2 is already in operation 
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or under construction. Moreover, it is reasonable to expect that 

the incremental resources reflected in building block 3 will 

develop at the levels requisite to ensure an adequate and 

reliable supply of electricity at the same time that affected 

EGUs may choose or be required to reduce their CO2 emissions by 

means of reducing their generation.442

d. Impacts on utility power sector. Reduced generation by 

affected EGUs, in the amounts that affected EGUs may rely on to 

comply with this rule, will not have adverse effects on the 

utility power sector. In light of the emission limits of this 

rule, and because the grid is interconnected and the electricity 

system is highly planned, reductions in generation by fossil 

fuel-fired EGUs in the amount contemplated under this rule, and 

occurring over the lengthy time frames provided under this rule, 

will result in replacement generation that generally is loweror zero- emitting. Mechanisms are in place in both regulated and 

deregulated electricity markets to assure that substitute 

 

442 It should be noted that in light of the low current and 

projected near term prices for natural gas, market forces may 

lead investors to choose to build new NGCC units, rather than 

new renewable resources. This result would not call into 

question the technical feasibility of a BSER that included 

reductions in fossil fuel-fired generation by the amount of a 

specified amount of new renewable resources. This is because 

under these circumstances, the fossil fuel-fired generators 

could still reduce their generation without causing reliability 

or other problems in the electric power system. 
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generation will become available and/or steps to reduce demand 

will be taken to compensate for reduced generation by affected 

EGUs. As a result, reduced generation will not give rise to 

reliability concerns or have other adverse effects on the 

utility power sector. Because of the availability of the 

measures in building blocks 2 and 3, the proposed levels of 

reduced generation are of reasonable cost for the affected 

source category and the nationwide electricity system, do not 

jeopardize reliability, and result in the appropriate amount of 

emission reductions. All these results come about because the 

operation of the electrical grid through integrated generation, 

transmission, and distribution networks creates fungibility 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 zeroemitting EGUs (building block 3) Further, this fungibility 

increases over longer timeframes with the opportunity to invest 

in infrastructure improvements, and as noted elsewhere, this 

rule provides an extended state plan and source compliance 

horizon. These characteristics of the integrated electricity 

system assure that reduced generation in specified amounts meets 
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the criteria to qualify as the “best” system of emission 

reduction. 

e. 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.”443 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. Buildings 

2 and 3 entail substitution of lower- or zero-emitting 

generation for higher-emitting generation, and a component of 

that substitution is reduced generation. Accordingly, our 

identification of the BSER in this final rule does not “rel[y] 

primarily” on reduced utilization as the BSER. 

Moreover, as also discussed, building blocks 2 and 3, as 

well as reduced generation, meet the requirements for the BSER, 

and therefore may serve as the basis for the emission guidelines 

in this rule, in accordance with CAA section 111(d)(1) and 

(a)(1). By the same token, reduced generation is one of several 

methods that affected EGUs may employ to achieve or help achieve 

the emission limits established by these emission guidelines. 

The commenter’s concerns over a perceived lack of a limiting 

 

443 EEI comment, at 284. 
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principle cannot be taken to mean that reduced generation cannot 

be considered to be a component of the BSER or constitute a 

method for affected EGUs to achieve their emission limits. 

Moreover, reduced generation, as applied to affected EGUs 

in this rule, is limited in a number of respects. The amount of 

reduced generation is prescribed. It is the amount of 

replacement generation that is lower- or zero- emitting, that is 

of reasonable cost, that can be generated without jeopardizing 

reliability, and that meets the other requirements for the BSER. 

As discussed, that amount is the amount of generation in 

building blocks 2 and 3. 

Moreover, 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 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 
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various reliability safeguards, will result in entities 

providing replacement generation. This means that consumers 

receive exactly the same amount of the same product, 

electricity, after the reduced generation that they received 

before it. No other industry is both physically interconnected 

in this manner and manufactures such a highly substitutable 

product; as a result, the use of reduced generation as a “system 

of emission reduction” is not easily transferrable to another 

industry. 

 4. The EPA authority to determine the BSER. In this 

section, we explain why the EPA, and not the states, has the 

authority to determine the BSER and, therefore, the amount of 

emission limitation required from the existing sources in the 

source category in section 111(d) rulemaking and the associated 

state plans. 

CAA section 111(d)(1) requires the EPA to establish a 

section 110-like procedure under which each state submits a plan 

that “establishes standards of performance for any existing 

source of air pollutant” and “provides for the implementation 

and enforcement of such standards of performance.” As CAA 

section 111(d) was originally adopted, in the 1970 CAA 

Amendments, state plans were required to establish “emission 

standards” -- an undefined term -- rather than “standards of 
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performance,” a term that was limited to CAA section 111(b).444

Prior to this change, however, the EPA issued regulations 

implementing CAA section 111(d) in 1975.445 These regulations 

established a cooperative framework, similar to that under CAA 

section 110, where the EPA first develops “emission guidelines” 

for source categories -- defined as a final guideline document 

reflecting “the degree of emission reduction achievable through 

the application of the best system of emission reduction which 

... the Administrator has determined has been adequately 

demonstrated” -- and states then submit implementation plans to 

regulate any existing sources.446 

The 1975 implementing regulations carefully considered the 

allocation of responsibilities as between the EPA and the states 

in regulatory actions under CAA section 111(d), and concluded 

that the EPA had the responsibility of determining the amount of 

emission limitation from the source category, while the states 

had the responsibility of assigning emission requirements to 

their sources that assured that amount of emission limitation. 

In issuing the regulations, the EPA explained “that some 

 

444 See “Clean Air Act Amendments of 1970,” Pub. L. 91-604, § 4, 

84 Stat. 1676, 1683-84 (Dec. 31, 1970). 

445 See “State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 FR 53,340 (Nov. 17, 1975). 

446 See ”State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 F.R. 53340 (Nov. 17, 1975). 
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substantive criterion was intended to govern not only the 

Administrator’s promulgation of standards but also [her] review 

of state plans.”447 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.”448 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] section 111(d).”449

In 1977, Congress revised CAA section 111(d) to require 

that the states adopt “standards of performance,” as defined 

under CAA section 111(a)(1). Currently, standards of performance 

are defined as “a standard for emissions of air pollutants which 

reflects the degree of emission limitation achievable through 

 

447 ”State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 F.R. 53340, 53342 (Nov. 17, 1975). 

448 ”State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 F.R. 53340, 53343 (Nov. 17, 1975). 

449 ”State Plans for the Control of Certain Pollutants From 

Existing Facilities,” 40 F.R. 53340, 53343 (Nov. 17, 1975). 
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the application of the best system of emission reduction which 

... the Administrator determines has been adequately 

demonstrated.” (Emphasis added.)450 By its terms, this provision 

provides that the EPA has the responsibility of determining 

whether the “best system of emission reduction” is “adequately 

demonstrated.” While this provision does not explicitly assign 

the responsibility to the EPA of identifying the “best system of 

emission reduction” in the first instance to the EPA, it is a 

logical inference that Congress intended that interpretation in 

light of the fact that the Administrator must make the 

“adequately demonstrated” determination. Even if the provision 

is considered to be silent on that question, the EPA reasonably 

interprets the provision under Chevron step 2 to assign that 

responsibility of identifying the “best system of emission 

reduction” to the EPA for the same reasons as discussed in the 

EPA’s explanation of the implementing regulations. 

In addition, in the legislative history of the 1977 CAA 

Amendments, Congress endorsed the overall approach of the 

implementing regulations, which lends further credence to the 

 

450 As noted, the 1977 version of CAA section 111(a)(1) differed 

from the current version, which was adopted in the 1990 CAA 

Amendments, but those differences do not call into the question 

the proposition that the EPA has the responsibility of 

determining the “best system of emission reduction ... 

adequately demonstrated” and, therefore, the amount of required 

emission limitation from the source category. 
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proposition that the EPA has the responsibility of determining 

the “best system of emission reduction” and the amount of 

emission limitation from the existing sources. Specifically, in 

the House report that introduced the substantive changes to CAA 

section 111, the Committee explained that “[t]he Administrator 

would establish guidelines as to what the best system for each 

category of existing sources is.” (Emphasis added.)451 States, on 

the other hand, “would be responsible for determining the 

applicability of such guidelines to any particular source or 

sources.” (Emphasis added.)452 The use of the term “guidelines,” 

which does not expressly appear in CAA section 111(d), indicates 

Congress was aware of and approved of the overall approach the 

EPA promulgated in its implementing regulations for determining 

the BSER. 

Commenters argued that the states should be given the 

authority to determine the best system of emission reduction 

and, therefore, the amount of emission limitation from their 

sources. For the reasons described above, this is an incorrect 

interpretation of CAA section 111(d)(1) and (a)(1). 

5. Relative stringency of requirements for existing sources and 

new and modified sources. Commenters also objected that the 

 

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

452 H.R. Rep. No. 95-294, at 195 (May 12, 1977). 
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proposed CAA section 111(d) standards are more stringent than 

the standards for new, modified or reconstructed sources, and 

they assert that setting section 111(d) standards that are more 

stringent than 111(b) standards would be illogical, contrary to 

precedent, contrary to the intent of the remaining useful life 

exception, and arbitrary and capricious.453 We disagree with 

these comments. 

Comparing the control requirements of the two sets of rules 

-- CAA section 111(d) and 111(b) –- is an “apples-to-oranges” 

comparison and, as a result, it is not possible to conclude that 

the 111(d) requirements are more stringent that the 111(b) 

requirements. 

 Most importantly, the two sets of rules have significantly 

different compliance times and compliance periods. The 

compliance time for the CAA section 111(b) rule for both new and 

modified sources is immediately upon construction or 

modification and, in fact, by operation of section 111(e) and 

(a)(2), new or modified sources that commenced construction 

prior to the effective date of the section 111(b) rule must also 

be in compliance upon the effective date of the rule. In 

contrast, the compliance time for the CAA section 111(d) rule 

 

453 ACC et al. (Associations) comments at 40, Luminant comments 

at 89. 
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does not begin until 7 years after promulgation of the rule, 

when the interim compliance period begins in 2022, and the final 

compliance time is not until 2030. Moreover, the compliance 

period for the interim requirements is 8 years. This longer 

compliance time and compliance period for existing sources 

accommodates a requirement that, on average, those sources have 

a lower nominal emissions limit than the requirements for new or 

modified sources, which those sources must comply with 

immediately. Indeed, it should be noted that under the schedule 

required under CAA section 111(b)(1)(B), the EPA would be 

required to review and revise the CAA section 111(b) rule 

shortly after the interim compliance time for the CAA section 

111(d) rule begins in 2022, and well before the final compliance 

date in 2030, which heightens the significance of the different 

compliance period. 

 In addition, for any individual source, the CAA section 

111(d) rule includes more flexible means of compliance. The 

state may assign emission limits differently than the EPA’s 

guidelines, and may be expected to authorize emissions trading 

or averaging. These flexibilities are not included in the CAA 

section 111(b) rule, rather, new and modified EGUs must meet the 

emission standard at all times. This distinction is another 
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reason why the CAA section 111(d) rule cannot be said to be more 

stringent than the CAA section 111(b) rule. 

6. Relationship between a source’s implementation of building 

blocks 2 and 3 and its emissions. In this section, we discuss 

the relationship between an affected EGU’s implementation of the 

measures in building blocks 2 and 3 and that affected EGU’s own 

generation and emissions. As discussed above, an affected EGU 

subject to a CAA section 111(d) state plan that imposes an 

emission rate may achieve that rate in part by implementing the 

measures in building block 2 (for a steam generator) and 

building block 3 (for a steam generator or combustion turbine). 

That is, an affected EGU may invest in low- or zero-emitting 

generation and may apply credits from those things against its 

emission rate. Those credits reduce the affected EGU’s emission 

rate and thereby help it to achieve its emission limit. 

In addition, the additional low- or zero-emitting 

generation that result from the affected EGU’s investment will 

generally displace higher-emitting generation. This is because, 

as described above, higher-emitting generation generally has 

higher variable costs, due to the fuel costs, than, at least, 

zero-emitting generation. Displacement of higher-emitting 

generation will lower overall CO2 emissions from the source 

category of affected EGUs. 
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If an affected EGU implements building block 2 or 3 by 

reducing its generation, it will reduce its own emissions. 

However, it may invests in other types of building block 2 or 3 

measures that do not, in-and-of-themselves, reduce the amount of 

its own emissions or, for that matter, its own generation. This 

is because the interconnected grid includes numerous generators, 

and electricity generation becomes undifferentiated the moment 

it is dispatched, so that it is not possible to trace 

electricity to any particular generator. Moreover, absent a 

limit on generation, such as, for example, one included in a 

permit, an affected EGU’s generation generally depends on where 

it falls on the dispatch curve. Even so, implementation of 

building blocks 2 and 3 will reduce CO2 from some affected EGUs, 

and therefore reduce CO2 on a source category-wide basis. 

This outcome is consistent with the requirements of CAA 

section 111(d)(1) and (a)(1). To reiterate, CAA section 

111(d)(1) requires that “any existing source” have a “standard 

of performance,” defined under CAA section 111(a)(1) as “a 

standard for emissions of air pollutants which reflects the 

degree of emission limitation achievable through the application 

of the best system of emission reduction ... adequately 

demonstrated [BSER] ....” These provisions require by their 

terms that “any existing source” must have a “standard of 
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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 

achieve the emission limits that result from the application of 

the BSER. The EPA is authorized to include in the BSER, for this 

source category, the measures in building blocks 2 and 3 

because, when applied to the source category, these measures 

result in emission standards that may be structured to ensure 

overall emission reductions from the source category and remain 

achievable by the affected EGUs. This remains so regardless of 

whether the “degree of emission limitation achievable through 

the application of the [BSER]” by any particular source results 

in actual emission reductions from that source. 
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The application of the building blocks has an impact that 

is similar to that of a trading program, under which, overall, 

the affected sources reduce emissions, but any particular source 

does not need to reduce its emissions and, in fact, may increase 

its emissions, as long as it purchases sufficient credits or 

allowances from other sources. Indeed, any emission rate-based 

standard may not necessarily result in emission reductions from 

any particular affected source (or even all of the affected 

sources in the category) due to the ability of the particular 

source (or even all of them) to increase its production and, 

therefore, its emissions, even while maintaining the required 

emission rate. 

7. Approach to subcategorization. As noted above, in this rule, 

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

and, in the emission guidelines that we are promulgating with 

this rule, we are treating steam EGUs and combustion turbines as 

separate subcategories. We are determining the BSER for steam 

EGUs and the BSER for combustion turbines, and applying the BSER 

to each subcategory to determine a performance rate for that 

subcategory. We are not further subcategorizing among different 

types of steam EGUs or combustion turbines. 

 This approach is fully consistent with the provisions of 

section 111(d), which simply require the EPA to determine the 
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BSER, do not prescribe the method for doing so, and are silent 

as to subcategorization. This approach is also fully consistent 

with other provisions in CAA section 111, which require the EPA 

first to list source categories that may reasonably be expected 

to endanger public health or welfare454 and then to regulate new 

sources within each such source category,455 and which grant the 

EPA discretion whether to subcategorize new sources for purposes 

of determining the BSER.456 

 Subcategorization may be appropriate when certain types of 

sources could not achieve the same emission limit as other types 

of sources, but here, each affected EGU can achieve the 

performance rate by implementing the BSER. Specifically, as 

noted, each affected EGU may take a range of actions –- some of 

which depend on whether the state imposes an emission rate or a 

mass limit -- including investment in the building blocks, 

replaced or reduced generation, and emissions trading. Further, 

in the case of a rate-based state plan, several other compliance 

options not included in the BSER for this rule are also 

available to all affected sources, including investment in 

demand-side energy efficiency measures. Such compliance options 

 

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

455 CAA section 111(b)(1)(B). 

456 CAA section 111(b)(2). 
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may also indirectly help affected sources achieve compliance 

under a mass-based plan. 

 Our approach of subcategorizing between steam EGUs and 

combustion turbines is reasonable because building blocks 1 and 

2 apply only to steam EGUs. Moreover, our approach of not 

further subcategorizing as between different types of steam EGUs 

or combustion turbines reflects the reasonable policy that 

affected EGUs with higher emission rates should reduce their 

emissions by a greater percentage than affected EGUs with lower 

emission rates. 

 Of course, a state retains great flexibility in assigning 

standards of performance to its affected EGUs and can, if it 

wishes impose different emission reduction obligations on its 

sources, as long as the overall level of emission limitation is 

at least as stringent as the emission guidelines, as discussed 

below. 

8. Reasons that this rule is within the EPA’s statutory 

authority and does not represent over-reaching. In this section, 

we respond to adverse comments that the EPA is overreaching in 

this rulemaking by attempting to direct the energy sector. These 

commenters construed the proposed rulemaking as the EPA 

proposing to mandate the implementation of the measures in the 

building blocks, including investment in renewable energy and 
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implementation of a broad range of state and utility demand-side 

energy efficiency programs. 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 (UARG)457 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.”458

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, the EPA is not 

finalizing either building block 4 or the portfolio approach. 

In this rule, the EPA is following the same approach that 

it uses in any rulemaking under CAA section 111(d), which is 

 

457 134 S. Ct. 2427 (2014). 

458 Utility Air Regulatory Group v. EPA, 134 S. Ct. 2427, 2444 

(2014) (citations omitted). 
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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 

is promulgating a uniform emission rate for steam-generating 

EGUs and a uniform emission rate for combustion turbines, and 

the EPA is translating those rates into a combined emission rate 

and equivalent mass limit for each state. These emission 

guidelines serve as the guideposts for state plan requirements. 

The states, in turn, promulgate emission standards and, in doing 

so, retain significant flexibility to either promulgate the 

emission rates in the guidelines, promulgate equivalent rates, 

or promulgate the equivalent mass limits. The sources, in turn, 

are required to comply with their emission limits, and may do so 

through any means they choose.

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 limitations. 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 
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of compliance options to achieve their emission limits. Those 

options include various means of implementing the building 

blocks as well as numerous other compliance options, ranging 

from -- depending in part on whether the state imposes a ratebased or mass-based emission limit -- implementation of demandside energy efficiency measures to co-firing. 

Moreover, in this rule, as with all CAA section 111(d) 

rules, the EPA is not directly regulating any entities. 

Moreover, the EPA is not finalizing the proposed portfolio 

approach. Accordingly, not only is the EPA not requiring that 

the states regulate non-affected EGUs, the EPA is not 

authorizing states to include in their CAA 111(d) plan 

regulations covering non-affected EGUs. 

It is certainly true that compliance with these air 

pollution controls will have costs, and those costs will affect 

the electricity sector by discouraging fossil fuel-fired 

electricity and encouraging alternative means of generating 

electricity. But for affected EGU, 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. This basic fact that 

the EPA regulations of air pollutants from affected EGUs 

invariably affect the utility sector is well-recognized. In 
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revising CAA section 111 in the 1977 CAA Amendments, Congress 

explicitly acknowledged that the EPA’s rules under CAA section 

111 for EGUs would significantly impact the energy sector.459 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 

 

459 The D.C. Circuit acknowledged this legislative history in 

Sierra Club v. EPA, 657 F.2d 298, 331 (D.C. Cir. 1981). There, 

the Court stated: 

The legislative history clearly supports our reading 

of amended section 111 as authorizing EPA to balance 

long term national and regional impacts of alternative 

standards. The Conferees defined the best technology 

in terms of “long-term growth,” “long-term cost 

savings,” effects on the “coal market,” including 

prices and utilization of coal reserves, and 

“incentives for improved technology.” [Citing CAA 

Conference Report: Statement of Intent; Clarification 

of Select Provisions, 123 Cong. Rec. 27071 (1977), 3 

L.H. at 324 (referring to H.R.Rep.No.95-294, 95th 

Cong., 1st Sess. 188 (1977), at 183-95, 4 L.H. at 

2651-62, Remarks of Senator Muskie introducing S. 252 

for debate, 123 Cong.Rec. 18018 (1977), 3 L.H. at 

717.] Indeed, the Reports from both Houses on the 

Senate and House bills illustrate very clearly that 

Congress itself was using a long-term lens with a 

broad focus on future costs, environmental and energy 

effects of different technological systems when it 

discussed section 111. [Citing S.Rep.No.95-127, 95th 

Cong., 1st Sess. (1977), 3 L.H. 1371; H.R.Rep.No.95-

294, 95th Cong., 1st Sess. 188 (1977), 4 L.H. 2465.] 
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sources in a manner that balances “our Nation’s energy needs and 

the possibility of economic disruption:” 

The appropriate amount of regulation in any particular 

greenhouse gas-producing sector cannot be prescribed 

in a vacuum: as with other questions of national or 

international policy, informed assessment of competing 

interests is required. Along with the environmental 

benefit potentially achievable, our Nation's energy 

needs and the possibility of economic disruption must 

weigh in the balance. 

The [CAA] entrusts such complex balancing to EPA 

in the first instance, in combination with state 

regulators. Each “standard of performance” EPA sets 

must “tak[e] into account the cost of achieving 

[emissions] reduction and any nonair quality health 

and environmental impact and energy requirements.” § 

7411(a)(1), (b)(1)(B), (d)(1); see also 40 C.F.R. § 

60.24(f) (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.460

 

460 American Electric Power v. Connecticut, 131 S. Ct. 2527, 

2539-40 (2011). 
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Similarly, the D.C. Circuit, in its 1981 decision upholding the 

EPA’s rules to reduce SO2 emissions from new coal-fired EGUs 

under the version of CAA section 111(b) adopted in the 1977 CAA 

Amendments, stated: 

[S]ection 111 most reasonably seems to require that 

EPA identify the emission levels that are “achievable” 

with “adequately demonstrated technology.” After EPA 

makes this determination, it must exercise its 

discretion to choose an achievable emission level 

which represents the best balance of economic, 

environmental, and energy considerations. It follows 

that to exercise this discretion EPA must examine the 

effects of technology on the grand scale in order to 

decide which level of control is best.... The standard 

is, after all, a national standard with long-term 

effects.461

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.”462 This rule has “economic, environmental, and 

energy” impacts, as Congress and the Courts expect in a CAA 

 

461 Sierra Club v. EPA, 657 F.2d 298, 330 (D.C. Cir. 1981). 

462 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 
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section 111 rule, but those impacts do not mean that the EPA is 

precluded from promulgating the rule. 

 As noted above, in this rule, to control CO2 emissions from 

affected EGUs, the EPA first considered more traditional air 

pollution control measures, including supply-side efficiency 

improvements, fuel-switching (for CO2 emissions, that entails cofiring with natural gas), and add-on controls (for CO2 emissions, 

that entails CCS). However, it became apparent that even if the 

 

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 meterological conditions 

are adverse) can, at lower cost, reduce local 

concentrations of sulfur oxides in the air, but cannot 

cope with the growing problem of sulfates and 

widespread acid rainfall. Use of low-sulfur Western 

coal would avoid many of these problems, but this coal 

is obtained by strip mining. Strip-mining reclamation 

is possible, but substantially hindered in large areas 

of the West by lack of rainfall. Moreover, in some 

coal-rich areas the coal beds form the underground 

aquifer and their removal could wreck adjacent farming 

or ranching economies. Large coal-burning plants might 

be located in remote areas far from highly populated 

urban centers in order to minimize the human effects 

of pollution. But such areas are among the few left 

that are unspoiled by pollution and both 

environmentalists and the residents (relatively few in 

number compared with those in metropolitan localities 

but large among the voting population in the 

particular states) strongly object to this policy. 

Id. at 406 n. 526. 
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EPA could have finalized those controls as the BSER463 and 

established the same uniform 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 stated that while they 

oppose including in the BSER generation shifts to lower- or 

zero-emitting sources (or, as proposed, demand-side energy 

efficiency), they request that those measures be available for 

compliance, which indicates their interest in implementing those 

measures.464

We expect that many sources will choose to comply with 

their emission limits through the measures in building blocks 2 

and 3 (as well as 4), but contrary to the assertions of some 

 

463 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. 

464 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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commenters, this will not result in unprecedented and 

fundamental alterations to the energy sector. As discussed 

above, Congress relied on the same measures as those the EPA is 

including in building blocks 2 and 3 as essential parts of the 

basis for the Title IV emission limits for fossil fuel-fired 

EGUs, and the EPA did the same for the emission limits in 

various rules for those same sources. In addition, as discussed 

elsewhere, reliance on the measures in building blocks 2 and 3 

is fully consistent with the recent changes and current trends 

in electricity generation, and as a result, would by no means 

entail fundamental redirection of the energy sector. 

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 that had the 

effect of applying the PSD requirements to large numbers of 

small sources that previously had not been subject to PSD and 

with respect to which, according to the Court, the EPA 

acknowledged that Congress did not intend be subject to the PSD 
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requirements.465 Commenters appear to interpret this decision to 

preclude the EPA from including at least building block 3 in the 

BSER because it includes measures that involve entities (such as 

renewable energy developers) that do not emit CO2 and have not 

previously been subject to the CAA. However, in this rule, the 

EPA is not attempting to subject any entity other than the 

affected EGUs in the source categories 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, 

requirements on entities other than affected EGUs. Thus, 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 jurisdiction and the parts of the economy that they 

represent will not be regulated by the EPA. 

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 

reduce the carbon intensity of generation at individual coal-

 

465 Util. Air Regulatory Group v. EPA, 134 S. Ct. 2427, 2443 

(2014). 
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fired steam EGUs by improving their heat rate. Heat rate 

improvements are changes implemented at an EGU that increase the 

efficiency with which the EGU converts fuel energy to electric 

energy, thereby reducing the amount of fuel needed to produce 

the same amount of electricity and consequently lowering the 

amount of CO2 produced as a byproduct of fuel combustion. Heat 

rate improvements yield important economic benefits to affected 

sources 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. In 2012, the generation-weighted 

average annual heat rate of domestic coal-fired EGUs was 

approximately 9,732 Btu per net kWh.466 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 carbon-intensity. 

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 

 

466 Similarly, in 2012, the generation-weighted average annual 

heat rates for coal-fired EGUs in each interconnection were 

9,700 Btu per net kWh (Eastern); 9,888 Btu per net kWh 

(Western); and 9,789 Btu per net kWh (Texas). 
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lieu of directly comparing an EGU’s performance against other 

EGUs with similar characteristics. Accordingly, as described 

below, our method effectively controls for the characteristics 

and factors of an EGU that typically remain constant over time 

(e.g., a unit is unlikely to dramatically increase or decrease 

in size). Our methodology for determining the amount of heat 

rate improvement appropriately included in the BSER as building 

block 1 is discussed in the next section, below. 

1. Summary of measures comprising the BSER in building block 1 

a. Measures under building block 1 - heat rate improvements. In 

finalizing the building block 1 portion of this rule, we 

considered over a thousand individual comments from the public, 

including individual EGUs and state agencies, on heat rate 

improvement, which are discussed below and also in the responses 

to comments document and the GHG Mitigation Measures TSD for the 

CPP Final Rule [Docket ID No. EPA-HQ-OAR-2013-0602]. Based on 

these public comments, we have refined the statistical analyses 

used in the proposal to identify the potential heat rate 

improvement that can be achieved on average by affected coalfired EGUs. 

In the proposal, we used two approaches to analyze the 

variability of an EGU’s gross heat rate using a robust dataset 

comprised of 11 years of hourly gross heat rate data for 884 
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coal-fired EGUs -- over 11 million hours of data collected 

between 2002 and 2012. The foundation of our first approach was 

an analysis of the variability of each EGU’s gross heat rate, 

which was accomplished in large part by grouping each EGU’s 

hourly data by similar ambient temperature and capacity factor 

(i.e., hourly operating level as a percentage of nameplate 

capacity) conditions. The second approach analyzed the 

difference between an EGU’s average gross heat rate and its best 

historical gross heat rate performance. We proposed that, on a 

nationwide basis, affected coal-fired EGUs should be able to 

achieve 6-percent heat rate improvement: 4-percent improvement 

from best practices, and an additional 2-percent improvement 

from equipment upgrades. We received many comments asserting 

that the 11-year dataset we had used to determine the 4-percent 

best practices figure likely reflected some portion of the 2-

percent equipment upgrades figure we had separately identified. 

Accordingly, these commenters claim that the EPA double-counted 

equipment upgrades in arriving at the full estimate of 6-percent 

heat rate improvement. Commenters also noted the difficulty, in 

some cases, of determining whether a heat rate improvement 

measure is an “equipment upgrade” or “best practice,” such as 

optimizing soot blowing with intelligent systems, using CO 

monitors for optimizing combustion, or applying air heater and 
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duct leakage controls. Based on commenters’ concerns over the 

potential for double-counting, the EPA has decided not to add a 

separate equipment upgrade component to its estimate of heat 

rate improvement potential. Nonetheless, we remain confident 

that additional equipment upgrades (including measures that are 

unambiguously equipment upgrades, such as turbine overhauls) are 

possible at many coal-fired EGUs, as supported by numerous 

commenters, the Sargent & Lundy study467 (S&L) and other industry 

reports and studies, many of which are referenced in the TSD 

developed for the proposed rule. 

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 

 

467 Sargent and Lundy 2009, Coal-Fired Power Plant Heat Rate 

Reductions, SL-009597, Final Report, January 2009, Docket ID No. 

EPA–HQ–OAR–2013–0602-XXXX, available at: 

http://www.epa.gov/airmarkets/resource/docs/coalfired.pdf. 
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improvement regionally, within the Eastern, Western and Texas 

Interconnections.468

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 TSD, our reliance on these gross heat rate data 

was reasonable given that (1) these data are the only 

comprehensive data available to the EPA, and (2) heat rate is 

proportional to CO2 emission rate. 

As in the proposal, we used more than one analytical method 

to evaluate the opportunity for EGUs to reduce their CO2

emissions through heat rate improvements. Our final methodology 

uses three different analytical approaches based on refinements 

of the two approaches described at the proposal stage. We call 

these final approaches: (1) the “efficiency and consistency 

improvements under similar conditions” approach; (2) the “best 

historical average performance” approach; and (3) the “best 

historical average performance under similar conditions” 

 

468 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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approach. As described below and in the TSD, each approach 

provides an independently reasonable way to estimate the 

potential for heat rate improvements by EGUs in each region. 

However, rather than select a potential heat rate improvement 

value supported by one or only some of these independently 

reasonable analytical approaches, we conservatively based our 

final determination for each region on the value for that region 

supported by all three approaches. 

The first approach, referred to here as 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 percent469). Thus, for example, one bin might contain 

all of an EGU’s hourly gross heat rate data generated during the 

 

469 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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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 

TSD, ambient temperature and hourly capacity factor are 

important conditions that influence heat rate at individual 

EGUs. By separating the EGU-specific data into bins based on 

these variables, and only directly comparing data within a bin, 

we were largely able to control for the influence of those 

variables on an EGU’s heat rate. Accordingly, having controlled 

for these two external factors, and having already controlled 

for unit-specific factors affecting heat rate by analyzing the 

data for each EGU in isolation, we are confident that the 

remaining variation in each bin’s data was primarily driven by 

factors under the EGU operator’s control. 

After allocating an individual EGU’s data across the bins, 

we next established a benchmark for each bin based on the best 

hourly gross heat rate accounting for outliers (i.e., we set the 

benchmark at the 10th percentile hourly gross heat rate value) 

during any two-year period.470 We compared the hourly gross heat 

 

470 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 

TSD for more details. 
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rate data within each bin to the EGU’s benchmark value. As in 

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. We refer to this percentage 

improvement value as the “consistency factor,” because applying 

it results in values for heat rate that are marginally more 

consistent with the EGU’s benchmark for that bin. Based on 

engineering judgement, in our proposal we selected a consistency 

factor of 30 percent after evaluating the heat rate improvement 

that would result from applying consistency factors of 10, 20, 

30, 40 and 50 percent of the distance between those lessefficient hourly gross heat rate values and the benchmark. 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 TSD.471 As in the proposal, we applied the 

 

471 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 TSD for more 

details. 
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consistency factor to each bin of each EGU’s hourly gross heat 

rate data, and averaged the result across all bins in that EGU’s 

matrix, giving us marginally improved gross heat rate for that 

EGU during the 11-year period from 2002 to 2012. We then 

compared the improved gross heat rate for each EGU to its actual 

2012 historic 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 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.472 

 

472 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 TSD for the 

results of this approach using benchmarks and consistency 

factors based on one-year averages. 
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In addition to the statistical approach described above, we 

employed a “best annual performance” approach refined from the 

proposal, which compared each EGU’s best two-year rolling 

average gross heat rate to that EGU’s 2012 average annual gross 

heat rate.473 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.474 

Our third and final approach, the “best annual performance 

under similar conditions” approach, combines aspects of the 

 

473 As described below, we also conducted this regionalized 

approach using each EGU’s best one-year rolling average. See the 

TSD for more details. 

474 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 TSD for 

more details. 
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first two approaches. First, as with the “efficiency and 

consistency improvements under similar conditions approach,” we 

grouped hourly data for each EGU by ambient temperature 

conditions and hourly capacity factor. Next, we calculated each 

EGU’s best two-year gross heat for each of the 168 ambient 

temperature-capacity factor bin.475 Similar to the “best 

historical average performance” approach, to calculate the 

potential heat rate improvement, the EPA then compared each 

EGU’s 2012 gross heat rate for each of the ambient temperaturecapacity 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.476

 

475 As described below, we also conducted this approach using 

one-year averages for each EGU instead of two-year averages. See 

the TSD for more details. 

476 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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As in the proposal, we additionally analyzed the data with 

our analytical approaches using one-year averaging periods in 

place of the two-year averaging periods described above.477

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 the Table 

6, the values produced by that approach were the minimum values 

produced by any of the three approaches: 

 

477 The TSD describes in more detail our rationale for using oneand two-year averaging periods in our analytical approaches and 

methodology as a whole. 
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Table 6. Heat Rate Improvement Potential by Region and Averaging 

Period. 

Analytical approach 

Heat rate improvement potential 

(percent) 

by region and averaging period 

Western Texas Eastern 

1

year 

2

year 

1

year 

2

year 

1 

year 

2

year

Efficiency and 

consistency improvements 

under similar conditions 

3.5% 2.1%* 3.7% 2.3%* 5.6% 4.3%*

Best annual performance 4.1% 2.6% 4.2% 3.1% 6.3% 4.9%

Best annual performance 

under similar conditions 4.7% 3.1% 4.9% 3.5% 6.9% 5.3%

Accordingly, we have concluded that the an appropriately 

conservative estimate 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 
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improvement. Furthermore, these approaches are conservative on 

even an individual basis because they do not account for the 

full extent of heat rate improvements available through 

equipment upgrades. While some EGUs may not have achieved 

significant heat rate improvement in the past and EGU owners may 

feel they face challenges in the future, our methodology as a 

whole indicates that coal-fired EGUs on average can at minimum 

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 for the CPP Final Rule. 

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;478 only that these heat 

 

478 Examples of the many types of best practices and equipment 

upgrades available to coal-fired EGUs include air heater 

baskets; air heater seals; automate steam system drains; heat 

rate optimization software; coal drying systems; 

combustion/optimization monitoring system; condenser cleaning 

system; condenser retubing; fan and pump variable frequency 

drives; steam seal and path upgrades; turbine internals 

replacement; turbine steam seal upgrades; intelligent 

sootblowing system software; the adoption and training of O&M 

staff on heat rate improvement procedures; alignment of the 

cycle by isolating as much as possible of the high-energy fluid 

leakage from the steam cycle; boiler chemical cleaning; cleaning 
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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 equipment upgrades. 

The performance rates quantified in section VI, below, 

reflect the region-specific values for heat rate improvement. 

Although the performance rates are based on the least stringent 

overall performance rate determined to be reasonable for any 

region, and are thus based in part on the percentage heat rate 

improvement identified for the region, this rule does not itself 

require any specific EGU to implement measures resulting in a 

 

air preheater coils; production cost optimization programs that 

benchmark plant thermal performance using historical plant data 

along with an on-site performance appraisal to identify 

potential areas for improved performance; remote monitoring 

centers with thermal performance software for monitoring heat 

rate; repairing boiler air in-leakage; high pressure feedwater 

pump overhaul; repairing flue gas desulfurization systems; 

repairing steam and water leaks; replacing feed pump turbine 

steam seals; and sliding pressure operation to reduce turbine 

throttling losses. 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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specific percentage heat rate improvement. Rather, the 

percentage heat rate improvement value is merely reflected in 

the performance rates and equivalent CO2 emission goals provided 

to the states. Each state has the flexibility to develop a plan 

that achieves those CO2 performance rates or emission goals by 

assigning the emission standards the state considers appropriate 

to its affected coal-fired EGUs. Similarly, depending on the 

content of the applicable plan, sources 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.479

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 TSD. 

In the final rule, the EPA extends the implementation 

deadline from 2020 to 2022. This additional time will be helpful 

to the states seeking to conduct more targeted analyses of the 

nature and extent of heat rate improvements that specific coalfired EGUs can make, considering specific recent improvements or 

upgrades, planned retirements of older coal-fired EGUs, and 

other relevant considerations. The extended deadline will also 

provide additional time to accommodate changes to heat rate 

monitoring methods at EGUs and for the installation of new 

 

479 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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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 the majority 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 $5.81 to $11.63 

per metric ton of CO2 removed, as previously estimated in the 

proposal and described in detail in the TSD.480 Depending on the 

balance between equipment upgrades and best practices, improving 

heat rate would even result in a net savings for some EGUs. 

Based on the analyses of technical potential and cost 

summarized above and in the proposal TSD, we find that heat rate 

improvements of 4.3, 2.1 and 2.3 percent are reasonable and 

conservative estimates of what coal-fired EGUs in the Eastern, 

Western and Texas Interconnections, respectively, can achieve at 

a reasonable cost. 

3. Response to key comments 

 

480 These cost figures from the proposal are now particularly 

conservative because they include 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, as discussed above, our assessment of 

heat rate improvement potential uses a unit-specific data 

methodology that compares each EGU’s performance against its own 

historical performance. By substantially basing our analysis on 

these unit-specific assessments, we inherently factor in the 

effect of numerous design conditions. We also conducted a 

regression analysis that evaluated the effect of numerous 

factors on heat rate, and found that subcategorizing would 

generally make little difference in our analysis. Additionally, 

subdividing the EGUs into subcategories would reduce the 

quantity of EGUs used to calculate each average, which would 

increase the influence of random and atypical variations in the 
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data on the overall averages, and would thus decrease our 

confidence in the accuracy of the results. Furthermore, states 

in determining the emission limitation for individual EGUs are 

free to apportion reductions in a way that reflects any 

subcategories of their choice. For a more detailed explanation 

of our decision not to subcategorize for purposes of determining 

building block 1, see the TSD. 

Many commenters told the EPA that EGUs already have 

undertaken significant efforts to operate efficiently to provide 

reliable electric service at the lowest reasonable cost; that 

they believe they cannot significantly improve heat rate; that 

best practice maintenance activities are performed on a daily 

basis, including during maintenance outages that allow for the 

inspection, cleaning and repair of all equipment; that extensive 

capital investments have been made to install state-of-the art 

equipment and replace equipment that is beyond repair; and that 

their employees continuously monitor and control operating 

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 
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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 sources based in part on the availability 

of heat rate improvements, the states are free to assess heat 

rate improvements on a more targeted, case-by-case basis that 

takes into account an EGU’s previous heat rate 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 
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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. Furthermore, 

to the extent that an affected EGU was in 2012 fully 

implementing every possible best practice for improving heat 

rate, it may still be capable of improving heat rate through 

equipment upgrades. 

Other commenters said that a 6-percent heat rate 

improvement overall is too high; that the heat rate improvement 

from upgrades are double-counted within the data used to 

determine heat rate improvements from best practices; and that 

the 2-percent heat rate improvement specifically for upgrades 

was inappropriately based on “conceptual” improvements from only 

one study. 

We have reduced the 6-percent heat rate improvement from 

the proposed rule to three regionalized figures of 4.3 percent 

(Eastern), 2.1 percent (Western) and 2.3 percent (Texas), as 

discussed above and described in detail in the revised TSD. 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 TSD. These 

overall heat rate improvement figures do not include an 
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estimated percent heat rate improvement attributable 

specifically to upgrades. Although we are no longer including in 

our calculation of building block 1 a separate 2-percent heat 

rate improvement attributable solely to equipment upgrades, this 

decision is not because we believe that our initial 2-percent 

assessment of equipment upgrades was incorrect. To the contrary, 

the information presented in the S&L study was similar to that 

in other industry reports and studies -- many of which were 

referenced in the proposal TSD -- describing potential heat rate 

improvements at EGUs from all types of equipment upgrades. 

However, we recognized that the 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 best practices and a portion 

of the 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, 
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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 

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 cooling water intake points. Our 
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analysis found that surface water temperature did explain some 

of the variation in heat rate, but that surface water 

temperature is strongly correlated with ambient air temperature 

-- a variable we did control for in our methodology. Because of 

the strong correlation between ambient air temperature and 

surface water temperature, the lack of hourly cooling water 

temperature data, the availability of a comprehensive dataset of 

nationwide hourly ambient air temperature, and the similar 

explanatory power of surface water temperature and ambient air 

temperature, it is unlikely that separately addressing cooling 

water temperature would significantly change the results. 

Rather, we are confident that our use of hourly ambient air 

temperature in our analyses adequately addressed any significant 

impact of cooling water temperature. See the TSD for further 

details about this analysis. As described further in the 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 
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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. 

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 percent heat rate improvement for its region as a guide 

while keeping in mind the uniform performance rate. The final 
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rule establishes a uniform national performance rate based on 

the least stringent regional performance rate calculated with 

the building blocks. Accordingly, affected sources in regions 

not setting the national level have emission reduction 

opportunities beyond those reflected in the applicable 

performance rate. For affected coal-fired EGUs in the contiguous 

United States, a methodology that assesses potential heat rate 

improvement within each interconnection reflects the regional 

nature of the interconnected electricity system and the regionwide scope of opportunities available for those EGUs to access 

emission reduction measures through emissions trading.481 For 

these and other reasons described in Section V.A of the preamble 

with respect to the BSER as a whole, we have reasonably based 

building block 1 on a regionalized approach. Applying this 

regionalized approach to building block 1 strikes an appropriate 

balance between the proposed nationwide analysis and commenters’ 

suggested state-specific analysis, which does not fully reflect 

the interconnected nature of the system within which affected 

coal-fired EGUs operate. 

 

481 As described in section [xxx], affected EGUs in states and 

territories that are isolated from the three major 

interconnections lack access to the same opportunities to access 

the building blocks across wide regions and, accordingly, have 

performance rates based on data specific to that state or 

territory. 
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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 the 

development of a comprehensive heat rate improvement study for 

each of the nearly 900 coal-fired EGUs covered by this rule on a 

unit-by-unit basis is likely to cost on the order of $50,000 to 

$100,000 each (almost $50 to $100 million total) and require 

three to four years to complete in total. Commenters have 

pointed out, and we agree, that a heat rate improvementestimating effort of that magnitude and duration is 

unnecessarily lengthy and expensive, and we believe would not 

serve the broader goal-setting purpose of this rulemaking. 

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. 
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Furthermore, site-specific information forms the foundation of 

the EPA’s estimated heat rate improvement potential, and similar 

data likely would be used in any site-specific heat rate 

improvement engineering study. Finally, EGU-specific detailed 

design and operation information is not consistently available 

for all the factors that influence heat rate. The EPA has used 

the comprehensive data that are available to reasonably and 

conservatively estimate potential heat rate improvement in each 

region. 

Commenters also said that shifting electricity generation 

from coal-fired EGUs to other EGUs because of measures 

implemented under other building blocks will lower the capacity 

factors of coal-fired EGUs, and thus increase, not decrease, 

their heat rates. 

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 TSD -- incorporates expected retirements of 
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inefficient units and generation shifts away from using coalfired EGUs as peaking units. 

Commenters also noted that the EPA used net heat rate in 

state goals, but used gross heat rate in its heat rate 

improvement analysis -- potentially ignoring the detrimental 

effect that parasitic load from air pollution control devices 

(APCD) and other equipment can have on net heat rate. 

The EPA’s variability analysis necessarily and reasonably 

used gross output data for each of the 884 EGUs in the EPA’s 

database because they are the only publicly available, unitspecific, hourly performance data. By definition, improvement in 

gross heat rate would be reflected in the net heat rate. Gross 

heat rate is the total heat output from the EGU, in units of 

Btu/gross kWh, and includes the power used by auxiliary 

equipment required to operate the EGU itself. By contrast, net 

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 
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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.482

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 

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 

 

482 See above for an explanation of gross versus net heat rate. 
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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 2025.483 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 

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 TSD. 

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. 

 

483 When considered on a regional basis, we expect these controls 

to impact heat rate by approximately 0.3 Btu/kWh in both the 

Eastern and Western Interconnections, and by less than 0.1 

percent in the Texas Interconnection. 
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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 

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 
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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 TSD, our review of the data shows that a 

relatively small amount of the data are affected by these 

changes; we remain confident that the values adopted for 

building block 1 are conservative and reasonable estimates of 

the potential for heat rate improvement in each region. In many 

instances, changes in monitoring methodology would have the 

result of actually underestimating the potential for heat rate 

improvement at some EGUs. Furthermore, because our methodology 

analyzes percentage heat rate improvement, our results are 

unaffected by EGUs that consistently used less accurate 

monitoring methodologies that tend to overestimate heat rate. 

For these and other reasons discussed in detail in the TSD, we 

remain confident in our results despite the marginal differences 
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attributable to monitoring methodologies in some of the heat 

rate data for a subset of EGUs.484 

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. Consult the TSD for a more detailed 

explanation. 

Commenters said that there is no proof that lowering the 

heat rate will reduce variability or that reduced variability 

will reduce heat rate, i.e., correlation does not prove 

causation. 

As an initial matter, it is important to note that for the 

final rule the EPA used three types of statistical analyses to 

evaluate and estimate potential heat rate improvements of coal-

 

484 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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fired EGUs, and only one of these analyses involved any 

consideration of heat rate variability. All three types of 

statistical analyses are described in the TSD. 

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. 

The consequence of a reduced heat rate is, of course, a 

lower rate of CO2 emissions, which is the purpose of the BSER for 

building block 1. This way of thinking about reduced variability 

is consistent with industry’s own efforts to reduce variability, 
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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 

1. Demonstration of Ability to Reduce CO2 Emissions through 

Shifting Generation 

The ability to switch generation from higher- to loweremitting generation reflects the way EGUs are generally 

dispatched.485 The standard approach to dispatching generation is 

through Security Constrained Economic Dispatch (SCED), a wellestablished practice in the electric power industry.486 As the 

name indicates, SCED has two defining components: economic 

operation of generating facilities and ensuring that the 

electric system remains reliable and secure.487 Economic dispatch 

 

485 See Preamble, II.C.1, History of the Power sector for 

background to this discussion. 

486 “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. 

487 “Security Constrained Economic Dispatch: Definitions, 

Practices, Issues and Recommendations: A Report to Congress”, 

Federal Energy Regulatory Commission, July 31, 2006. 
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generally refers to shorter-term planning and operations from a 

day ahead through real time. During this period, generating 

units are committed – a process known as “unit commitment” where 

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 on the system. Overall 

changes in the level of generation from different facilities are 

also planned over time periods longer than this two-day dispatch 

period. Over a calendar year, for example, units are planned and 

scheduled seasonally or monthly to ensure that sufficient 

capacity and energy will be available to meet expected loads in 

an area. Over a period of a week, units are committed to be 

prepared to start up or shut down to meet forecast loads, and 

dispatch is coordinated within this planning and unit commitment 

framework. This process enables system operators to respond 

quickly to short-term changes in demand, and also to shift 

generation among different generation types to match longer-term 

requirements and goals. 

 EGUs using technologies with relatively low variable 

costs, such as nuclear units, are for economic reasons generally 

operated at their maximum output whenever they are available. 

Renewable EGUs such as wind and solar units also have low 

variable costs, but in any event are generally operated when 
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wind and sun conditions permit rather than at operators' 

discretion. In contrast, fossil fuel-fired EGUs have higher 

variable costs and are also relatively flexible. Fossil fuelfired 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 coalfired EGUs (as well as oil- and gas-fired steam EGUs) and NGCC 

units. In the short term — that is, over time intervals shorter 

than the time required to build a new electric generation unit — 

fossil fuel-fired units consequently tend to compete more with 

one another than with nuclear and renewable EGUs. The amount of 

generation shifting from coal-fired EGUs to NGCC units that 

takes place as a result of this competition is highly relevant 

to overall power sector GHG emissions, because a typical NGCC 

unit produces less than half as much CO2 per MWh of electricity 

generated as a typical coal-fired EGU. Over the past decade or 

more, since at least 2000, fossil fuel-fired generation has been 

shifting from coal- and oil-fired EGUs to natural gas NGCC 

units, both as a result of construction of new NGCC units, and 
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also as a result of dispatch of existing 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.488 As we demonstrate elsewhere 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 NGCCs in recent years and is expected to continue this shift 

in the future. In the reference case without 111d, EIA forecasts 

40 GW of coal retirements and 53 GW of NGCC additions from 2012 

to 2030.489 An EPA review of state Integrated Resource Plans 

(IRPs) shows a pattern of shifting away from coal steam 

generation to NGCC. 

A review of the electric utility industry structure also 

shows that that utilities are able to shift generation among 

 

488 Ventyx Electric Power Database. 

489 Energy Information Administration, Annual Energy Outlook 2015 

reference case, ref2015.d021915a. 
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existing affected sources to meet the requirements of this 

building block. In the first instance, many of the NGCC units 

are owned by the same companies or affiliates as steam units. 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 EGU owner is 

also the dispatch entity, as in most traditional market 

structures, the EGU owner will generally have operational 

control over the unit. In organized markets such as RTOs, the 

owner can exercise a similar control over the levels of 

generation across units by how it offers generation from its 

units to the market operator. In both types of market 

structures, environmental conditions, such as compliance costs 

or limits on generation, can be factored in with fuel costs to 

influence the timing of when the unit is offered in the 

dispatch, as well as the price and generation level at which the 

unit is dispatched. An analysis of generation data from steam 

and NGCC units in 2012 shows that only 23 percent of the steam 

generation occurred where the entity (a company or affiliate) 

had no NGCC generation. Among entities with both steam and NGCC 

generation, an increase in NGCC generation from 2012 capacity 
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factors to a capacity factor of 75 percent on a net basis would 

represent 33 percent of the 2012 steam generation.490 

In regions with organized electricity markets (including, 

but not limited to, RTOs or ISOs), 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 coal-fired unit can reduce generation that is 

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. An owner of a source can also reduce the generation 

of an EGU by substituting generation from a lower-emitting NGCC 

directly. This substitution can take the form of a Power 

Purchase Agreement from a replacement source, an alternative 

available both in regions with organized wholesale electricity 

markets or in regions without such markets. Unused capacity from 

existing NGCCs can be a source of supply for reducing the level 

of higher-emitting EGUs. It is also possible that the owner of a 

steam unit could directly invest in an existing EGU, by 

purchasing the asset or taking a partial ownership position, 

thus acquiring the generation from the unit through that means. 

The acquired generation and its associated emissions could be 

 

490 Egrid database. 
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used for compliance by the higher-emitting EGU. Under a ratebased standard, the emissions and generation associated with a 

purchase or acquisition could be averaged with the higheremitting EGU emissions and generation to reduce the combined 

emissions rate through the use of emission rate credits. The 

amount of generation that could be shifted using the approaches 

described in this paragraph will depend on the type and terms of 

the commercial arrangements, but the wide range of approaches 

permitted by this rule – reflecting both the characteristics of 

the interconnected operations of EGUs and those of CO2 itself as 

a global-impact pollutant –provides the needed flexibility, both 

within a year and across multiple years, to permit EGUs to 

fashion these arrangements to fit their circumstances. 

Under a mass-based program, the steam generators simply 

need to reduce their generation (or buy allowances, or co-fire 

or repower, or install CCS). They do not need to purchase 

replacement, lower-emitting electricity or the environmental 

attributes of that electricity. They may need to do so to 

fulfill any electricity supply obligations they might be under, 

but they do not have to do so to meet the requirements of this 

rule. Once the steam generators reduce their generation, the 

other entities in the electricity system arrange for the 

replacement electricity. But that replacement electricity does 
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not lower the emissions from the steam generation. The reduced 

generation by the steam generators lowers the emissions. An EGU 

should also be able to meet its reduction obligations by 

purchasing tradable emission rate credits or mass allowances. 

Purchased emission rate credits would be averaged into the 

existing generation and emissions from the EGU to calculate a 

reduced emissions rate in a rate-based program. Purchased mass 

allowances would be added to any allowances already held to 

enable the EGU to hold a sufficient number of allowances to 

cover emissions in a mass-based program. In each case the 

calculation would need to reflect the type of program and the 

type of credit or allowance being applied (see section VIII for 

more detail on how these programs operate). 

The approaches shown here collectively demonstrate that all 

steam generators, regardless of size of form of ownership, can 

implement building block 2 through some or all of the mechanisms 

described. 

2. Magnitude of Generation Shift 

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. This examination showed that, although most NGCC units 
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have historically been operated in intermediate-duty roles for 

economic reasons, they are technically capable of operating in 

base-load roles at much higher annual utilization rates. Average 

annual availability (that is, the percentage of annual hours 

when an EGU is not in a forced or maintenance outage) for NGCC 

units in the U.S. generally exceeds 85 percent, and can exceed 

90 percent for some groups.491

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.492 These changes in generation 

patterns have been driven largely by changes over time in the 

 

491 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. 

492 http://www.eia.gov/todayinenergy/detail.cfm?id=6990. 
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relative prices of natural gas and coal. Although the relative 

fuel prices vary by location, as do the recent generation 

patterns, this trend holds across broad regions of the U.S. In 

the aggregate, the historical data provide ample evidence 

indicating that, on average, existing NGCC units can achieve and 

sustain utilization rates higher than their historical average 

utilization rates. 

The experience of relatively heavily-used NGCC units 

provides an additional indication of the degree of increase in 

average NGCC unit utilization that is technically feasible. In 

response to comments regarding the use of nameplate capacity in 

determining NGCC utilization rate, 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.493,494 In effect, these plants were 

being dispatched to provide base-load power. In addition to the 

 

493 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). 

494 An annual utilization rate of 75 percent on a net summer 

basis is similar to the proposed rule’s finding of 70 percent 

utilization on a nameplate basis. 
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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 idled or operated 

at much lower capacity factors. Nonetheless, the data clearly 

demonstrate that a substantial number of existing NGCC plants 

have proven the ability to sustain 75 percent utilization rates 

for extended periods of time. We view this as strong evidence 

that increasing the annual average utilization rates of existing 

NGCC units to 75 percent on a net summer basis would be 

technically feasible. 

The EPA believes that an annual average utilization rate of 

75 percent on a net summer basis is a conservative assessment of 

what existing NGCC plants are capable of sustaining for extended 

periods of time. This level is based on the 85th percentile 

plant in 2012. In 2012, the 90th percentile plant operated at 
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approximately 80%, a level which EPA believes is also 

technically feasible on average for the existing NGCC fleet. 

For purposes of establishing state goals, historical (2012) 

electric generation data are used to apply each building block 

and develop each state's goal (expressed as an adjusted CO2

emission rate in lbs per MWh). In 2012, total electric 

generation from existing NGCC units was X TWh. After the 

application of the building block 2 NGCC up to 75 percent target 

utilization rate in each region on a net summer basis, and 

including generation from NGCC units that were under 

construction in 2012, the total generation from these existing 

sources is assumed to be X TWh. 

Although producing X TWh of generation from existing NGCC 

units is not actually required, because states may choose other 

abatement measures to reach the state goals, the EPA 

nevertheless believes that producing this quantity of generation 

from this set of NGCC units is feasible. As a reference point, 

NGCC generation increased by approximately 430 TWh (an 80 

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 X percent higher 

than 2014 levels. This reflects a smaller ramp-up rate in NGCC 

generation than has been observed from 2005 to 2012. We also 
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expect an increase in NGCC generation of this amount would not 

impair power system reliability. Increases in NGCC usage at 

existing EGUs that displaces generation from steam sources will 

not impact reliability, since the available fossil generation 

will not change, leaving the system with adequate dispatchable 

resources to continue to meet reserve margin and maintain 

reliability. In addition, the final rule makes specific 

provision to ensure that reliability can be planned and 

maintained under this final rule.495

The EPA also examined the technical capability of the 

natural gas supply and delivery system to provide increased 

quantities of natural gas and the capability of the electricity 

transmission system to accommodate shifting generation patterns. 

For several reasons, we conclude that these systems would be 

capable of supporting the degree of increased NGCC utilization 

needed for states to achieve the goals established by this rule. 

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 

 

495 See also Reliability discussion in the state plans section. 
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percentage points above their average utilization rates (which 

have recently been in the range of 40 to 50 percent).496 Fleetwide combined-cycle average monthly utilization rates have 

reached 65 percent,497 showing that the pipeline system can 

currently support these rates for an extended period. If the 

current pipeline and transmission systems allow these 

utilization rates to be achieved in peak hours and for extended 

periods, it is reasonable to expect that similar utilization 

rates should also be possible in other hours when constraints 

are typically less severe, and be reliably sustained for other 

months of the year. Furthermore, this final rule will not have a 

significant impact on peak demand for natural gas, including 

winter demand when natural gas for electricity will compete with 

other sector demands, since the state goals are annual 

requirements and increases in demand for natural gas will be 

during non-peak periods when NGCC capacity factors are currently 

low. 

 

496 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). 

497 EIA, Electric Power Monthly, February, 2014. Table 6.7.A. 
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The second consideration supporting our view that natural 

gas and electricity system infrastructure would be capable of 

supporting increased NGCC unit utilization rates is the 

flexibility of the emission guidelines. The state goals do not 

require any particular NGCC unit to achieve any particular 

utilization rate in any specific hour or year. Thus, even if 

isolated natural gas or electricity system constraints were to 

limit NGCC unit utilization rates in certain locations in 

certain hours, this would not prevent an increase in NGCC 

generation overall across a state or broader region and across 

all hours. The third consideration supporting a conclusion 

regarding the adequacy of the infrastructure is that pipeline 

and transmission planners have repeatedly demonstrated the 

ability to methodically relieve bottlenecks and expand 

capacity.498 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 

 

498 See, e.g., EIA, Natural Gas Pipeline Additions in 2011, Today 

in Energy; INGAA Foundation, Pipeline and Storage Infrastructure 

Requirements for a 30 Tcf Market (2004 update); INGAA 

Foundation, North American Midstream Infrastructure Through 

2035—A Secure Energy Future Report (2011). 
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to meet the potential demands from increased use of existing 

NGCC units. Over a longer time period, much more significant 

pipeline expansion is possible. In previous studies, when the 

pipeline system was expected to face very large demands for 

natural gas use by electric utilities about 10 years ago, 

increases of up to 30 percent in total deliverability out of the 

pipeline system were judged to be possible by the pipeline 

industry.499 There have been notable pipeline capacity expansions 

over the past five years, and substantial additional pipeline 

expansions are currently under construction.500 Similarly, the 

electric transmission system is undergoing substantial 

expansion.501 Further, as discussed below in Sections X and X of 

this preamble (on state flexibilities and state plans, 

 

499 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. 

500 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. 

501 According to the Edison Electric Institute, member companies 

are planning over 170 projects through 2024, with costs totaling 

approximately $60.6 billion (this is only a portion of the total 

transmission investment anticipated). Approximately 75 percent 

of the reported projects (over 13,000 line miles) are high 

voltage (345 kV and higher). 

http://www.eei.org/issuesandpolicy/transmission/Documents/Trans_

Project_lowres_bookmarked.pdf. 
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respectively), we believe the flexible nature of the goals 

provides time for infrastructure improvements to occur should 

they prove necessary in some locations. Finally, as discussed 

below in section X, the EPA is finalizing a start date two years 

later than at proposal, or almost seven years from the date of 

this final rule, and then phasing in building block 2 through 

the interim period. Combining these factors of currently 

observed average monthly NGCC utilization rates of up to 65 

percent, the flexibility of the emission guidelines, the rates 

of historical growth, and the availability of time to address 

any existing infrastructure limitations, it is reasonable to 

conclude that the natural gas pipeline system can reliably 

deliver sufficient natural gas supplies, and the electric 

transmission system can reliably accommodate changed generation 

patterns, to allow NGCC utilization to increase up to an average 

annual utilization rate of 75 percent on a net summer basis. 

We recognize that an increase in NGCC utilization rates at 

existing units corresponds with an associated increase in 

natural gas production, consistent with the current trends in 

the natural gas industry. The EPA expects the growth in NGCC 

generation assumed in goal-setting to be feasible and consistent 

with domestic natural gas supplies. Increases in the natural gas 

resource base have led to fundamental changes in the outlook for 
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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 production 

has increased by 32 percent over that same timeframe (from 19.2 

TCF in 2000 to 25.3 TCF in 2012). EIA's Annual Energy Outlook 

for 2015 projects that production will further increase to 33 

TCF by 2030, as a result of increased supplies and favorable 

market conditions. For comparison, NGCC generation growth of X 

TWh (calculated in goal setting) would result in increased gas 

consumption of roughly X TCF for the electricity sector, which 

is less than EIA’s projected increase in natural gas production. 

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 
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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. 

Such a result is consistent with the EPA's determination that 

increasing the average utilization rate of existing NGCC units 

to 75 percent would be technically feasible. 

3. Timing of Generation Shift 

Some stakeholders have expressed concern that the 

performance rate- and goal-setting methodology — in particular, 

calculating the interim performance rates and goals on the basis 

of achieving the shift in generation assumed under building 

block 2 by the first year of the interim period — requires 
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states to achieve such a significant portion of the required CO2

emission reductions early in the interim period that it defeats 

the intended purpose of providing states flexibility in how they 

may achieve the required emission reductions. In particular, 

these stakeholders have stated that significant shifts of 

generation away from coal-fired generators to existing NGCC 

units (as calculated under building block 2) will be difficult 

for some states to achieve by the first year of the interim 

period as a result of technical, engineering, and infrastructure 

limitations or other considerations, may limit cost-effective 

options for emission reductions, and might have negative 

implications for reliability and/or recent investments in fossil 

steam technology. According to these stakeholders, these 

concerns existed even though the proposed rule did not require 

all emission reductions to be achieved in 2020, but rather 

provided that the interim goal could be met on an average basis 

for the 2020-2029 period. 

In the proposal, the EPA determined that emission 

reductions are feasible and achievable at fossil fuel-fired 

steam EGUs by shifting from more carbon-intensive EGUs to less 

carbon-intensive EGUs, as part of the BSER. More specifically, 

the EPA proposed that, generation shifts from fossil fuel-fired 

steam units (which are primarily coal-fired) to NGCC units, up 
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to a utilization of 70 percent on a nameplate capacity basis, 

could be achieved by 2020, as part of building block 2 and for 

purposes of establishing state goals. In contrast, the EPA 

proposed that reductions in CO2 emissions from fossil fuel-fired 

units associated with other measures, such as increased 

utilization of RE generating capacity and increased demand-side 

energy efficiency, would be achievable on a phased-in basis 

between 2020 and 2029, reflecting the necessary time needed for 

deployment (79 FR 34866). 

We note that the design of the guidelines makes clear that 

states are not required to reach their targets using precisely 

the levels of each building block that the EPA used to determine 

each state's goal. Nevertheless, some stakeholders have 

expressed concern that it may not be feasible to ensure 

significantly higher levels of utilization for existing NGCC 

units that might be required in order to meet the interim state 

goals because of the time required to improve natural gas 

pipeline infrastructure in some states. Stakeholders have also 

stated that, while some coal-fired units have recently been 

constructed and many have received significant capital 

investment (e.g., in the form of pollution control retrofits), 

some states' interim goals could not be achieved unless these 

units stop operating by 2020. According to stakeholders, this 
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concern particularly applies for states that have both 

significant amounts of steam generation and significant amounts 

of existing NGCC capacity that is not currently being operated 

at high levels of utilization. In light of these concerns, the 

EPA solicited comment in the proposal on potential rationales 

for phasing in the potential to shift generation under building 

block 2 in the subsequent NODA (79 FR 64543). 

As described in section X of this preamble, the EPA has 

revised the interim compliance period to start in 2022, which in 

and of itself provides a meaningful response regarding the 

concerns expressed by commenters about the timing of building 

block 2’s generation shift potential. More specifically in 

response to the comments about building block 2 received from 

stakeholders, the EPA has evaluated the timing of implementation 

of building block 2 within the framework of BSER, and is 

finalizing a change to building block 2 that phases in the shift 

from existing fossil steam to existing NGCC over the interim 

period. This phase-in allows for additional time to complete 

potential infrastructure improvements (e.g., natural gas 

pipeline expansion or transmission improvements) that might be 

needed to support more use of existing natural gas-fired 

generation, and provides states with increased ability 

coordinate actions taken under building block 2 with actions 
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taken under building block 3 (operation of new renewable 

capacity). Additionally, this phase-in increases the flexibility 

provided to states to address capital investment concerns 

regarding individual sources when scheduling compliance actions 

over the course of the interim and final periods. 

The phase-in schedule is based on two parameters. The first 

parameter defines an amount of generation shift to existing NGCC 

capacity that is feasible by 2022, and the second parameter 

defines how quickly that amount could grow until the full amount 

of NGCC generation could be achieved as part of the BSER. Both 

of these parameters are determined by examining the extent to 

which gas-fired generation increased over historical time 

periods. The first parameter is based on the single largest 

annual increase in power sector gas-fired generation since 1990, 

which occurred between 2011 and 2012 and is equal to 22 

percent502. We believe this is a conservative estimate of the 

ability of the sector to increase utilization of NGCC capacity 

between now and 2022, given that this increase already occurred 

in a single year. The second parameter is based on the average 

 

502 US EIA Monthly Energy Review, Table 7.2b Electricity Net 

Generation: Electric Power Sector (2015). Available at: 

http://www.eia.gov/totalenergy/data/browser/xls.cfm?tbl=T07.02B&

freq=m. 
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annual growth in gas-fired generation in the power sector 

between 1990 and 2012, or approximately 5 percent per year. 

In the performance rate calculation methodology, these two 

parameters constrain the annual rate at which building block 2 

shifts generation from fossil steam units to NGCC units. As 

discussed in Section X, the interim performance rate is an 

average of annual rates calculated over the 2022-2029 period. 

The two parameters above limit the extent to which NGCC 

generation is able to increase and replace fossil steam 

generation in each year of the interim period. In the first 

year, NGCC generation is limited to a maximum of a 22 percent 

increase from 2012 levels in each region. In each subsequent 

year, regional NGCC generation is limited to a maximum of a 5 

percent increase from the previous year. This phase-in continues 

in the performance rate-setting methodology until the BSER level 

of shifting from fossil steam generation to NGCC generation is 

completed. Under this approach, building block 2 is completely 

phased into the performance rates of all regions by the end of 

the interim period. 

This phase-in, in addition to the flexible nature of the 

goals (discussed below in Sections X and X of this preamble), 

ensures that the overall framework of this final rule includes 

sufficient flexibility, particularly with respect to timing of 
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and strategies for reducing emissions from the affected units, 

so that states can develop cost-effective strategies, and 

states, utilities, grid operators and others can readily respond 

to unexpected changes or demands on the energy system, such as 

severe weather, and allow for infrastructure improvements to 

occur should they prove necessary in some locations. 

4. Cost 

Having established the technical feasibility and 

quantification of the potential to replace incremental 

generation at higher-emitting EGUs with generation at NGCC 

facilities as a CO2 emissions reduction strategy, we next turn to 

the question of cost. The cost of the power sector CO2 emission 

reductions that can be achieved through shifting generation 

among existing fossil fuel-fired EGUs depends on the relative 

variable costs of electricity production at EGUs with different 

degrees of carbon intensity. These variable costs are driven by 

the EGUs' respective fuel costs and by the efficiencies with 

which they can convert fuel to electricity (i.e., their heat 

rates). Historically, natural gas has had a higher cost per unit 

of energy content (e.g., MMBtu) than coal in most locations, but 

for NGCC units this disadvantage in fuel cost per MMBtu relative 

to coal-fired EGUs is typically offset in significant part, and 

sometimes completely, by a technological heat rate advantage. 
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To consider the cost implications of building block 2, the 

EPA expanded upon the proposal’s extensive analysis of the 

magnitude and cost of CO2 emission reductions through generation 

shifting within defined areas (consistent with the application 

of building blocks for performance rate- and goal-setting), 

without consideration of the availability of emission reduction 

measures reflected in the other building blocks. 

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. The EPA conducted such 

scenarios to address average utilization targets of 70 percent, 

75 percent and 80 percent on a net basis, allowing for shifting 

of fossil generation between existing units within the regions 

described above. This scenario identifies a generation pattern 

that would meet electricity demand at the lowest total cost, 

subject to all other specified operating and bulk power transfer 

constraints for the scenario, including the specified average 

NGCC unit utilization rate. 
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The costs of the various scenarios were evaluated by 

comparing the total costs and emissions from each scenario to 

the costs and emissions from a business-as-usual scenario. For 

the scenario reflecting a 75 percent NGCC utilization rate on a 

net basis with regional fossil generation shifting, comparison 

to the business-as-usual case indicates that the average cost of 

the CO2 reductions achieved over the 2022-2030 period was $40 per 

metric ton of CO2, comparable to the average cost estimated for 

this building block at proposal. We view these estimated costs 

as reasonable and therefore as supporting the use of a 75 

percent net utilization rate target for purposes of quantifying 

the emission reductions achievable at a reasonable cost through 

the application of building block 2 in the BSER. 

We also conclude from these analyses that potential impacts 

to fuel prices and electricity prices from achieving the extent 

of fossil generation shifting estimated 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 X over the 2022-2030 period, which is well within the 
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range of historical natural gas price variability.503 Projected 

wholesale electricity price increases over the same period were 

X, which similarly is well within the range of historical 

electric price variability. These projected impacts on prices 

were captured in the emission reduction costs of these scenarios 

already described above, which are reasonable and support use of 

a 75 percent NGCC utilization rate target for purposes of 

quantifying the emission reductions achievable through 

application of the BSER. 

However, we also note that the costs (and their 

incorporated price impacts) just described are higher than we 

would expect to actually occur in real-world compliance with 

state goals. One reason for this is that the building block 2 

phase-in reduces the average utilization rate over the interim 

period to less than 75 percent in all three interconnections. 

Additionally, the 75 percent utilization rate in the scenario 

exaggerates the stringency with which building block 2 is 

actually reflected in each of the state goals: While the goal 

computation procedure uses a maximum of 75 percent (before the 

phase-in) as a target NGCC utilization rate on a national 

average basis, this target is only achieved in the Eastern 

 

503 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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Interconnection. Performance rates in the Western and Texas 

Interconnections are not based on the full 75 percent NGCC 

utilization rate in those regions. Also, at least some states 

may be able to achieve additional emission reductions through 

other measures that, if less costly than generation shifting, 

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’ flexibility to 

choose among alternative CO2 reduction strategies that could 

offer lower-cost reductions, instead of relying on fossil 

generation shifting to the extent analyzed here. 

Based on the analyses summarized above, the EPA concludes 

that an average annual utilization rate for each region’s NGCC 

units of up to 75 percent is a technically feasible, costeffective, and adequately demonstrated building block for BSER. 

For further information on the analysis discussed in this 

section, see Chapter X 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 proposed 
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rule. This section summarizes some of these comments, and the 

remainder of the comments are responded to in the Response to 

Comment document, available in the docket. 

The EPA received multiple comments regarding the proposed 

use of nameplate capacity in calculating the generation 

potential under building block 2. These comments stated that net 

summer capacity is a more meaningful and reliable metric than 

nameplate capacity, because net capacity best reflects the 

electric output available to serve load. The EPA agrees with 

these comments. In response, the EPA reexamined historical data 

on a net summer basis and found that increasing the annual 

average utilization rates of existing NGCC units to 75 percent 

on a net summer basis would be technically feasible. Consistent 

with this analysis, performance rate and state goal calculations 

in the final rule are also based on net summer generating 

capacity. 

The EPA also 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 
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direct emissions from power plants. The technical details 

supporting this analysis can be found in the Regulatory Impact 

Assessment. 

Commenters also express 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 RTO or ISO. 

These entities currently control the dispatch of their units 

while respecting existing all requirements from environmental 

rules. This final rule does not change these current 

circumstances, and makes clear that it is the EGU that is 

responsible for meeting the requirements in the state plan; the 

state is responsible for the development of that plan, but does 

not need to control the dispatch. 

Commenters have further argued that the proposed rule will 

have the unintended consequence of requiring environmental 

dispatch. The EPA does not believe the proposed rule has any 

such consequence, because nothing in the rule requires dispatch 

entities to depart from current economic dispatch principles. 

This final rules makes that point even clearer by emphasizing 
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the role of market based approaches and the use of tradable 

emission rate credits and mass allowances that enable the 

incorporation of costs as part of the standard economic 

dispatch. 

Other comments object to the use of a single capacity 

factor goal on the grounds that not all units can achieve this 

goal of the highest performing units, and that some may be 

designed for cycling and so may need upgrades. The EPA disagrees 

with these comments. The 75 percent capacity factor establishes 

a regional potential for generation from existing NGCC capacity, 

and an individual unit requirement. The EPA has set this target 

to reflect the fact that a portion of NGCC units already run 

above that capacity factor and are generally designed to have 

availabilities above that level.504 Moreover, by encouraging 

higher capacity factors, the final rule should actually result 

in less cycling rather than more. 

Another concern expressed by commenters on the proposed 

rule was the disparity in state goals among different states. 

The EPA recognizes these comments and has designed the final 

rule to greatly reduce such disparity, by setting a single 

performance rate for each technology and using those performance 

rates as the basis for calculating state goals. As a result, the 

 

504 See Chapter X of GHG Abatement TSD. 
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EPA believes these adjustments to the rule address these 

comments. 

E. Building Block 3 — New Low- and Zero-carbon Generating 

Capacity 

 The third element of the foundation for the EPA’s BSER 

determination for reducing CO2 emissions at affected fossil fuelfired EGUs entails an analysis of the extent to which generation 

at the affected EGUs can be replaced by using an expanded amount 

of low- and zero-carbon electricity generating capacity, such as 

renewable electricity (RE), to produce replacement generation. 

In this section we address: the history and trends in RE 

development, the importance of expanding the use of RE, the 

adequate demonstration of this building block as a component of 

the BSER, changes made from the proposal, key comments, the 

method by which RE target generation levels are quantified, the 

magnitude and timing of increases in RE generation associated 

with this building block, and the reasonableness of costs 

associated with those increases. 

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, solar and water. While 

RE has been used to generate electricity for over a century, the 
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push to commercialize RE more broadly began in the 1970s.505

Following a series of energy crises, new federal organizations 

and initiatives were established to coordinate energy policy and 

promote energy self-sufficiency and security, including solar 

energy legislation, the Public Utility Regulatory Policies Act 

of 1978 (PURPA) and the 1980 Energy Security Act.506 

 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.507 

 Since 1992, federal tax policy has provided important 

financial support via tax credits for the production of RE and 

investments in RE. While the specific provisions for these tax 

credits have expired and been renewed (or extended) a number of 

 

505 Nearly all hydroelectric capacity was built before the mid1970s. U.S. DOE. History of Hydropower. Accessed March 2015. 

Available at: http://energy.gov/eere/water/history-hydropower. 

506 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. 

507 “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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times, the financial support has helped drive recent growth in 

RE. 

 States have also taken a significant lead in requiring the 

development of RE resources. In particular, a number of states 

have adopted renewable portfolio standards (RPS), which are 

regulatory mandates to increase production of RE. As of 2013, 29 

states and the District of Columbia have enforceable RPS or 

similar laws.508 These RPS requirements and federal tax credits 

continue to drive the relatively robust near-term growth of nonhydropower 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., 

 

508 Energy Information Administration, Annual Energy Outlook 2014 

with Projections to 2040, at LR-5 (2014). 
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modern wind turbines power electronics allow turbines to provide 

voltage and reactive power control at all times).509,510 

 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 2005.511 Total non-hydro RE 

capacity was approximately 16,000 megawatts (MW) in 1998. In 

2013, total non-hydro RE capacity was five times higher with 

80,000 MW.512 In particular, there has been substantial growth in 

the wind and solar photovoltaic (PV) markets in the past decade. 

Since 2009, wind energy has tripled and solar capacity has grown 

twenty-fold.513 

 

509 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. 

510 American Wind Energy Association. AWEA Comments on EPA’s 

Proposed Carbon Pollution Emission Guidelines for Existing 

Stationary Sources and Supplemental Proposed Rule. p. 107. 

511 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. 

512 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/. 

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

billion per year by 2030.514 RE growth is further spurred by the 

significant amount of existing natural resources that can 

support RE production in the United States.515 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.516 In the reference 

case, RE generation increases by more than 70 percent from 2013 

to 2040 and accounts for over one-third of new generation 

capacity.517

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.518 Introducing 

more zero-emitting RE generation over the long-term could 

significantly reduce CO2 emissions, as production of RE 

 

514 “Global Renewable Energy Market Outlook.” Bloomberg New 

Energy Finance, November 16, 2011, Available at: 

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

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

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

516 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at LR-5 (2014), P. 25. 

517 Energy Information Administration, Annual Energy Outlook 2015 

with Projections to 2040, at LR-5 (2014), P. ES-6-7. 

518 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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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 

50 percent by 2030).519 A recent IPCC report also concluded that 

RE has large potential to mitigate CO2 emissions.520

 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.521

Increasing RE use will also continue to lower other air 

pollutants (e.g., fine particles, ground-level ozone, etc.), 

 

519 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. 520 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. 

521 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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diversify energy supply, hedge against fossil fuel price 

increases and create economic development and jobs in 

manufacturing, installation, and other sectors of the economy. 

4. Ownership of RE by Fossil Fuel-Fired EGUs 

The ability of affected EGUs to obtain incremental RE to 

reduce CO2 emissions is well-demonstrated, whether it is through 

direct ownership, bilateral contracts, or procurement of the 

environmental attributes associated with RE generation.522

Consequently, the EPA believes that an increase in RE is a 

proven way to reduce CO2 emissions at affected EGUs of all types 

at a reasonable cost. 

Affected EGUs have already directly invested in RE. Of the 

417 entities that owned part of at least one affected EGU under 

this rule, 191 also owned RE (biomass, geothermal, solar, water 

or wind). These 191 owners owned 84 percent of affected EGU 

capacity. As a whole, these entities’ share of RE capacity was 

equal to 21 percent of the total of their affected EGU 

capacity.523

Some of the largest owners of affected EGUs also owned RE 

(see Table 7). Of the more than 3,000 MW of RE capacity owned by 

NRG Energy, Inc., solar represents over 20 percent (nearly 800 

 

522 Refer to GHG Abatement Measures TSD for additional ownership 

statistics. 

523 SNL Energy. Data used with permission. Accessed January 2015. 
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MW) and wind was almost 80 percent of the total (over 2,500 MW). 

Duke Energy Corporation owns 175 MW of solar and over 1,500 MW 

of wind. NextEra Energy, Inc.’s share of RE capacity approaches 

40 percent of their total affected EGU capacity.524

TABLE 7. Ownership of Affected EGUs and RE Capacity. 

Ultimate Parent Covered 

Units 

Generation 

(MWh) 

Covered 

Units 

Capacity 

(MW) 

Renewable 

Capacity 

(MW) 

NRG Energy, Inc. 112,018,189 48,964 3,303 

Duke Energy Corporation 155,255,056 38,446 4,917 

Southern Company 138,080,958 36,328 3,317 

American Electric Power 

Company, Inc. 

143,547,594 35,526 1,158 

NextEra Energy, Inc. 104,325,610 28,344 11,164 

Calpine Corporation 99,589,172 24,148 1,637 

Entergy Corporation 48,954,652 23,411 145 

Tennessee Valley 

Authority 

83,774,468 21,717 5,429 

Berkshire Hathaway Inc. 83,558,238 18,899 6,342 

FirstEnergy Corp. 72,021,222 16,175 1,372 

 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 

 

524 Ibid. 
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of RE for their members. Federal power authorities own or 

contract significant amounts of RE.525,526

The list of the ten largest electric utilities with wind 

power capacity on system (owner or under contract) includes 

vertically integrated utilities, municipal utilities, and 

federal power authorities. Xcel Energy and Berkshire Hathaway 

Energy rank number one and two with 5,736 MW and 4,992 MW of 

wind capacity, respectively. Basin Electric Power Cooperative 

had 716 MW and CPS Energy, a public utility, had 1,059 MW of 

wind power capacity.527

Many affected EGUs are already planning on significant 

amounts of RE according to their integrated resource plans 

(IRPs). For instance, Dominion plans for over 800 MW of wind and 

solar in their 2015 to 2029 planning period. Electric utilities 

use IRPs to plan operations and investments over long time 

horizons. These plans typically cover 10 to 20 years and are 

mandated by public utility commissions (PUCs). 

 

525 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. 

526 SEIA comment pp. 98-147. 

527 American Wind Energy Association. U.S. Wind Industry Annual 

Market Report (2014 data). Accessed April 2015. Available at 

http://www.awea.org/AnnualMarketReport.aspx?ItemNumber=7422&RDto

ken=64560&userID=. 
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 EPA agrees with commenters that highlighted the opportunity 

owners and operators of affected EGUs across the U.S. already 

have to procure RE. Commenters found many fossil fuel-fired EGU 

owners own or contract for RE and can control the dispatch mix 

among these sources. 

One commenter highlighted that in many parts of the 

country, EGUs are owned and operated by vertically integrated 

utilities. These utilities can be investor owned utilities that 

operate under traditional electricity regulation, municipal 

utilities (munis), or electric cooperatives (co-ops). These 

utilities have significant control over the types of generating 

capacity they develop or acquire, and over the electricity mix 

used to meet demand within their service territories. 

The commenter similarly observed that EGU owners 

participating in organized markets retain sufficient control to 

substitute fossil fuel-fired generation with RE, even when those 

EGU owners do not directly determine dispatch among energy 

sources. They offered the example of Oklahoma Gas & Electric 

(OG&E), which owns generation assets utilizing coal, gas-fired 

combined cycle and wind technology and is able to make decisions 

regarding the utilization of fossil fuel-fired EGUs and energy 

assets within the rules of the regional transmission 

organization (RTO). OG&E and other EGU owners, including munis 
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and co-ops operating in organized markets, can also make longerterm decisions about what types of capacity they choose to 

develop going forward. 

The commenter also emphasized that independent power 

producers (IPPs) also can and do own both RE and fossil 

generation. They provided the example of NRG, which is a 

diversified IPP that operates substantial coal, natural gas, 

wind, solar, and nuclear capacity. NRG demonstrates the ability 

of IPPs to reduce utilization of fossil fuel-fired EGUs and 

replace that generation with RE. NRG announced a goal to cut CO2

emissions from its fleet 50 percent by 2030 (from a 2014 

baseline). NRG has already reduced CO2 emissions from its fleet 

by 40 percent since 2005. This demonstrates that when an IPP 

commits to shifting its generation portfolio, it can do so at 

reasonable cost and without reliability impacts. The NRG example 

shows that reduced utilization of fossil fuel-fired EGUs that is 

replaced by RE also owned by the EGU owner is adequately 

demonstrated. 

Commenters said EGU owners can replace fossil fuel-fired 

generation with RE through bilateral contracts and renewable 

energy credit (REC) purchases. They stated that the bilateral 

market for RE and REC markets are well developed. There are no 

legal or technical obstacles to a fossil fuel-fired EGU owner 
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acting as the counterparty of a bilateral contract for purchase 

of energy from a RE facility. Purchase of RECs tracked in a 

registry is not limited to utilities. Third parties, including 

IPPs, can purchase and retire RECs. To date, there has not been 

significant need for merchant generators to purchase RECs. 

However, there are no legal or technical obstacles that would 

prevent this action. The fact that RECs are purchased by a 

diverse set of market participants—including residential 

consumers, commercial businesses, and industrial facilities—

demonstrates that such a purchase for all EGU owners is 

adequately demonstrated. 

5. Renewable Energy Credit Markets 

 RECs are used to demonstrate compliance with state RE 

targets, such as state RPS, and also to substantiate claims 

stemming from RE use. RECs are tradable instruments that 

represent the generation of one megawatt-hour (MWh) of RE and 

certain information or characteristics of the generation, called 

attributes.528 RECs are traded and transferred regardless of the 

actual energy flow. REC ownership confers the right to claim the 

generation attributes. 

 

528 EPA Green Power Partnership, Renewable Energy Certificates 

July 2008). Available at 

http://www.epa.gov/greenpower/documents/gpp_basics-recs.pdf. 
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 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 ruled that states have 

created RECs in programs designed to promote increased use of 

RE, and that “attributes associated with the facilities are 

separate from, and may be sold separately from, the capacity and 

energy.”529 

 In complying with states’ RPS requirements in 2012, 61 

percent of RECs were sourced from in-state resources (65 percent 

on weighted average basis). When sourcing RECs from out-ofstate, RPS requirements typically restrict eligible RECs to the 

state’s region (e.g., ISO or neighboring states). Utilities may 

have sourced RECs from out-of-state to reduce the cost of 

compliance, to source RECs from specific generation types, or 

for other reasons.530

 

529 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). 

530 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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6. Quantification of Renewable Energy Generation Potential for 

BSER and Major Comments 

The methodology for quantifying RE target generation levels 

under building block 3 is a modified version of the alternative 

RE approach from proposal, with adjustments that reflect the 

data and information the EPA collected through stakeholder 

comments. In evaluating the proposed and alternative RE 

approaches, commenters observed that RPS, as the basis for 

setting RE target generation levels under the proposed approach, 

are policy instruments that states may choose to implement for a 

variety of reasons not related to CO2 emission reductions. 

Additionally, differences across RPS policies in eligible 

resources, crediting mechanisms, deliverability requirements, 

alternative compliance payments, and other policy elements made 

the regional averaging of state-level RPS requirements 

challenging. Finally, commenters provided data demonstrating 

that RE resource potential can vary significantly within the 

regions identified under the proposed approach, producing statelevel targets 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 technical basis for quantifying building block 3 target 
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generation levels that accounts for regional differences in RE 

resources and power market conditions. The EPA agrees with these 

comments. 

 Within the framework of the alternative RE approach, the 

EPA received significant comments on the interstate nature of RE 

and the power system, use of total RE generation to define 

target generation levels, RE technologies that contribute to 

setting target generation levels, cost and performance estimates 

associated with those technologies, magnitude of the reduced 

cost applied to new RE capacity as an incentive to deploy, and 

application of a nationally uniform technical potential limiter 

to modeled projections of economic deployment. Based on 

commenter data and information, the primary adjustments the EPA 

made to the alternative RE approach are: 

 The target generation level is 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.531

Specifically, the target generation levels under building block 

 

531 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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3 include all generation from BSER RE technologies that 

commenced operation subsequent to the BSER data year of 2012. 

 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), target generation levels are 

quantified for each of the three BSER regions – the Eastern 

Interconnection, Western Interconnection, and Texas 

Interconnection – rather than at the state-level. 

 The BSER RE technologies used to quantify target generation 

levels no longer include landfill gas and concentrated solar 

power (CSP). Incremental landfill gas and CSP generation are no 

longer projected to deploy on an economic basis during the 

compliance period and consequently have been removed as BSER RE 

technologies. All other RE technologies from the proposed 

alternative approach – onshore wind, utility-scale solar PV, 

geothermal and hydropower – are maintained as part of the BSER 

and no new RE technologies have been added. 

 Commenters observed that the cost and performance estimates the 

EPA relied on at proposal from the Energy Information 

Administration’s Annual Energy Outlook 2013 are outdated and do 

not reflect the decline in cost and increase in performance that 

have been demonstrated by current projects, particularly in 

regards to wind and solar. Commenters provided data from a 
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variety of sources to support these claims, including Lawrence 

Berkley National Lab, the Department of Energy (DOE) and Lazard. 

Consequently, cost and performance estimates for onshore wind 

and utility-scale solar technologies were revised to reflect the 

mid-case estimates from the National Renewable Energy 

Laboratory’s (NREL’s) 2015 Annual Technology Baseline. 

 The final methodology for quantifying building block 3 target 

generation applies a reduced cost of building new RE capacity of 

$40 per metric ton CO2. This cost represents the avoided cost of 

other actions that could be taken instead to reduce CO2 emissions 

from the utility power sector and, unlike at proposal, is not 

derived from RE technology cost assumptions but rather results 

from the costs associated with building block 2. A harmonized 

cost-effectiveness threshold across building blocks 2 and 3 

ensures that emission reduction opportunities are evaluated for 

inclusion in the BSER on equitable terms. 

 The technical potential limiter that constrained cost-effective 

RE deployment under the alternative approach has been removed 

from the final methodology.532 Commenters observed several issues 

with applying the technical potential limiter, including that 

 

532 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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this feature limits future performance to historical levels of 

development, does not factor in the total size of the RE 

resource in a given state, relies on non-exclusive resource 

estimates where a single area of land may contribute to the 

technical potential of multiple RE technologies, and is 

inconsistent with a regional approach to quantifying target 

generation levels. EPA agrees with these comments and the 

technical potential limiter 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 2. Many of these comments provided 

helpful information and insights, and have resulted in 

improvements to the final rule. These comments, as well as EPA 

responses are available in the Response to Comment document. 

The final methodology for quantifying incremental RE target 

generation levels relies on a combination of modeling and nonmodeling approaches that produce regional technology-specific 

estimates. 

Estimates for the economic potential of new hydropower are 

the result of a DOE avoided cost methodology that develops 

regional hydropower supply curves and compares that supply 

potential against the revenue available to those projects 

through regional marginal generation prices and capacity values. 
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The deployment levels of hydropower are increased until total 

generation costs, inclusive of the reduced cost of building new 

RE capacity, equal avoided costs for each region. 

In contrast, economic potential estimates for utility-scale 

solar photovoltaic (PV)), onshore wind and geothermal 

technologies are the result of IPM modeling projections that 

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 (resource 

quality, land use exclusions, terrain variability, distance to 

existing transmission, population density etc.), system 

constraints (interregional transmission limits, partial reserve 

margin credit for intermittent RE installations, minimum 

turndown constraints for fossil fuel-fired EGUs, short-term 

capital cost adders to reflect the potential added cost due to 

competition for scarce labor and materials etc.) and technology 

constraints (construction lead times, hourly generation profiles 

for non-dispatchable resources by season etc.).533 Additionally, 

deployment of variable, non-dispatchable RE resources in IPM is 

limited to 20 percent of net energy for load by technology type 

 

533 Refer to GHG Abatement Measures TSD for more detail on 

modeling methodology. 
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and 30 percent of net energy for load in total at each of IPM’s 

64 U.S. sub-regions.534 These constraints do not represent a 

technical feasibility limit but rather a conservative view of 

penetration levels that would not require significant grid 

integration costs.535 

To reflect the interstate nature of the power system, the 

economic potential identified under the avoided cost and 

modeling approaches is presented on a regional basis. Three 

power sector regions are used for this purpose – the Eastern 

Interconnection, Western Interconnection and Texas 

Interconnection.536 

The regional economic potential in 2030 sets the final RE 

target generation level under building block 3. To ensure 

adequate opportunity to plan for and implement any necessary RE 

integration strategies and investments, 2030 economic potential 

levels are phased in over the interim compliance period in three 

stages – 2022 through 2024, 2025 through 2027, and 2028 through 

2030. The first stage of deployment limits growth in RE target 

generation to annual increases consistent with the most recent 

 

534 Regions that have already exceeded these limits are held at 

historical percent of net energy for load. 

535 Refer to the GHG Abatement Measures TSD for additional 

information on constraints related to deployment of nondispatchable RE. 

536 Refer to Section V.A.3. 
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five-year deployment averages for the BSER RE technologies. The 

second stage limits annual target generation growth to levels 

consistent with the historical maximum deployment for the BSER 

RE technologies. The third stage increases target generation 

levels at a constant level from 2028 through 2030 to achieve the 

2030 economic potential.537 Regional RE target generation values 

for all years, representing RE generation incremental to the 

BSER data year of 2012, are presented below. 

TABLE 8. Building Block 3 Target Generation Levels (MWh). 

Year Eastern 

Interconnection 

Western 

Interconnection 

Electric 

Reliability Council 

of Texas 

2022 145,326,468 56,931,543 31,058,067 

2023 167,746,931 60,443,578 37,217,478 

2024 189,692,816 64,798,622 43,008,457 

2025 233,278,550 76,786,908 53,643,200 

2026 271,801,204 95,456,423 62,659,794 

2027 309,867,354 114,669,103 71,589,727 

2028 366,885,008 141,757,894 84,920,883 

2029 423,280,371 169,587,110 98,133,904 

2030 479,177,844 198,008,732 111,252,409 

7. Cost of CO2 Emission Reductions from Renewable Energy 

Generation 

 The EPA believes that RE generation at the levels 

represented in building block 3 can be achieved at reasonable 

costs. The DOE avoided cost methodology applies a reduced cost 

 

537 Additional information on interim period RE target generation 

levels is available in the GHG Abatement Measures TSD. 
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of building new hydropower generating capacity of approximately 

$35 per metric ton. Under the modeling approach, the EPA applies 

a reduced cost of building new utility-scale solar PV, onshore 

wind and geothermal generating capacity of $40 per metric ton 

CO2. This reduced cost is translated to $28 per MWh for inclusion 

in the modeling framework, under the assumption that incremental 

RE is replacing affected EGU generation of an approximate 

emissions intensity of 0.7 metric tons of CO2 per MWh.538 The 

projected total power system cost of applying this reduced cost 

to the EPA Base Case is $2.2 billion annually from 2022 through 

2030. Total power system costs are a function of annualized 

capital costs, variable operating expenses, fixed operating 

expenses, fuel purchases and the expense associated with the 

benefit of providing the reduced cost to each qualifying RE 

build. The projected emission reductions average 165 million 

metric tons from 2022 through 2030. Consequently, the cost of 

achieving CO2 reductions through the expansion of RE generation 

is $13 per metric ton on average from 2022 through 2030.539 

There are a number of reasons why the EPA believes that the cost 

of CO2 emission reductions from RE generation will be lower than 

 

538 In the EPA Base Case, fossil fuel-fired EGUs are projected to 

operate in the EPA Base Case at approximately 0.72 metric tons 

of CO2 per MWh in 2030. 

539 Refer to the GHG Abatement Measures TSD for further analysis 

and IPM run results. 
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what is presented in this section. First, interim period target 

generation is, on average, more than 20 percent less than the 

economic potential identified by the modeling and avoided cost 

approaches. Second, modeling constraints that restrict nondispatchable RE to a percentage of net energy for load at each 

of the 64 U.S. IPM regions represents uncertainty associated 

with grid integration costs rather than a determination of 

technical infeasibility. In fact, many regions have demonstrated 

levels of RE penetration that exceed the constraints. Third, the 

total system costs presented in this section assume all 

incremental generation in the compliance period receives the 

full benefit of the cost reduction; however, the majority of 

cost-effective RE generation projected by IPM does not require 

the full $28 per MWh reduced cost to become economic. Fourth, 

there are a number of RE technologies not included in the BSER 

that may contribute to compliance with building block 3 target 

generation, including distributed generation technologies, 

offshore wind, CSP, waste-to-energy and many other technologies 

that are already in widespread use.540 The EPA believes that 

these factors provide significant opportunities for lower-cost 

achievement of the building block 3 target generation levels. 

VI. Source Category-Specific CO2 Emission Performance Rates 

 

540 See Section VIII.G for a description of qualifying non-BSER 

RE technologies 
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A. Overview 

In this section, the EPA sets out technology-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 source categories affected by 

the rule (fossil steam generation and gas-fired combustion 

turbines).541 These final emission performance rates reflect the 

EPA’s quantification of the BSER based on the three building 

blocks described in section V above. This procedure follows a 

similar logic to BSER quantification at proposal, but it keeps 

the emission performance rates separate for fossil steam and 

NGCC source categories instead of immediately blending them 

together into a single value for all affected categories. 

Commenters noted that the proposed rule established standards 

that were based on the aggregation of units, and their reduction 

potential, in a state rather than providing technology-specific 

standards. While many commenters appreciated the flexibility 

this state-focused structure provided, some noted two concerns 

with this approach: 1) it would potentially create different 

 

541 The only gas units currently considered “likely affected” 

units are turbines at NGCC units (both the gas and steam 

turbine). The remainder of the section will use the term “NGCC” 

to collectively refer to the output from both the steam and gas 

turbines at a NGCC unit. 
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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 standards by not providing technology-specific 

standards of performance. In response to comments, the final 

rule establishes technology-specific emission performance rates 

that are identical across units within a source category 

regardless of where a unit is located within the continental 

U.S.542 

These performance rates reflect the average emission rate 

requirement for each source category. Similar to the proposal, 

they are presented as adjusted average emission rates that 

reflect other generation components of BSER in addition to the 

fossil component. These performance rates must be achieved by 

2030 and sustained thereafter. The interim performance rates 

apply over a 2022-2029 interim period and would be achieved on 

average through 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 

 

542 As noted later in this section, the approach for states and 

U.S. territories outside the continental U.S. does not rely on 

the emission performance rates because units in these areas do 

not have access to regional interconnected grids. 
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technology categories as they scale up to their full BSER 

potential by 2030. The performance rates are meant to reflect 

emission performance required across all affected units when 

averaged together and inclusive of lower-emitting BSER 

components. 

 The performance rates are expressed in the form of 

adjusted543 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 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 units within a state. 

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 of the 

building blocks to that state would not be expected to produce 

 

543 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 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 Final Rule and the 

Greenhouse Gas Abatement Measures TSD. Specific topics addressed 

in the various TSDs are noted throughout the discussion below. 

B. Performance Rate Requirements 

The EPA has developed a single performance rate requirement 

for existing fossil steam units in the continental U.S., and a 

single rate for existing gas turbines in the continental U.S., 

reflecting application of the BSER, based on all three building 

blocks described earlier, to pertinent data. The rates are 
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intended to represent CO2 emission rates achievable by 2030 after 

a 2022-2029 interim period on an output-weighted-average basis 

collectively by all affected EGUs, with certain computation 

adjustments described below to reflect the potential to achieve 

mass emission reductions by avoiding fossil fuel-fired 

generation. 

1. Final performance rate requirements 

The performance rates are set forth in Table 8 below, 

followed by a description of the computation methodology. 

Table 8. 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 

1,465 1,290 

Stationary Combustion 

Turbines 

810 780 

 

 The performance rates are expressed as adjusted outputweighted-average emission rates for each technology. As 

discussed later in this section, the emission rate computation 

includes an adjustment designed to reflect mass emission 

reductions associated with lower-emitting BSER components. The 

adjustment is made by estimating the annual net generation 

associated with an achievable amount of qualifying incremental 

lower-carbon and zero-carbon generation and substituting those 
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MWhs (along with corresponding emissions) for the baseline 

electricity generation and CO2 emissions from the higher-emitting 

affected EGUs. Under the final rule approach, regionally 

identified building block three potential generation replaces 

fossil steam and NGCC generation on a pro-rata basis 

corresponding to the historic mix of fossil generation in each 

region. However, as discussed in Section VIII, it the state 

decides to implement these adjustments in its state plan, the 

state must still demonstrate compliance with the CO2 emission 

performance rates for affected EGUs or the equivalent statebased goals provided in section VII. 

2. Interim Emission Performance Rates 

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 
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reflect the averaging of estimated emission performance rates 

for each year in the interim period (i.e., 2022-2029). 

The interim performance rates are less stringent than the 

final 2030 emission performance rates because the amount of 

emission reduction potential identified for the BSER increases 

over time, as explained in section V above. 

C. Form of the Performance Rates 

1. Rate-based standard 

 The interim and final emission performance rates for fossil 

steam and NGCC units are presented in the form of adjusted 

output-weighted-average CO2 emission rates that the affected 

fossil fuel-fired units could achieve, on average, through 

application of the measures comprising the BSER (or alternative 

control methods). Several aspects of this form of emission rate 

are worth noting at the outset: the use of emission rates 

expressed in terms of net rather than gross energy output; the 

use of output-weighted-average emission rates for all affected 

EGUs; the use of adjustments to accommodate incremental NGCC 

generation and renewable energy measures that reduce CO2

emissions by reducing the quantity of fossil fuel-fired 

generation and associated emissions; and the adjustability of 

the goals based on the severability of the underlying building 

blocks. 
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a. Rationale for a rate-based standard. First, the EPA sets an 

emission rate requirement for each source category by 

identifying the technology-specific reductions available under 

the building blocks. It then gives each state the choice to 

apply the emission performance rates directly to the affected 

units 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 or statewide mass-based goal are 

alternative implementation metrics for realizing the emission 

performance rates at the aggregate 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 standards that apply 

uniformly to technology categories nationwide, and the EPA is 

providing corresponding state emission rate goals and state mass 

goals to maximize 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. 
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b. Net vs. gross MWh. The second aspect noted above concerns 

the expression of the goals in terms of net energy output544 – 

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.545 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 already have in place 

the equipment necessary to collect and report hourly net 

generation, and we have determined that the reporting 

requirement would therefore not be burdensome. 

c. Output-weighted performance rates for all affected EGUs. 

This final rule provides an expression of the BSER that stops 

 

544 As discussed below in Section VIII on state plans, we are 

similarly determining that states choosing a rate-based form of 

emission performance level for their plans should establish a 

requirement for affected EGUs to report hourly net energy 

output. 

545 For some EGUs, total net or gross energy output also includes 

useful thermal output, in addition to either net or gross 

electric energy output. 
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one step short of the state goals provided at proposal. Whereas 

the proposal also estimated the BSER impact on fossil steam and 

NGCC emissions and generation, it went one step further by 

averaging these two technology rates into a single rate for each 

state. Under this final rule, the EPA is identifying the fossil 

steam rate and the NGCC rate separately instead of only 

presenting them in a blended fashion at the state level.546 These 

two emission performance rates are the expression of the BSER 

for the final rule for affected EGUs located within the 

continental U.S. 

The modification from a blended emission rate in the 

proposed rule to a technology-specific emission performance rate 

for affected EGU categories in the final rule was made in 

response to comments that technology-specific emission rates 

were more analogous to prior 111(d) efforts and more consistent 

with the statute. The EPA received significant comment 

suggesting a technology specific, source-specific requirement is 

consistent with past section 111(d) regulations. However, many 

 

546 However, as discussed here and in the next section, in order 

to provide maximum flexibility to states, the EPA averages these 

two emission rates together for each state using their adjusted 

2012 baseline generation share to arrive at a single statewide 

emission performance goal. The state has the option to comply 

with this statewide goal through a compliance pathway of its 

choice. This compliance pathway may or may not involve requiring 

its affected units to meet the emission performance rates. 
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commenters also supported the flexibility provided to states 

through a state goal metric provided at proposal. Therefore, the 

EPA does provide alternative statewide rate-based and mass-based 

compliance goals in the next section. 

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 
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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. 

d. Severability of building blocks. Section V above discusses 

the severability of the three building blocks upon which the CO2

emission performance rates are based. Because the building 

blocks can be implemented independently of one another and the 

emission performance rates reflect the sum of the emission 

reductions from all of the building blocks, if any of the 

building blocks is found to be an invalid basis for the “best 

system of emission reduction ... adequately demonstrated,” the 

rates would be adjusted to reflect the emissions reductions from 

the remaining building blocks. As noted above, the performance 

rates and statewide goals that would result from any combination 

of the building blocks are computed and included in the CO2

Emission Performance Rate and Goal Computation TSD for Final 

Rule and its appendices using the methodology described below 

and elaborated on in that TSD. 

D. Performance Rate-Setting Equation and Computation Procedure

 The methodology used to compute the performance rates is 

summarized on a step-by-step basis below in section 3. The 

methodology is described in more detail in the CO2 Emission 
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Performance Rate and Goal Computation TSD for Final Rule, which 

includes a numerical example illustrating the full procedure. 

The quantification of the building blocks used in the 

computation procedure is discussed in Section V above and in the 

Greenhouse Gas Abatement Measures TSD. 

1. Inventory of likely affected EGUs 

In order to calculate the source-category emission rates 

reflecting the BSER, the EPA first needed to develop a baseline 

inventory of likely affected EGUs in order to estimate the 

impact of BSER. The EPA developed an inventory of likely covered 

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. 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 covered 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 

does not reflect a final applicability determination, and where 
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a unit’s status was unclear, the EPA generally treated the 

unit’s status in a manner consistent with the proposal.547

Since the final rule’s applicability includes under 

construction units, the EPA also identified units that had not 

yet commenced operation in the 2012 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. In some cases, NEEDS did not reflect units 

that had commenced construction. Therefore, the EPA updated its 

approach to identifying units that had commenced construction 

prior to January 8, 2014, but that had not commenced operation 

in 2012. In the final rule, the EPA uses EIA data, comments, as 

 

547 The EPA notes that in some cases, it may not yet be possible 

to determine the status of an EGU as affected or not affected 

without additional data. There are potentially some units 

excluded or included in the baseline that will ultimately have a 

different status following an applicability determination. 

However, these cases are limited, and the effect of any ultimate 

change in any given unit’s applicability status is unlikely to 

yield a significant change in the BSER computation at the 

regional level. The EPA does not believe that discrepancies 

between the inventory we assume here to be affected by the rule 

and the ultimate applicability status of any given unit would 

introduce any significant bias into the calculation of these 

uniform-technology rates. 
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well as NEEDS data to identify these “under construction” 

units.548,549 

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 Final Rule explains the prime 

mover, capacity, and fuel criteria used to identify the likely 

affected EGUs.550 

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 

 

548 The NEEDS database was also updated to reflect the latest 

data and commenter input on under construction units. 

549 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”. Some of these “under construction” 

units have commenced operation prior to signature of this final 

rule. 

550 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 based on already scheduled 

reductions. 
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made an adjustment to flag these units as having commenced 

operation during 2012 and treat them as under construction 

units, consistent with commenters’ suggestion; for BSER 

computational purposes, generation and emissions for these units 

are estimated based on a typical first full year operation for 

that technology class. 

2. Data year 

In the proposed rule, the EPA considered using a 

historical-year data set, a projected-year data set, or a hybrid 

of the two as a starting point for applying the technology 

assumptions identified under BSER. The EPA proposed using 2012 

data as it was the most recent data year for which complete data 

were available 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 it 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. 
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Moreover, some commenters pointed out that using 2010, 2011, 

2012 data, or an average of the three would not address their 

concerns about recent year anomalies in hydro generation due to 

high snow pack. Some commenters also suggested the EPA use a 

baseline including years prior to 2012, not to increase 

representativeness of the power sector, but as a means of 

recognizing early action. 

In this final rule, the EPA is taking a hybrid approach 

where it still largely relies on reported 2012 data as the best 

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. 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 
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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 13 GW of capacity that 

operated in 2010 and/or 2011 were retired prior to 2012. 

Using state-level, prior year data, either on its own, or 

as part of a multi-year baseline, is not as 

representative of the current power fleet as the 2012 

data, which better reflects significant changes in power 

sector infrastructure. 

2) A three-year baseline would not address some of the 

substantive concerns raised by commenters. Many 

commenters pointed out that using a three-year baseline 

would not address their critical concern about variation 

in the hydrological cycle due to snow pack (particularly 

in the Northwest), because the snow pack was 

significantly above average in both 2011 and 2012. The 
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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 a multiple baseline years 

would require additional assumptions in regards to which 

generation to consider from a fleet that is changing in a 

given state or region (or even where units are switching 

fuel sources such as a coal-to-gas conversion). 
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4) Due to the region-based nature of deriving 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 

does not vary to the same degree that unit-level data 

varies. Moreover, the variation at the regional-level 

that does exist in 2012 relative to previous years is not 

necessarily random variation, but illustrates trends in 

the power sector infrastructure that are desirable to 

capture for purposes of determining a representative year 

from which further improvements in CO2 emissions 

performance can be made. Because the EPA is moving from a 

state approach at proposal to a regional approach for 

calculating the expression of the BSER in this final 

rule, unit-level operational variation from year to year 

becomes even less relevant to the calculation of regional 

emission performance rates (i.e., an outage in a fossil 

unit in one region is likely to be offset by increased 

generation from another fossil unit in that same region). 
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5) Some commenters suggested the EPA use an earlier baseline 

year as a means of recognizing early action. They noted 

that an earlier baseline would reflect a higher-emitting 

fleet and therefore when the same level of building block 

MWhs are applied, they would result in a higher (i.e., 

less stringent) state goal. The EPA disagrees with this 

view for several reasons. First, the objective of 

selecting a baseline to inform BSER is to have one that 

best reflects the power sector and consequently the best 

system of emission reductions of which the power fleet is 

capable. Using an earlier baseline that “inflates” the 

starting point would undermine this objective, not serve 

it. Second, the EPA disagrees with the premise of this 

comment – that the baseline would change and building 

block potentials would stay the same. For instance, 

building block two is based on incremental generation 

potential (incremental generation = potential generation 

– actual 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). 
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However, that comparison is not relevant to the 

quantification of emission reduction potential under 

111(d). In those previous instances, the EPA was 

considering typical unit-level behavior for allowance 

allocation purposes – not for determining the emission 

reduction requirements of the program. Those allowance 

allocation determinations were independent of and 

subsequent to the determination of emission reduction 

requirements in those rulemakings. 

7) The EPA received significant comment that 2012 was not a 

representative year for natural gas prices, and thus the 

EPA should use another year. The EPA disagrees with this 

comment, and does not view it as grounds for a change to 

the baseline period. While the EPA does recognize that 

Henry Hub natural gas prices averaged approximately 

$2.75/MMBTU in 2012, which is lower than 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 
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generation in 2012 when gas prices dropped. However, this 

does not change the outcome of the EPA quantification of 

the BSER, because the BSER is based on the emission 

reduction potential of the fleet. That potential (e.g., a 

fuller realization of the existing NGCC generation 

potential equivalent to 15 MWh) does not change 

regardless of the year used for baseline NGCC generation. 

Therefore, a different data year may change a baseline 

data point, but it would not change the ending point 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 

Although the EPA determined that the 2012 data year better 

informed its BSER determination than a preceding year or a 

multi-year average, commenters did identify some limitations 

that we are addressing through targeted adjustments. These are 

discussed below: 
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1) Adjustments to state-level data to account for annual 

variation in the hydrologic cycle as it relates to fossil 

generation. 

Hydropower plays a unique role in a handful of states in 

that it is 1) a significant portion of their generation 

portfolio, 2) 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.551 Therefore, no similar adjustment was needed to 

account for weather patterns with these technologies. 

Unlike market conditions (e.g., changes in natural gas 

prices) that may produce different generation profiles 

year-to-year but that do not change the overall generating 

potential of the fossil fuel-fired fleet, variation in the 

hydrologic cycle does fundamentally change the generating 

potential of the fossil fuel-fired units 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 

 

551 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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CO2 Emission Performance Rate and Goal Computation TSD for 

CPP Final Rule provides analysis and explains the 

adjustment that the EPA made to the state-level 2012 data 

for Alaska, Idaho, Maine, Montana, Oregon, South Dakota, 

and Washington to better reflect fossil generation in an 

average year over a 1990-2012 baseline. The EPA agrees with 

commenters that using a 2010-2012 baseline would not 

address the concern as 2011 was also an outlier year 

relative to historical snow-pack and hydro generation. 

2) Extended unit outages due to maintenance. 

Generally, because of the regional-level approach to 

calculate performance rates, the EPA does not believe that 

unit-level variations in operation influence the regional 

average performance rates reflecting BSER purposes. For 

instance, as some units ramp down, and others ramp up to 

replace their load at the regional level, total fossil 

generation changes little due to these 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 a state if it 

chooses to use a rate-based or mass-based statewide goal. 

Even though the EPA is calculating performance rates that 
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it believes are not affected by this type of unit-level 

variation, it still evaluated the possible impacts it may 

have when reconstituting state goals in the next section. 

The EPA examined units nationwide with 2012 outages to 

determine where unit-level outages might yield a 

significant difference in state goal computation. When 

applying this test to all of the units informing the 

computation of the BSER, emission performance rates, and 

statewide goals, the EPA determined that the only unit with 

a 2012 outage that 1) significantly impacted its output 

relative to preceding and subsequent years, and 2) 

significantly impacted its state’s goal was the Sherco unit 

3 in Minnesota. The EPA therefore adjusted this unit’s 2012 

fossil steam generation upwards (and made a corresponding 

adjustment to lower NGCC generation assumed to occur in 

Minnesota in the adjusted baseline data) to reflect a more 

representative year for the state in which this 900 MW unit 

operates. 

3) Many commenters also noted that because the EPA uses annual 

data, 2012 was not representative for units coming online 

part way through the year. The EPA relies on annual data, 

so if a unit is underrepresented in a certain part of the 

year because it is not yet online, then another unit is 
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likely over-represented as it is operating more than it 

otherwise would when the second unit commences operation. 

Therefore, the resulting annual generation level may be 

considered to be representative and there is not 

necessarily a need for any adjustment. 

However, the EPA recognizes that the over-represented and 

under-represented units do not necessarily fall within the 

same state, and therefore this potential difference in the 

state location of the affected units could have an impact 

when estimating appropriate statewide goals. To address 

this comment, the EPA adjusted the 2012 generation data for 

fossil units coming online during 2012 to represent an 

average annual operating level for that type of unit, which 

resulted in increased baseline emissions and generation 

assumed for those units beyond their reported partial-year 

operations in 2012. Conceptually, the assumption of fullyear 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 determine the state location 

of such units. As a result, this data adjustment marginally 
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inflates the total generation and emissions in the 2012 

baseline beyond 2012 reported levels. 

In summary, this final rule continues to rely on the latest 

reported 2012 data as the foundation for quantifying the BSER. 

However, the EPA has made limited adjustments to the baseline to 

address some of the relevant concerns raised by commenters. 

4. Equation 

This section describes the equation used to determine the 

emission performance rates for fossil steam and NGCC units. More 

detailed information regarding rate computation, including 

example calculations, can be found in the CO2 Emission 

Performance Rate and Goal Computation TSD for Final Rule, which 

is available in the docket for this action. The following 

paragraphs summarize the steps taken to adjust baseline data to 

reflect the building block potential and derive performance 

rates. The next section explains how these nationwide 

performance rates are reconstituted into a statewide goal metric 

similar to proposal if a state desires to use a statewide goal 

as a mechanism for demonstrating compliance at the aggregate 

state level in a state plan instead of applying the emission 

performance rates to its affected EGUs. The EPA has translated 

these technology-specific emission rates into statewide goals 

that states may use to demonstrate aggregate compliance in 
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section VII of the preamble and the CO2 Emission Performance Rate 

and Goal Computation TSD for Final Rule. 

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 all affected EGUs that had commenced operation prior to 

2012.552 The EPA made limited changes to the historical unitlevel data based on comments received at proposal. For each 

state and region, the agency aggregated the 2012 operating data 

for all coal-fired steam EGUs as one group, all oil- and gasfired steam EGUs as a second group, and all NGCC units as a 

third group. The EPA adjusted these state values upwards in a 

limited number of instances to reflect the hydro and unit outage 

 

552 EGUs whose capacity or fossil fuel combustion were 

insufficient to qualify them as “likely affected” EGUs were not 

included in the goal computations. Most simple cycle combustion 

turbines 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 

the final rule. 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. As described in the state plan section of 

the preamble, units may still quantify and convert UTO (i.e., 

taking credit for waste heat capture) when demonstrating 

compliance. See the applicability criteria described in Section 

IV.C above. 
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concerns raised in comments and described above. Per the 

adjustments 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. 

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 generation and emissions using their capacity. The EPA 

assumed a 55 percent capacity factor for under construction NGCC 

units and a 60 percent capacity factor for under construction 

fossil steam units, which are consistent with the values and 

methodology the EPA proposed for under construction units. These 

values are based on the average capacity factors for units in 

these technology classes coming online in the 2007-2011 time 

frame. 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 
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EPA used the national baseline average for that technology. This 

is similar to the adjustment made at proposal, 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 to derive an adjusted historic baseline 

total for each state and region. 

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 2012 data to the 

state level, the final rule further aggregates it to the 

regional level prior to building block application. The regions 

reflect the Eastern, Western, and Texas Interconnections. The 

shift to a regional framework was based on comments suggesting 

that the EPA would better capture the interstate impacts of the 

building blocks under a regional structure. The basis for the 

regions are defined and discussed in Section V.A.3). 

Step three (presentation of source category baseline 

emission rates). As discussed in the beginning of this section, 
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the EPA took a technology-specific approach to setting 

standards. 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 applies 

the building blocks at the regional level maintaining a separate 

fossil steam rate and a NGCC rate for each region. The starting 

point for calculating the technology-specific emission 

performance rates is the adjusted baseline regional emission 

rate and generation value for fossil steam and NGCC separately. 

Step four (application of building block one). The total CO2

emissions amount for the coal-fired steam EGU group 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 is 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 averages together 

the region’s baseline oil- and natural gas-fired steam rate with 

its building block 1 adjusted coal steam rate to get a fossil 

steam rate post building block 1.553 

 

553 Building block 1 analysis acknowledges some variation in heat 

rate improvement potential at different units. The 
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 Step five (application of building block three). At 

proposal, the EPA incorporated incremental RE MWhs 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 three 

in a manner more analogous to building block two treatment where 

the MWhs identified for the building block replace baseline 

fossil MWhs levels (and corresponding emissions) on a one-to-one 

basis. The EPA is adopting this replacement methodology for 

building block three in the final rule consistent with comments 

noting that such a computational procedure better reflects the 

reduction potential of that building block. 

In this revised equation, part of building block three 

incremental RE potential and all of building block two 

incremental NGCC potential are ultimately applied to replace 

higher-emitting fossil steam generation and emissions. Because 

incremental RE potential is lower emitting than building block 

two incremental NGCC potential, building block three’s 

replacement impact is calculated first when determining the 

impact on technology rates for each affected fossil-fuel 

category. Calculating building block three replacement impacts 

 

implementation of this building block simply reflects a heat 

rate improvement on average across a region’s coal fleet, not 

necessarily a heat rate improvement at every unit. 
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first is also consistent with comments the EPA received noting 

that this step is necessary to ensure that the EPA can 

subsequently calculate the full potential of building block 2 

potential to replace higher-emitting fossil steam. 

First, building block three replacement potential is 

identified for each region to arrive at a total amount of 

incremental zero-emitting generation hours available to replace 

fossil generation in the region. Next, the incremental zero 

emitting generation hours are assumed to replace generation and 

associated emissions from each of the fossil steam and NGCC 

fleets in the region on a pro-rata basis in the following 

manner. The EPA determines the percent of fossil steam 

generation and the percent of NGCC generation of total affected 

fossil generation in each region’s baseline. It then assigns 

those percentages of the incremental zero-emitting MWhs to each 

of those technology source categories.554 The incremental zeroemitting generation assigned to that technology replaces the 

respective fossil generation from that technology’s baseline 

value. The numerator (emissions) is also effectively reduced at 

 

554 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 historically and 30 percent from NGCC units – then 

70 MWhs of the incremental zero-emitting generation are assumed 

to replace baseline fossil steam generation and 30 MWhs are 

assumed to replace baseline NGCC generation. 
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this stage by the amount of average CO2 emissions associated with 

the replaced fossil generation. 

Step six (application of building block two). If the 

remaining generation level for the NGCC fleet in a region, 

taking into account the previous steps replacement of NGCC 

generation, is less than 75 percent of the fleet’s potential 

summertime generating capacity (75 percent capacity factor), 

then the NGCC generation in the region is assumed to increase to 

levels equal to the lesser of 1) its potential at 75 percent 

capacity factor or 2) a generation level above which there is no 

longer fossil steam generation within the same region to 

replace. In other words, the regional NGCC capacity factor is 

only assumed to reach 75 percent if there is higher-emitting 

fossil steam generation that it could replace after step five. 

The incremental NGCC generation replaces fossil steam generation 

in the region on a one-for-one basis. This replacement reduces 

the amount of fossil steam generation in the fossil steam rate 

denominator as well as the amount of fossil steam emissions in 

the numerator.555

As explained in step seven, when determining the final 

fossil steam rate, this incremental NGCC generation and 

 

555 For purposes of determining the emission performance rates 

for fossil steam, incremental NGCC generation is defined as the 

final adjusted NGCC generation level minus the baseline level. 
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corresponding emissions are assigned to the fossil steam rate 

denominator and numerator respectively in a manner analogous to 

building block three. That is, the incremental NGCC generation 

that is replacing fossil steam generation is included in the 

fossil steam denominator and the incremental emissions are 

included in the numerator.556 

Step seven (arriving at the adjusted technology-specific 

rates for the region). In step four, the EPA calculated a 

regional fossil steam emission rate that reflected the building 

block 1 heat rate improvement. In steps five and six, it 

calculated an amount of remaining fossil steam generation and 

NGCC generation after building blocks two and three were 

applied. Step seven quantifies the 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 reflecting the implementation of 

all three building blocks. 

 

556 Inclusion of the generation and emissions from incremental 

NGCC in the fossil steam rate is necessary to reflect the 

emission reductions associated with building block two. An 

unadjusted fossil steam rate on its own would not reflect any 

change as generation and emissions from replaced fossil steam 

would decrease proportionally when building block two is 

applied. 
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For the numerator of the fossil steam rate, the EPA 

multiplies the remaining fossil steam generation (post Step six) 

by the fossil steam rate reflecting the heat rate improvement 

from building block 1 (Step four). It then adds in the emissions 

associated with incremental NGCC generation from building block 

2 (step six) by multiplying the incremental NGCC generation 

(delta between the baseline NGCC generation level and post step 

six NGCC generation) by the baseline NGCC rate for that region. 

This constitutes the numerator of the fossil steam emission 

rate. 

For the fossil steam denominator, the EPA adds the 

remaining fossil steam generation (post step six), the 

incremental NGCC generation, and the amount of zero emitting 

building block three MWhs assigned to replace fossil steam 

generation in the region (step five). Dividing the fossil steam 

numerator described above into this fossil steam denominator 

results in a regional adjusted fossil steam rate reflecting the 

three building blocks. 

For the NGCC uniform technology rate, the EPA calculates a 

numerator in a similar manner. First, it takes the remaining 

NGCC generation (post step six) and multiplies it by the 

regional baseline NGCC rate to calculate the total emissions in 

the numerator. For the denominator, the EPA added the remaining 
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NGCC generation (post step six) to the amount of zero-emitting 

building block three generation assigned to that technology in 

step five. Dividing the emissions into this total generation 

value (inclusive of the RE generation assigned to replace NGCC) 

provides a regional adjusted NGCC rate. 

Step eight (determining the nationwide technology-specific 

emission performance rate). Following step seven, the resulting 

adjusted fossil steam rates and NGCC rates for each region are 

evaluated. The highest (least stringent) emission rate for each 

technology category is identified among the three regions. This 

becomes the nationwide emission performance rate for that 

technology class. 

Finally, the EPA repeats steps four through eight for each 

year 2022-2030. The resulting annual rates vary because the 

amount of building block two and three potential in each year 

varies. The rates for years 2022-2029 are 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 
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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. 

 The CO2 emission performance rates described in Table 8 

above are relevant for the continental U.S. jurisdictions. 

Affected EGUs in Alaska, Hawaii, Guam, and Puerto Rico are not 
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subject to these rates. Because the continental U.S. (CONUS) 

BSER relies on a region-wide determination of potential 

reductions, the non-continental United States jurisdictions with 

affected EGUs are not subject to this regional BSER framework. 

For these non-CONUS jurisdictions, the EPA developed a blended 

emission rate similar to proposal (but incorporating updated 

building block assumptions) and described in the technical 

support document entitled “CO2 Emission Performance Rate and Goal 

Computation TSD for Final Rule,” which is available in the 

docket. 

VII. Statewide CO2 Emission Performance Goals 

A. Overview 

In section VI of this preamble, the EPA provides the 

methodology for computing source category-specific CO2 emission 

performance rates, based on the BSER. In the June 2014 proposal, 

the EPA proposed a set of state-specific emission rate-based CO2

goals (in lbs of CO2 per MWh of electricity generated). In 

addition, the EPA issued 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 
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(i.e., goals expressed in terms of total tons of CO2 per year 

from affected EGUs), as long as the translated goal achieves the 

equivalent in stringency. 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 (79 FR 

67406) and technical support document (Docket ID no.: EPA-HQOAR-2013-0602-22187) to further clarify potential methods for 

the translation to a mass-based equivalent. The outreach 

provided 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, the 

EPA received informed substantive comments for the EPA to 

consider for the final rule. 

Numerous commenters encouraged the EPA to allow states the 

maximum possible degree of flexibility in developing plans for 

their affected EGUs, whether a mass-based or rate-based CO2 goal 

is chosen. States and other stakeholders supported the option to 

translate rate-based goals to mass-based goals in state plans 

and requested a simple and transparent method for determining 
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mass-based statewide CO2 goals that are equivalent to statewide 

rate-based CO2 goals. We received substantive 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. The EPA is providing massbased statewide goals in this final rule in place of having 

states determine the mass values themselves. Using the comments 

received, the EPA is providing a straightforward and translation 

methodology from the CO2 emission performance rates to yield 

statewide rate-based and mass-based CO2 emission performance 

goals; section VIII below discusses mechanisms for states to 

plan for and demonstrate achievement of the statewide CO2

emission performance goals. 

The EPA is aggregating the performance rates discussed in 

section VI into statewide CO2 emission performance goals for each 

state to facilitate states’ efforts to formulate compliance 

plans encompassing maximum flexibilities. This statewide goal is 

not a compliance requirement, but rather an option that the 

state may choose to use to demonstrate that its affected fleet 

is complying with the technology-specific emission performance 

rates on average if a state chooses not to apply the performance 
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rates to its affected EGUs directly. As discussed further in 

section VIII on state plans, the states, in turn, are charged 

with setting specific emission standards for the EGUs in their 

respective jurisdictions such that the EGUs operating under 

those standards together satisfy the requirements of the final 

emission guidelines as expressed by the emission performance 

rates or statewide emission performance goals. 

B. Reconstituting Statewide CO2 Emission Performance Goals from 

the Source Category-Specific Emission Performance Rates 

In order to provide states flexibility for planning 

purposes, the EPA is providing a state-specific averaging of the 

technology-specific emission performance rates to determine a 

statewide goal similar to the state goal metric issued at 

proposal. While the emission performance rates reflect the 

standards of performance based on the BSER, the statewide goals 

reflect one approach through which states may choose to adopt 

and implement those standards. 

The EPA derived the statewide rate-based CO2 emission 

performance goals by multiplying the fossil steam emission 

performance rate by the baseline fossil steam generation in a 

state and multiplying the NGCC performance rate by the baseline 

NGCC generation in a state. The resulting emissions for fossil 

steam and NGCC are then added together for each state. This 
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emission total is divided into that state’s baseline generation 

values from affected units in order to develop a state’s ratebased CO2 emission performance goal for 2030. This blended rate 

reflects the aggregate emission rate a state may expect to 

achieve when its fleet is meeting its technology-specific 

emission performance rates. 

This step is repeated for years 2022-2029 using the 

emission performance rates calculated for each of those years in 

the previous section. The resulting state emission rates for 

each year 2022-2029 are then averaged together to determine the 

state’s interim rate-based emission performance goal. This 

results in interim and final statewide goal values unique to 

each state’s historical blend of fossil steam and NGCC 

generation. 

The EPA also 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 three and two 

year increments are not regulatory guidelines or equivalents for 

interim goals, but rather illustrative of a type of gradual 

reduction compliance strategy that states may use to reach their 

interim and final statewide goals. 
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The EPA is providing equivalent mass-based statewide CO2

emission performance goals for each state, which are provided 

below. The mass-based statewide CO2 emission performance goals 

are based on the tonnage totals from the numerator of the 

statewide rate-based CO2 emission performance goals. These mass 

levels are then adjusted to account for the ability of affected 

EGUs to increase utilization under rate-based compliance by 

engaging in emission reduction strategies that are in excess of 

what is necessary to demonstrate compliance if affected EGUs 

choose to replace their own generation. Due to the nature of the 

emission performance rate methodology, which selects the highest 

regional value for each source category as the CO2 emission 

performance rate, there are cost-effective emission reduction 

opportunities originally quantified under building blocks 2 and 

3 that were not ultimately captured in the emission performance 

rates. The EPA recognizes that these cost-effective 

opportunities are available to affected EGUs in a rate-based 

compliance setting as a means of increasing utilization while 

maintaining the relevant emission performance rate. To afford 

affected EGUs similar compliance flexibility under mass-based 

compliance, the EPA has translated these excess emission 

reduction opportunities (which were quantified at the regional 

level) to a tonnage basis and then incorporated those additional 
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tons into each state’s mass-based goal on the basis of that 

state’s share of 2012 affected EGU generation.557 

The EPA notes that it is the emission performance rates in 

section VI that constitute the application of BSER to the 

affected EGUs and serves as the chief regulatory requirement of 

this rulemaking. The statewide CO2 emission performance goals 

provided here are metrics that states may choose to adopt when 

demonstrating compliance at the state level, and states may 

consider these goals when determining how to set unit-level 

compliance requirements. The EPA believes that the regional 

nature of determining the emission performance rates encompasses 

a large population size and makes it robust against unit-level 

variation and unit-level inventory discrepancies. The EPA does 

acknowledge that state-level rate-based goals or mass-based 

goals may be sensitive to inventory changes within a state’s 

fleet. That is, the EPA used a representative baseline that 

aggregated data for “likely affected” units. However, if 

subsequent applicability review or formal applicability 

determinations change the status of these units as of 2012 in 

regards to their inclusion or exclusion in the state’s 

 

557 For more detail on the translation methodology, please refer 

to the technical support document, CO2 Emission Performance Rate 

and Goal Computation TSD for Final Rule, which is available in 

the docket. 
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inventory, the EPA will consider allowing states, via State Plan 

submittal, to adjust their statewide rate or mass goal by up to 

1% if such a change is necessary. 

This adjustment flexibility provision is based on comments 

received at proposal. For example, some stakeholders noted that 

the affected status of particular units was unclear. The EPA 

recognizes that all the necessary data to determine the affected 

status of some units may not be available at this time. As 

stated in the previous section, the EPA does not believe unitlevel variation or inclusion/exclusion disparities between 

baseline inventory and affected units will impact the regionally 

determined emission performance rates discussed in the previous 

section. However, variations in baseline data or inventory may 

have an impact on the state-level rate-based or mass-based goals 

provided in this section. Therefore, the EPA is allowing the 

flexibility for states to demonstrate the need for this type of 

adjustment under the justifications above and utilize an 

adjusted value for compliance purposes when submitting its state 

plan. 

 As described in the previous section, the non-continental 

United States (non-CONUS) jurisdictions with affected sources 

(Alaska, Hawaii, Guam, and Puerto Rico) required a different 

Best System of Emission Reduction framework as the regional 
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nature of deriving emission performance rates was not 

appropriate for their more isolated systems. Therefore, the EPA 

determined bottom-up state goals for these non-CONUS 

jurisdictions based on the same building blocks used for the 

continental United States, but without the regional framework 

component. It then assigned the non-CONUS areas the less 

stringent of their state/jurisdictional specific bottom-up rate 

or the rate resulting from applying the continental technologyspecific emission rates into a non-CONUS jurisdictional goal 

based on that jurisdictions historic mix of fossil steam and 

NGCC generation. This “lesser of” approach is consistent with 

limiting the BSER so that no region or jurisdiction has to do 

more than the region with the least reduction potential. 

Table 9. Statewide558 Rate-Based CO2 Emission Performance Goals 

(Adjusted Output-Weighted-Average Pounds of CO2 Per Net MWh 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 

Alaska 

Arkansas 

Arizona* 

California 

Colorado 

Connecticut 

Delaware 

 

558 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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Florida 

Lands of the 

Fort Mojave 

Tribe 

Georgia 

Guam 

Hawaii 

Iowa 

Idaho 

Illinois 

Indiana 

Kansas 

Kentucky 

Louisiana 

Massachusetts 

Maryland 

Maine 

Michigan 

Minnesota 

Missouri 

Mississippi 

Montana 

Lands of the 

Navajo Nation 

North 

Carolina 

North Dakota 

Nebraska 

New Hampshire 

New Jersey 

New Mexico* 

Nevada 

New York 

Ohio 

Oklahoma 

Oregon 

Pennsylvania 

Puerto Rico 

Rhode Island 

South 

Carolina 

South Dakota 
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Tennessee 

Texas 

Lands of the 

Ute Tribe of 

the Uintah 

and Ouray 

Reservation 

Utah* 

Virginia 

Washington 

Wisconsin 

West Virginia 

Wyoming 

* Excludes EGUs located in Indian country within the state. 

Table 10. Statewide Mass-Based CO2 Emission Performance Goals 

(Adjusted Output-Weighted-Average Tons of CO2 From All Affected 

Fossil Fuel-Fired EGUs) 

State 

 Interim 

Goal 

Final Goal

Alabama 

Alaska 

Arizona* 

Arkansas 

California 

Colorado 

Connecticut 

Delaware 

Florida 

Georgia 

Guam 
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Hawaii 

Idaho 

Illinois 

Indiana 

Iowa 

Kansas 

Kentucky 

Lands of the 

Fort Mojave 

Tribe 

 

Lands of the 

Navajo Nation 

Lands of the 

Ute Tribe of 

the Uintah 

and Ouray 

Reservation 

 

Louisiana 

Maine 

Maryland 

Massachusetts 

Michigan 

Minnesota 

Mississippi 

Missouri 

Montana 

Nebraska 

Nevada 
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New Hampshire 

New Jersey 

New Mexico * 

New York 

North 

Carolina 

 

North Dakota 

Ohio 

Oklahoma 

Oregon 

Pennsylvania 

Rhode Island 

South 

Carolina 

 

South Dakota 

Tennessee 

Texas 

Utah * 

Virginia 

Washington 

West Virginia 

Wisconsin 

Wyoming 
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* Excludes EGUs located in Indian country within the state. 

VIII. State Plans 

A. Overview 

After the EPA establishes the emission guidelines, each 

state559 shall then develop, adopt and submit a state plan under 

CAA section 111(d). Each state’s obligation under section 111(d) 

and under these guidelines is to establish a standard of 

performance for the affected EGUs in its jurisdiction in order 

to implement the BSER. That standard of performance may 

expressly incorporate the CO2 emission performance rates the EPA 

has set forth in these guidelines to express the BSER, or, as an 

alternative, the state may establish standards of performance at 

different levels for different EGUs. As a second alternative, 

the state may adopt measures apart from or in addition to 

standards of performance for its affected EGUs. These guidelines 

include rate-based and mass-based CO2 emission goals for each 

state that represent the equivalent in aggregate of the CO2

emission performance rates applied to the affected EGUs in each 

state; states that adopt either of the two alternative 

approaches – differential standards of performance among their 

 

559 In this section, the term “state” encompasses the 50 states 

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

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

as eligible to develop and implement a CAA section 111(d) plan. 
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affected EGUs or “state measures” - must demonstrate that, in 

the aggregate, the differential standards of performance and/or 

measures they adopt will result in their affected EGUs meeting 

in the aggregate either the states’ respective rate-based CO2

emission goals or mass-based CO2 emission goals. The EPA believes 

that it is appropriate to allow states this significant 

flexibility in both the timing and location of emission 

reductions because CO2 is a global pollutant, and where and when 

the reductions occur is not as significant to the environmental 

outcome as compared to many other conventional pollutants. 

Each state must decide whether to adopt a plan to meet the 

CO2 emission performance rates for affected EGUs – either as 

emission standards for each EGU reflecting the CO2 emission 

performance rates that represent BSER or as emission standards 

differentiated among its affected EGUs, or adopt and implement, 

in the rate-based metric or in the mass-based metric, the CO2

emission goals set forth by the EPA for the state. As already 

stated, the EPA is establishing goals for each state in order to 

ensure both that states and affected EGUs enjoy the maximum 

flexibility and latitude in meeting the requirements of the 

emission guidelines and that the BSER is fully implemented by 

each state. For its plan, a state will be able to choose to 

either impose federally enforceable emission standards that 
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fully meet the emission guidelines directly on affected EGUs 

(the “emission standards” approach) or use a “state measures" 

approach, which would comprise, at least in part, measures 

implemented by the state that are not included as federally 

enforceable components of the plan, with 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 emissions reductions. 

In developing the plan, the state rulemaking process must 

meet the minimum public participation requirements of these 

guidelines, including a public hearing and meaningful engagement 

with all members of the public, including affected communities. 

Within the time period specified in the emission guidelines 

(from as early as August 31, 2016, to as late as August 31, 

2018, depending on whether the state receives an extension), the 

state must submit its final state plan to the EPA. The EPA then 

must determine whether to approve or disapprove the plan. If a 

state does not submit a plan, or if the EPA disapproves a 

state’s plan, then the EPA has the express authority under CAA 

section 111(d) to establish a federal plan for the state. During 

and following implementation of its plan, each state must 

demonstrate to the EPA that its affected EGUs are meeting the 
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interim and final performance requirements included in this 

final rule through monitoring and reporting requirements. 

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

located in its area of Indian country, if the tribe either does 

not submit a CAA section 111(d) plan or does not receive EPA 

approval of a submitted plan, the EPA has the responsibility to 

establish a CAA section 111(d) plan for that area if it 

determines that such a plan is necessary or appropriate to 

protect air quality.560 

This section is organized as follows. First, we discuss the 

state plan performance periods. Second, we describe the types of 

plans that states can submit. Third, we summarize the components 

of an approvable state plan submittal. Fourth, we address the 

process and timing for submittal of state plans and plan 

revisions. Fifth, we address plan implementation and achievement 

of CO2 emission performance rates or state CO2 emission goals for 

affected EGUs, and the consequences if they are not met. Sixth, 

we discuss several additional considerations for states in 

developing and implementing plans, including: accounting for 

emission reduction measures in state plans; treatment of 

interstate effects; requirements for rate-based emission trading 

approaches; evaluation, measurement, and verification (EM&V) 

 

560 See 40 CFR 49.1 to 49.11. 
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criteria for RE and demand-side EE resources used to adjust a CO2

rate; consideration of a facility’s “remaining useful life” and 

“other factors;” and electric reliability. Finally, we note 

certain resources that are available to facilitate state plan 

development and implementation. 

B. State Plan Performance Periods

 This section describes state plan requirements related to 

the timing of achieving the emission guidelines and state plan 

performance periods. A performance period is a period for which 

the final plan submittal must demonstrate that the required CO2

emission performance rates or state CO2 emission goal will be 

met. The EPA received significant and diverse comments on both 

the start date of the interim period and the trajectory of 

compliance over the interim period. After careful consideration 

of those comments, we are finalizing a start date of January 1, 

2022 for the interim period, and three interim step periods. 

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 in 2030. 

Therefore the final rule requires that interim CO2 emission 

performance rates or state CO2 emission goals be met for the 

interim period of 2022-2029, and for the three interim step 

periods (2022-2024, 2025-2027, 2028-2029). The final rule allows 
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states that choose to meet a state CO2 emission goal the 

flexibility to define an alternate trajectory of emission 

performance between 2022 and 2029 to the steps specified in the 

rule. States have the option of meeting goals of the state’s 

choosing for the interim step periods instead of meeting the 

interim step goals provided in the emission guidelines, as long 

as meeting the state-determined interim step goals will still 

result in the interim state CO2 emission goal being met on an 8-

year average or cumulative basis and the 2030 state CO2 emission 

goal is achieved. To be approvable, a state plan submittal must 

demonstrate that the emission performance of affected EGUs will 

meet the interim step CO2 emission performance rates or state CO2

emission interim step goals on average over the 2022-2024, 2025-

2027, and 2028-2029 periods and the final CO2 emission 

performance rates or state CO2 emission goal no later than 2030. 

This relatively long planning and implementation period 

provides states with substantial flexibility regarding methods 

and timing of achieving emission reductions. States may wish to 

make adjustments to their implementation approaches along the 

way, or as conditions change, may need to make adjustments to 

ensure that their plans achieve the CO2 emission performance 

rates or state CO2 emission goals as intended. As a result, the 

agency envisions that the EPA, states and affected EGUs will 
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have an ongoing relationship in the course of implementing this 

program. The EPA believes that timing flexibility in 

implementing measures provides significant benefits that allow 

states to develop plans that will help achieve a number of 

goals, including, but not limited to: reducing cost, addressing 

reliability concerns and addressing concerns about stranded 

assets. 

 The EPA received numerous comments regarding the concept 

of the interim compliance period, including comments supporting 

the flexibility afforded states in developing their plans and 

the timing necessary to meet the 2030 emission requirements. 

Some commenters supported beginning the interim goal program at 

2020. Others stated that the investments necessary to meet the 

proposed 2020 reduction goals are unachievable in that timeframe 

or would place too great a burden on affected EGUs and states. 

Some suggested that the 2020 interim goal step should be 

eliminated in favor of later start dates, including 2022, 2025, 

or other years. Other commenters provided input suggesting that 

states be allowed to establish their own set of interim 

guidelines and thereby control their own glide path toward the 

2030 goal. As discussed in previous sections, based on comments 

received, the EPA has adjusted the start date for the interim 

period to 2022, and is retaining the flexibility for states to 
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establish their own emissions trajectory during the interim 

period. Because of the additional time provided before the 

beginning of the interim plan performance period, the EPA has 

determined that additional assurance that states are making 

progress in implementing the plan between the time of the state 

plan submittal and the beginning of the interim period is 

appropriate. As discussed in detail in section VIII.D, the final 

rule requires that the state plan submittal include a timeline 

with all the programmatic milestone steps the state will take 

between the time of the state plan submittal and 2022 to ensure 

the plan is effective as of 2022. States must submit a report to 

the EPA in 2021 that demonstrates that the state has met the 

programmatic milestone steps that the state indicated it would 

take from the submittal of the final plan through the end of 

2020, and that the state is on track to implement the approved 

state plan as of January 1, 2022. If the EPA approves a state 

plan that includes the required obligation on the state to 

submit this report, and the state either does not submit the 

requisite report by July 1, 2021, or the state submits a report 

demonstrating it has not met the programmatic milestones, the 

EPA’s approval of the state plan will convert to a disapproval. 

Per the requirements of CAA section 111(d), the EPA will develop 

and implement a federal plan in the instance of such 
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disapproval. 

 Many commenters supported providing incentives for states 

to deploy CO2-reducing investments, such as RE and demand-side EE 

measures, as early as possible. The EPA recognizes the value of 

such early actions, and in this final rule is providing states 

with discretion to credit reductions from the activities, 

implemented from 2013 onward, in the context of both mass-based 

and rate-based plans. If a state demonstrates, in its July 1, 

2021 report, that it has implemented such early action measures, 

the EPA will consider its report to be presumptively approvable. 

See sections VIII.C. and VIII.G for a discussion of state plan 

requirements related to incentivizing early action under massbased and rate-based plans, respectively. 

The EPA has based its determination of the BSER on 

reductions that are achievable beginning in 2022. For that 

reason, these guidelines require no reductions to be made by 

affected EGUs prior to 2022 or by other entities in those states 

that adopt a state measures plan. At the same time, the EPA has 

concluded that it is essential to the achievement in a timely 

and cost-effective way of the emissions reductions required to 

meet the CO2 emission performance rates or, in the alternative, 

the state goals, that the states and EGUs are rewarded for 

undertaking investments that yield reductions in the years prior 
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to 2022. Accordingly, state plans must include a mechanism to 

ensure this outcome. 

For purposes of meeting this requirement, a state plan 

would be presumptively approvable if it included provisions 

comprising one of the following elements: 

 A commitment to demonstrating plan performance on the basis 

of averaging its emissions over a 10-year period beginning 

with emissions from its affected EGUs in 2020, factoring in 

the state’s projected business as usual emissions (rates) 

in 2020 and 2021. 

 A mechanism for awarding to affected EGUs allowances or 

credits for reductions that would contribute to the state’s 

achievement of reductions in 2020 and 2021 that are below 

its business as usual projected emissions for each of those 

years, and provided that the state’s emission in 2020 and 

2021 not exceed the state’s projected business as usual 

level. 

Nothing in these provisions would have the effect of 

requiring any particular affected EGU to achieve reductions 

prior to 2022. In addition, states would have the option for 

including in their state plans mechanisms as alternatives to 

those described above for meeting the overall emissions 

reduction requirements for 2020 and 2021, provided that any 
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state submitting a plan that included a mechanism as an 

alternative to the presumptively approvable mechanism(s) 

described above could demonstrate that the alternative would 

achieve the same outcome as the mechanism(s) described above. 

 The EPA is including this state plan requirement for 

several reasons. Chief among them are those offered by 

commenters to the effect that the overall cost of achievement of 

the state goals could be reduced by an approach that granted 

some form of beneficial recognition to emissions reduction 

investments that both occur and yield reductions prior to the 

first date on which the program mandates reductions or imposes 

emissions limitations. 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 periods, the EPA should 

include in the final guidelines provisions that accelerate 

deployment of RE resources, since in so doing the program would 

speed achievement of expected reductions in the cost of those 

technologies commensurate with their accelerated deployment. 

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 
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would apply all requirements for meeting the emission guidelines 

to affected EGUs in the form of federally enforceable emission 

standards,561 which we refer to as an “emission standards” state 

plan type. The second, which we refer to as a “state measures” 

plan type, would allow the CO2 emission performance rates or 

state CO2 emission goals to be achieved in part, or entirely, 

through state measures562 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 during the period that the state 

is relying on state measures. The inclusion of a backstop of 

federally enforceable measures is legally necessary for a state 

to meet the requirements of 111(d), which specifically requires 

a state to submit standards of performance, if the state chooses 

to adopt the state measures plan type. 

 These two types of state plans and their respective 

 

561 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.” 

562 “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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approaches, either of which could be implemented on a singlestate or multi-state basis, allow states to meet the statutory 

requirements of CAA section 111(d) while accommodating the wide 

range of regulatory requirements and other programs that states 

have deployed or will deploy in the electricity sector that 

reduce CO2 emissions from affected EGUs. Further, as described in 

detail below, both types of plans are responsive to comments we 

received from states and other stakeholders. 

 As described below, the EPA believes that each state is 

able to satisfy the requirements of the final emission 

guidelines by implementing a plan that applies all requirements 

to the affected EGUs in the form of federally enforceable 

emission standards that achieve the CO2 emission performance 

rates or applicable state CO2 emission goal. Under the emission 

standards state plan type, the EPA is finalizing three 

approaches for state plans: 

 rate-based emission standards for affected EGUs, which may 

include use of emission trading; 

 mass-based emission standards for affected EGUs, which may 

include use of emission trading; and 

 other emission standards for affected EGUs in the form of a 

rate or mass standard that results from application of 

operational or other standards, such as a limit on total 
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operating hours of an affected EGU over a specified period 

or the retirement of an affected EGU.563 

While the EPA believes that the CO2 emission performance 

rates can be met, or states can achieve their CO2 emission goals, 

through this first type of state plan, which applies federally 

enforceable emission standards to affected EGUs, the agency also 

recognizes that many states have existing or planned programs 

that limit CO2 emissions from affected EGUs or those that replace 

or avoid generation from affected EGUs and result in CO2 emission 

reductions. This includes market-based emission budget trading 

programs that apply to affected EGUs, such as the programs 

implemented by California and the RGGI participating states, as 

well as RE and demand-side EE requirements and programs, such as 

renewable portfolio standards (RPS), energy efficiency resource 

standards (EERS), and utility- and state-administered incentive 

programs for the deployment of RE and demand-side EE 

technologies and practices. The EPA is providing additional 

flexibility to states to accommodate such requirements and 

programs through a “state measures” plan.564

 

563 Both rate-based and mass-based emission standards could be 

implemented by states in different ways, including limits that 

apply to specific affected EGUs and market-based emission 

trading programs. These variants are outlined below. 

564 Note that emission budget trading programs that meet certain 

basic design criteria may also be included in an “emission 

standards” plan, as described below. 
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The state measures plan type is composed of measures 

adopted and implemented by the state that, at least in part, are 

not included as federally enforceable components of the plan, 

but result in achievement of the CO2 emission performance rates 

or the applicable state rate-based or mass-based CO2 emission 

goal. These state measures could apply to affected EGUs and/or 

other entities. In a state measures plan, the state must 

demonstrate how its state measures (in conjunction with any 

federally enforceable emission standards for affected EGUs that 

the state chooses to include as part of the state plan) will 

either meet the CO2 emission performance rates or achieve the 

state CO2 emission goal for affected EGUs. Additionally, the 

state must include in its state plan a “backstop” that will 

apply federally enforceable emission standards to affected EGUs 

sufficient to meet the CO2 emission performance rates or state 

CO2 emission goal, if when being implemented the plan fails to 

achieve the required level of CO2 emission performance during 

specified plan performance periods. These backstop federally 

enforceable emission standards will assure that affected EGUs 

achieve the CO2 emission performance rates or state CO2 emission 

goal per the requirements of CAA section 111(d) if the state 

measures fail to result in the expected level of emission 

performance. 
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In addition to providing states the option of developing an 

emission standards or state measures type plan, the final rule 

makes clear that states can adopt either a rate-based or massbased CO2 emission goal. Further, the EPA notes that for either 

an emission standards plan or a state measures plan, if a state 

chooses the option of meeting a state rate or mass CO2 emission 

goal, the metric chosen for the goal is independent from the 

measures that implementing authorities may adopt to achieve 

them. For example, a state could potentially adopt mass-based 

emission standards and/or other measures and demonstrate that 

its plan will achieve a rate-based CO2 goal. Likewise, a state 

could adopt rate-based emission standards and/or other measures 

and demonstrate that its plan will meet a mass-based CO2 goal. 

2. Summary of comments on state plan approaches 

The EPA received a wide range of comments on the basic plan 

approaches in the proposal. Numerous commenters supported 

providing states with the option of implementing a rate-based or 

mass-based approach. Some commenters expressed concern that a 

rate-based approach would not reduce overall emissions, and 

could actually lead to increased emissions. The EPA does not 

agree with this latter comment, because both approaches would 

result in adequate and appropriate constraints on CO2 emissions. 

As documented in the RIA, a rate-based approach would result in 
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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 

approaches, as described below. 

 The EPA received a mix of comments for and against the 

proposed portfolio approach, in which state requirements and 

other measures that apply to non-EGU entities would be part of a 

state’s federally enforceable state plan. Multiple commenters 

supported the portfolio approach because it would align with 

existing state and utility planning processes in the electric 

power sector, and would maximize state discretion 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 utilityadministered EE programs. Commenters noted that the portfolio 

approach would provide states maximum flexibility to take local 

circumstances, economics and state policy into account when 

developing their plans. 
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 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).565 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. However, the EPA is finalizing the state 

measures plan type, as described below, that would accommodate 

state choices and allow states to rely upon a variety of 

 

565 Legal concerns with the proposed portfolio approach are 

explored in section VIII.C.4.d. 
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measures, as was envisioned under the portfolio approach, in a 

way that meets the statutory requirements of CAA section 111(d). 

3. “Emission standards” state plan approach 

The first type of state plan imposes requirements solely on 

affected EGUs in the form of federally enforceable emission 

standards, which we refer to as an “emission standards” plan. 

This type of state plan, as described below, may consist of 

rate-based emission standards for affected EGUs; mass-based 

emission standards for affected EGUs; and other emission 

standards for affected EGUs in the form of a rate- or mass-based 

emission standard that results from application of an 

operational or other standard. Rate-based and mass-based 

emission standards may incorporate the use of emission trading, 

as described below. The EPA anticipates the use of emission 

trading in state plans, due to the advantages of this 

approach.566

Under this approach, the state plan submittal must 

demonstrate that these federally enforceable emission standards 

for affected EGUs will achieve the state CO2 emission goal or CO2

emission performance rates or the applicable rate-based or massbased state CO2 emission goal. 

 

566 The legal basis for authorizing trading in emission standards 

is discussed in section VIII.C.3.d. 
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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 achieve either the CO2 emission performance rates for 

affected EGUs or the state rate-based CO2 emission goal. To meet 

the CO2 emission performance rates, a plan would establish 

separate rate-based emission standards for affected fossil fuelfired electric utility steam generating units and stationary 

combustion turbines (in lb CO2/MWh) that are equal to or lower 

than the CO2 emission performance rates in the emission 

guidelines. To meet a state rate-based CO2 goal, a plan would 

establish a uniform rate-based emission standard (in lb CO2/MWh) 

that applies to all affected EGUs in the state. This uniform 

emission rate would be equal to or lower than the applicable 

state rate-based CO2 goal specified in the final emission 

guidelines. 
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 Under these two approaches, compliance by affected EGUs 

with the rate-based emission standards in a plan would ensure 

that affected EGUs meet the CO2 emission performance rates in the 

emission guidelines or the state rate-based CO2 goal for affected 

EGUs. No further demonstration would be necessary by the state 

to demonstrate that its plan would achieve the CO2 emission 

performance rates or the state’s rate-based CO2 goal. 

If a state chose, it could instead apply rate-based 

emission standards to individual affected EGUs, or to categories 

of affected EGUs, at a lb CO2/MWh rate that differs from the CO2

emission performance rates or the state’s rate-based CO2 goal. In 

this case, compliance by affected EGUs with their emission 

standards would not necessarily ensure that the collective, 

weighted average CO2 emission rate for these affected EGUs meets 

the CO2 emission performance rates or the state’s rate-based CO2

goal. 

Under this type of approach, the state would be required to 

include a demonstration,567 in the state plan submittal, of how 

its plan would achieve the CO2 emission performance rates or 

applicable state rate-based CO2 goal. This demonstration would 

include a projection of the collective, weighted average CO2 rate 

 

567 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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it anticipates the fleet of affected EGUs would achieve as a 

result of compliance with the emission standards in the plan. 

Once the plan is implemented, if the CO2 emission performance 

rates or applicable state rate-based CO2 goal are not achieved, 

corrective measures would need to be implemented, as described 

in section VIII.F.3. 

Under a rate-based approach, a state may include in its 

plan a number of provisions to facilitate affected EGU 

compliance with the emission standards. First, a state may 

encourage (or require) EGUs to undertake actions to reduce CO2

emissions at the source level, such as heat rate improvements or 

fuel switching. Second, a state may implement a market-based 

emission trading program, which enables EGUs to generate and 

procure Emission Rate Credits (ERCs), a tradable compliance unit 

representing one MWh of electric generation (or reduced 

electricity use) with zero associated CO2 emissions. These ERCs 

would be issued by the administering state regulatory body. 

The state may issue ERCs to affected EGUs that emit below a 

specified CO2 emission rate, as well as for measures that provide 

substitute generation for affected EGUs or avoid the need for 

generation from affected EGUs. These ERCs may then be used to 

adjust the reported CO2 emission rate of an affected EGU when 

demonstrating compliance with a rate-based emission standard. 
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For each submitted ERC, one MWh is added to the denominator of 

the reported CO2 emission rate, resulting in a lower adjusted CO2

emission rate. 

Eligible measures that may generate ERCs, as well as the 

accounting method for adjusting a CO2 emission rate, are 

discussed in section VIII.G.1. Requirements for rate-based 

emission trading approaches are discussed in section VIII.G.3. 

Quantification and verification requirements for RE and demandside EE programs and projects are discussed in section VIII.G.4. 

ERCs issued in 2022 or a subsequent year may be carried 

forward (or “banked”) and used for demonstrating compliance in a 

future year.568 For example, an ERC issued for a MWh of RE 

generation that occurs in 2022 may be applied to adjust a CO2

emission rate in 2023 or future years without limitation. ERCs 

may be banked from the interim plan performance period to the 

final plan performance period. 

Banking provides a number of advantages while ensuring that 

the same output-weighted average CO2 emission rates of the 

interim and final state CO2 goals are achieved over the course of 

a state plan. Banking provisions have been used extensively in 

 

568 States may also consider issuing ERCs representing MWh 

generation or savings that occur from 2013-2021. Requirements 

for including this type of a provision in a state plan are 

discussed in section VIII.G.1.b.(2). 
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rate-based environmental programs and mass-based emission budget 

trading programs.569 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.570 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 emission rate credits or 

emission allowances may be used for compliance in the future. 

 

569 Banking under mass-based emission budget trading programs, 

and the rationale for banking provisions, is addressed below in 

section VIII.C.3.b.(2)(a).

570 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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Linking short-term and long-term economic incentives, which 

allows owners or operators of affected EGUs and other market 

participants to assess both short-term and long-term incentives 

when making decisions about compliance approaches or emission 

reduction investments, reduces long-term compliance costs for 

affected EGUs and consumer price impacts. In addition, the 

increased temporal flexibility provided by banking would further 

help address potential electric reliability concerns, as banked 

ERCs can be used to meet emission standard requirements for an 

affected EGU. 

Rate-based emission standards included in a state plan must 

be quantifiable, verifiable, enforceable, non-duplicative and 

permanent. These requirements are described in more detail at 

section VIII.D.2. Requirements for rate-based emission trading 

programs that are included in a state plan are discussed in 

detail in section VIII.G.3. This discussion includes 

requirements for the issuance of ERCs. 

b. Mass-based approach. The second “emission standards” approach 

a state may elect to use is mass-based emission standards 

applied to affected EGUs. Under this approach, the plan would 

include federally enforceable emission standards on mass CO2

emissions from affected EGUs that are designed to achieve the 

mass-based CO2 goal for a state’s affected EGUs (see section 
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VII).571 

 Under a mass-based approach, a state could require that 

individual affected EGUs meet a specified mass emission 

standard. Alternatively, a state could choose to implement a 

market-based emission budget trading program. The EPA envisions 

that the latter option is most likely to be exercised by states 

seeking to implement a mass-based emission standard approach, as 

it would maximize compliance flexibility for affected EGUs and 

enable the state to meet its mass goal in the most economically 

efficient manner possible. 

(1) Mass-based emission standard applied to individual affected 

EGUs. One pathway a state could take to achieve its mass-based 

CO2 goal would be to apply mass-based emission standards to 

individual affected EGUs, in the form of a limit on total 

allowable CO2 emissions. These emission standards would be 

designed such that total allowable CO2 emissions from all 

affected EGUs in a state are equal to or less than the state’s 

 

571 The EPA notes that states could also apply mass emission 

limits on affected EGUs that are designed to achieve a state’s 

rate-based goal. Under this type of approach, the state would be 

required to include a demonstration, the state plan submittal, 

of how its plan would achieve the goal. This demonstration would 

include a projection of the collective, weighted average CO2 rate 

it anticipates the fleet of affected EGUs would achieve as a 

result of the mass emission limits placed on affected EGUs. Once 

the plan is implemented, if the rate goal is not achieved for 

the fleet of affected EGUs as a whole, corrective measures would 

need to be implemented, as described in section VIII.F.3. 
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mass-based CO2 goal. The individual affected EGUs would be 

required to emit at or below their mass-based standard to 

demonstrate compliance. Under this approach, individual affected 

EGUs would be required to undertake source-specific measures to 

assure their CO2 emissions do not exceed their assigned emission 

limit. Affected EGU compliance with the emission standards 

prescribed under this type of mass-based approach would ensure 

that the affected EGUs in a state achieve the state’s mass-based 

CO2 goal. 

 Mass-based emission standards included in a state plan 

must be quantifiable, verifiable, enforceable, non-duplicative 

and permanent. These requirements are described in more detail 

at section VIII.D.2. 

(2) Mass-based emission standard with a market-based emission 

budget trading program. A second pathway a state could take to 

achieve its mass-based CO2 goal would be to implement a marketbased emission budget trading program. This type of program 

provides maximum compliance flexibility to affected EGUs, and as 

a result, may be attractive to states who choose to implement a 

mass-based approach in their state plan. 

An emission budget trading program establishes a combined 

emission standard for a group of emission sources in the form of 

an emission budget. Emission allowances are issued in an amount 
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up to the established emission budget.572 Allowances may be 

distributed to affected emission sources through a number of 

different methods, including direct allocation to affected 

sources or auction. These allowances can be traded among 

affected sources and other parties. The emission standard 

applied to individual emission sources is a requirement to 

surrender emission allowances equal to reported emissions, with 

each allowance representing one ton of CO2. 

(a) Emission budget trading programs that ensure achievement of 

a state CO2 goal. Under the emission standards plan type, a massbased emission budget trading program must be designed such that 

compliance by affected EGUs would achieve the state mass-based 

CO2 goal. Under this approach, a state plan would establish 

emission budgets for affected EGUs during the interim and final 

plan performance periods that are equal to or lower than the 

applicable state mass-based CO2 goals specified in section VII. 

Compliance periods for affected EGUs would also be aligned with 

the interim and final plan performance periods. This approach 

would limit total CO2 emissions from affected EGUs during the 

interim and final plan performance periods to an amount equal to 

or less than the state’s mass-based CO2 goal. 

 

572 An emission allowance represents a limited authorization to 

emit, typically denominated in one short ton or metric ton of 

emissions. 
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 Under this approach, compliance by affected EGUs with the 

mass-based emission standards in a plan would ensure that the 

state achieves its mass-based CO2 goal for affected EGUs. No 

further demonstration would be necessary by the state to 

demonstrate that its plan would achieve the state’s mass-based 

CO2 goal. 

For this type of plan, where the emission budget is equal 

to or less than the state mass CO2 goal,573 the EPA would assess 

achievement of the state goal based on compliance by affected 

EGUs with the mass-based emission standards, rather than 

reported CO2 emissions by affected EGUs during the interim plan 

performance periods and final plan performance periods. This 

approach would allow for allowance banking between performance 

periods, including the interim and final performance periods 

outlined in this final rule. This is a typical design element 

for emission budget trading programs addressing GHG emissions. 

Allowing allowance banking across plan performance periods, 

including from the interim period to the final period, provides 

a number of advantages while ensuring that the same cumulative 

emission reductions are achieved over the course of a state 

plan. Emission budget trading programs with unlimited allowance 

 

573 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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banking limit cumulative tonnage emissions over the period in 

which they are applied. As a result, common program design is to 

allow allowance banking without limitation, unless there is an 

environmental reason for not doing so (e.g., for criteria 

pollutants where timing of emissions is important). As discussed 

in section VIII.C.3.a above, addressing banking under rate-based 

emission trading programs, this is because banking reduces the 

cost of attaining the requirements of the program. In addition, 

the increased temporal flexibility provided by allowance banking 

would further help address potential electric reliability 

concerns, as banked allowances can be used to meet emission 

limit requirements for an affected EGU.

(b) Addressing emission budget trading programs with broader 

source coverage and other flexibilities. As described in section 

VIII.C.3.b(2)(a) above, under the emission standards plan type, 

a mass-based emission budget trading program must be designed 

such that compliance by affected EGUs would achieve the state 

mass-based CO2 goal. However, emission budget trading programs, 

including those currently implemented by California and the RGGI 

participating states, include a number of different design 

elements. If a state chose, it could apply mass-based emission 

standards in the form of an emission budget trading program that 

differs in design from that outlined in section VIII.C.3.b(2)(a) 
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above. However, these types of emission budget trading programs 

must be submitted as a state measure, rather than incorporated 

as federally enforceable emission standards, as described below 

in section VIII.C.4.c. 

(c) State plan provisions required for a mass-based emission 

budget trading program approach. For a mass-based emission 

trading program approach, the state plan would include as its 

federally enforceable emission standards requirements that 

specify the emission budget and related compliance requirements 

and mechanisms. These requirements would include: CO2 emission 

monitoring, reporting, and recordkeeping requirements for 

affected EGUs; provisions for state allocation of allowances; 

provisions for tracking of allowances, from issuance through 

submission for compliance; and the process for affected EGUs to 

demonstrate compliance (allowance “true-up” with reported CO2

emissions). Mass-based emission standards that take the form of 

an emission budget trading program must be quantifiable, 

verifiable, enforceable, non-duplicative and permanent. These 

requirements are described in more detail at section VIII.D.2. 

(d) Considerations for mass-based emission budget trading 

programs. The EPA notes that while an emission budget trading 

program included in an emission standards plan must be designed 

to achieve a state mass-based CO2 goal, states have wide 
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discretion in the design of such programs, provided the emission 

standards included in the plan are quantifiable, verifiable, 

enforceable, non-duplicative, and permanent. 

 A key example is state discretion in the CO2 allowance 

allocation methods included in the program.574 This includes the 

methods used to distribute CO2 allowances and the parties to 

which allowances are distributed. For example, if a state chose, 

it could include CO2 allowance allocation provisions that provide 

incentives for certain types of complementary activities, such 

as RE generation, that help achieve the overall CO2 emission 

limit for affected EGUs established under the program. States 

could also use CO2 allowance allocation provisions to provide 

incentives for early action, such as RE generation or demandside EE savings that occur prior to the beginning of the interim 

plan performance period in 2022. For example, a state could 

include CO2 allowance allocation provisions where CO2 allowances 

are distributed to RE generators based on MWh of RE generation 

that occurs prior to 2022. Such provisions might be addressed 

through a finite set-aside of CO2 allowances that are available 

for allocation under these provisions. 

c. Other EGU emission standard approaches. As discussed in 

 

574 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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further detail in section VIII.D.d.(3) regarding the legal 

issues and statutory language of CAA section 111(h), the EPA is 

finalizing that design, equipment, work practice, and 

operational standards cannot be considered as “standards of 

performance” for this final rule. However, the third “emission 

standards” approach a state may elect to use is emission 

standards for affected EGUs that result in reduced CO2 lb/MWh or 

total tons of CO2 affected EGUs because of operational or other 

standards. Under this approach, the state would include in its 

state plan an emission standard that is the rate or mass 

standard that results from the applicable operational or other 

standard. For example, a state might choose to recognize that an 

individual affected EGU has plans to retire, and those plans 

could be codified in the state plan by adopting an emission 

standard of 0 CO2 lb/MWh, or 0 total tons, as of a certain date. 

The state would thus include in the state plan an emission 

standard of 0 CO2 lb/MWh or 0 total tons for that affected EGU 

that applies after a specified date. Under a mass-based 

approach, the state could also include an emission standard 

(e.g., a mass limit) that reflects the result of a limit on an 

affected EGU’s total operating hours over a specified period. 

 An approvable plan could apply such emission standards to a 

subset of affected EGUs or all affected EGUs. As with any plan, 
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the state would need to demonstrate that the plan would achieve 

the required level of emission performance for affected EGUs, in 

either CO2 lb/MWh or total tons of CO2. A plan could also apply 

such emission standards to a subset of affected EGUs in the 

state while applying emission standards to the remainder of 

affected EGUs in the state. For example, a plan might include an 

emission standard of 0 CO2 lb/MWh reflecting a retirement mandate 

for one or more affected EGUs in a state and apply a rate-based 

emission standard equal to the CO2 emission performance rate or 

state’s rate-based CO2 emission goal to the remainder of affected 

EGUs. 

As with the other two approaches, emission standards under 

this approach must be quantifiable, verifiable, enforceable, 

non-duplicative and permanent. These requirements are described 

in more detail at section VIII.D.2. 

d. Legal basis for emission standards approach. The emission 

standards approach is consistent with the requirements of CAA 

section 111(d). If a state simply adopts the CO2 emission 

performance rates, then the corresponding rate-based emission 

standards in the state plan establish standards of performance 

for affected EGUs as required under section 111(d)(1)(A). 

Similarly, if a state chooses to achieve the rate-based CO2

emission goal through rate-based emission standards, or to 
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achieve the mass-based CO2 emission goal through mass-based 

emission standards, 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). 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 

emission trading. Thus, the credit and allowance trading that is 

allowed under the emission standards approach is consistent with 

the statutory requirement that the plan establish standards of 

performance. 

e. Legal basis for emissions trading in state plans. There are 

three legal issues 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 
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scheme. Third, we give a similar explanation of the EPA’s 

interpretation of the same phrase in the context of a mass-based 

allowance trading scheme. 

(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 the use of emissions trading in this 

rule. 

For purposes of this legal discussion, in the case of an 

emission limitation expressed as an emission rate, trading takes 

the form of buying or selling ERCs that an affected EGU may 

generate if its actual emission rate is lower than its allowed 

emission rate. 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 
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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 requirement to retire tradable allowances qualify as 

a “standard for emissions.” The term “standard” is not defined, 

but its everyday meaning is a rule or requirement,575 which, 

under either a Chevron step 1 or step 2 analysis, 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.”576 In addition, in the 1995 Municipal 

Solid Waste (MSW) Combustor rule the EPA authorized emission 

trading by sources.577

 

575 E.g., “Something that is set up and established by authority 

as a rule for the measure of quantity, weight, value, or 

quality.” Webster’s Third New International Dictionary 2223 

(1993). 

576 70 FR 28606, 28616-17 (May 18, 2005). 

577 60 FR 65387, 6540/2 (Dec. 19, 1995).
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It should be noted that CAA section 302(l) includes another 

definition of “standard of performance,” which is “a requirement 

of continuous emission reduction, including any requirement 

relating to the operation or maintenance of a source to assure 

continuous emission reduction.” As described above, section 

111(d) contains its own, more specific definition of “standard 

of performance,” which a tradable emission rate or mass limit 

satisfies. Whether or not section 302(l) applies in light of 

section 111(d)’s more specific definition, a tradable emission 

rate or mass limit also meets section 302(l)’s requirements. A 

tradable emission rate applies continuously in that the source 

is under a continuous obligation to meet its emission rate, and 

that is so regardless of the averaging time, e.g., a rate that 

must be met on an annual basis. Similarly, an allowance 

requirement applies continuously in that the source is 

continuously under an obligation to assure that at the 

appropriate time, it will have enough allowances to cover its 

emissions. In this respect, a tradable emission rate or 

allowance 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 
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tradable emission rate or allowance program is appropriate for 

CO2 emissions, the air pollutant covered by this rule, because 

CO2 emissions do not cause short-term health or welfare dangers; 

rather, their effects occur over a longer term. 

(2) In our final rule, we are prescribing certain specific 

requirements for trading systems for ERCs in a rate-based 

approach. These specific requirements are in addition to the 

generic requirements for any state plan (see section VIII.D.2.d 

below for the legal basis for the generic components for state 

plans) and are intended to ensure the integrity of the ERC 

trading system. The integrity of the trading system is key to 

ensuring that a state plan provides for implementation and 

enforcement of the standards of performance. 

Here, we explain our interpretation of the phrase “provides 

for implementation and enforcement of [the] standards of 

performance” in the context of the integrity of a trading system 

for ERCs under a rate-based approach. As described previously, 

the EPA has legal concerns regarding whether 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 

does not run afoul of these legal concerns, as neither the 

requirements of section 111(d) nor of the federally enforceable 

state plan extend to non-EGU generators or third-party verifiers 
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of such compliance units. In the Legal Memorandum we also 

discuss specific legal issues regarding EM&V criteria, EM&V 

plans, and Projection guidance. 

(3) In our final rule, we are prescribing certain specific 

requirements for trading systems for allowances in a mass-based 

approach. These specific requirements are in addition to the 

generic requirements for any state plan (see section VIII.D.2.d 

below for the legal basis for the generic requirements for state 

plans) and are intended to ensure the integrity of the allowance 

trading system. The integrity of the trading system is key to 

ensuring that a state plan provides for implementation and 

enforcement of the standards of performance. 

Our interpretation of the phrase “provides for 

implementation and enforcement of [the] standards of 

performance” in the context of the integrity of a trading system 

for allowances under a mass-based approach is further explained 

in the Legal Memorandum. 

4. “State measures” state plan type 

 The second type of state plan is what we refer to as a 

“state measures” plan. As previously discussed, the EPA believes 

states will be able to submit state plans under the emission 

standards plan type, and its respective approaches, and achieve 

the CO2 emission performance rates or rate-based or mass-based 
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state CO2 goals by imposing federally enforceable requirements on 

affected EGUs. Upon further consideration of the requirements of 

CAA section 111(d), and in consideration of the comments we 

received on the proposed portfolio approach and the variation of 

the state commitments approach, the EPA is finalizing the state 

measures plan type in addition to the emission standards plan 

type. The EPA believes the state measures plan type will provide 

states with additional flexibility to accommodate existing or 

planned programs that involve measures implemented by the state, 

or by entities other than affected EGUs, that result in avoided 

generation and CO2 emission reductions at affected EGUs. The EPA 

believes this second state plan type will afford states with 

appropriate flexibility while meeting the statutory requirements 

of CAA section 111(d). 

Measures implemented under the state measures plan type 

could include RE and demand-side EE requirements and deployment 

programs. This type of plan could align with existing state 

resource planning in the electricity sector, including RE and 

demand-side EE investments by state-regulated electric 

utilities. The state measures plan type also can accommodate 

emission budget trading programs that address a broader set of 

emission sources than just affected EGUs subject to CAA section 

111(d), such as the programs currently implemented by California 
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and the RGGI participating states in the Northeast and MidAtlantic. 

 This plan type would allow the state to implement a suite 

of state measures that are adopted, implemented, and enforceable 

only under state law, and rely upon such measures578 in achieving 

the required level of CO2 emission performance from affected 

EGUs. The state measures under this plan type could be measures 

involving entities other than affected EGUs, or a combination of 

such measures with emission standards for affected EGUs, so long 

as the state demonstrates that such measures will result in 

achievement of the CO2 emission performance rates or applicable 

state CO2 emission goal. The EPA notes that under this plan type, 

a state could also choose to include any emission standards for 

affected EGUs as federally enforceable requirements in the state 

plan to be implemented alongside or in conjunction with state 

measures the state would implement and enforce. 

 For a state measures plan to be approvable, it must include 

a demonstration of how the measures, whether state measures or 

state measures in conjunction with any federally enforceable 

emission standards, will achieve the CO2 emission performance 

 

578 “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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rates or state CO2 emission goal for affected EGUs. However, 

because the state measures would not be federally enforceable 

emission standards, the plan must also include a “backstop” of 

federally enforceable emission standards, in order for the state 

measures plan type to satisfy the requirement of CAA section 

111(d) that a state submit standards of performance for affected 

EGUs. This backstop would impose federally enforceable emission 

standards on the state’s affected EGUs in the case that the 

state measures fail to achieve the required CO2 emission 

performance rates or CO2 emission goal. The backstop, discussed 

further below, would assure that the CO2 emission performance 

rates or state CO2 emission goals are fully achieved by affected 

EGUs in the form of federally enforceable emission standards. 

a. Requirements for state measures under a state measures plan.

Under the state measures plan type, state measures must be 

satisfactorily described in the supporting material for a state 

plan submittal. The supporting material would need to 

demonstrate that the state measures meet the same integrity 

elements that would apply to federally enforceable emission 

standards. Specifically, the state plan submittal must 

demonstrate that the state measures are quantifiable, 

verifiable, enforceable, non-duplicative and permanent. These 

requirements are described in more detail at section VIII.D.2. 
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 The EPA would assess the overall approvability of a plan 

using a state measures plan type based, in part, on the state’s 

satisfactory demonstration that the state measures, in 

conjunction with any federally enforceable emission standards on 

the affected EGUs that might be included in the plan, would 

result in the state plan’s achievement of either the CO2 emission 

performance rates or the CO2 emission goal for the state’s 

affected EGUs. This includes a demonstration of adequate legal 

authority and funding to implement the state plan and any 

associated measures. The EPA’s determination that such a plan is 

satisfactory would be based in part on whether the state 

measures are adequately described in the supporting 

documentation and the plan submittal demonstrates that the state 

measures are quantifiable, verifiable, enforceable, nonduplicative and permanent as described above. This is necessary 

for the EPA to ensure that the results achieved through the plan 

are quantifiable and verifiable, and to assess whether the state 

measures are anticipated to achieve the CO2 emission performance 

rates or state CO2 emission goal for affected EGUs. 

 EPA’s evaluation of the approvability of a state measures 

plan would also include assessing whether the backstop comprised 

of federally enforceable emission standards for the state’s 

affected EGUs, in the case that the state measures fail to 
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achieve the required CO2 emission performance rates or CO2

emission goal, would assure that the CO2 emission performance 

rates or state CO2 emission goals are fully achieved by affected 

EGUs. The trigger for the backstop must also satisfactorily 

provide for the implementation of the backstop emission 

standards. 

b. Considerations for the state measures plan type backstop. As 

further discussed in section VIII.C.4.c, the EPA believes a 

backstop, composed of federally enforceable emission standards 

for the affected EGUs that are sufficient to achieve the state 

CO2 emission goal or meet the CO2 emission performance rates in 

the event that state measures do not result in the anticipated 

CO2 emission performance, is necessary for the state measures 

plan type to meet the requirements of CAA section 111(d). The 

state plan must specify the backstop that would apply federally 

enforceable emission standards to the affected EGUs if the state 

measures plan does not achieve the anticipated level of CO2

emission performance by affected EGUs. The state plan must 

include promulgated regulations (or other requirements) that 

fully specify these emission standard requirements, which must 

be quantifiable, verifiable, enforceable, non-duplicative and 

permanent. These requirements are described in more detail at 

section VIII.D.2. 
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 These federally enforceable emission standards must be 

designed such that compliance by affected EGUs with the emission 

standards would achieve the state’s rate-based or mass-based 

interim and final goals for affected EGUs, or the CO2 emission 

performance rates. The emission standards must specify CO2

emission performance levels (in rate or mass) that would apply 

for the interim plan performance period (including specifying 

levels for each of the interim step 1 through step 3 periods) 

and the final two-year plan performance periods.579 

 The backstop emission standards must also make up for any 

shortfall in CO2 emission performance during a prior plan 

performance period that led to triggering of the backstop, which 

is discussed further below. The state may effectuate this by 

submitting, along with the backstop emission standards, 

provisions to adjust the emission standards to account for any 

prior emission performance shortfall, such that no modification 

of the emission standards is necessary in order to address the 

emission performance shortfall. Examples of such provisions are 

discussed below. The state may also address the requirement to 

make up for any shortfall in CO2 emission performance by 

 

579 This includes the level of emission performance during the 

interim plan periods 2022-2024, 2025-2027 and 2028-2029, as well 

as the performance level that would be achieved during every 

subsequent 2-year final plan performance period (2030-2031, and 

subsequent two-year periods). 
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submitting as part of the final plan backstop emission standards 

that assure affected EGUs would achieve the state’s rate-based 

or mass-based interim and final CO2 goals for affected EGUs, or 

the CO2 emission performance rates, and then later submit 

appropriate revisions to the backstop emission standards 

adjusting for the shortfall through the state plan revision 

process. 

 The federally enforceable backstop emission standards for 

affected EGUs could be designed by the state to take the form of 

rate-based emission standards, mass-based emission standards, or 

other emission standards, as described above for emission 

standards plan types. Alternatively, the backstop emission 

standards could be based on the federal plan, using the federal 

plan regulations as a model rule. 

 The state measures plan must also specify the trigger and 

conditions under which the backstop federally enforceable 

emission standards would apply. The trigger and attendant 

conditions for deployment of the backstop would address the CAA 

section 111(d) requirement that states submit a program for the 

implementation of standards of performance. The state measures 

plan must specify the level of emission performance that will be 

achieved by affected EGUs as a result of implementation of the 

state measures plan during the interim and final plan 
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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 two-year final plan performance 

period (2030-2031, and subsequent two-year periods). If actual 

CO2 emission performance by affected EGUs exceeds the specified 

level of emission performance by 10 percent or more during a 

specified interim or final plan performance period, the state 

measures plan must require that the backstop federally 

enforceable emission standards would take effect and be applied 

to affected EGUs. In the event of such an exceedance, the state 

measures plan must provide that such emission standards would be 

effective within 18 months of the deadline for the state’s 

submission of its periodic report to the EPA on state plan 

implementation and performance, as described in section 

VIII.D.2.c.580 While the state is taking any necessary 

administrative and technical actions to implement the backstop 

emission standards regulations that were promulgated as part of 

the state plan, state measures must remain in effect and 

continue to be implemented by the state until such time as the 

backstop emission standards are effective. 

 

580 States may choose to establish an effective date for backstop 

emission standards that is sooner than 18 months. 
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 As described above, the federally enforceable emission 

standards for affected EGUs must be designed to ensure that the 

CO2 emission performance rates or a state’s interim and final CO2

goals are achieved. This includes specifying CO2 emission 

performance levels (in rate or mass) during the interim and 

final plan performance periods, as well as inclusion of 

provisions to automatically adjust those emission performance 

levels as appropriate to make up for any CO2 emission performance 

shortfall during a prior plan performance period that led to 

triggering of the backstop. 

 For example, assume a plan identified a mass-based CO2 

standard for affected EGUs of 100 million tons during the 

interim step 1 performance period (2022-2024), 90 million tons 

during the interim step 2 performance period (2025-2027), and 80 

million tons during the interim step 3 performance period (2028-

2029. Over the entire interim plan performance period (2022-

2029), the interim mass-based CO2 goal is cumulative emissions of 

270 million tons. Assume that CO2 emissions from affected EGUs in 

the interim step 1 period were actually 115 million tons, 

triggering implementation of the backstop. In this instance, the 

mass-based standard for affected EGUs implemented as part of the 

backstop during subsequent plan performance periods would need 

to ensure that cumulative CO2 emissions during the 2022-2029 
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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.581 The emission standards 

included in the plan must specify calculations for how such 

adjustments will be made. 

 A similar approach could be applied for a rate-based plan. 

For example, assume the identified emission performance level 

during the interim step 1 performance period is 1,000 lb CO2/MWh 

and the emission performance level during the interim step 2 

performance period is 900 lb CO2/MWh. Further assume that 

affected EGUs actually emit at a rate of 1,150 lb CO2 during the 

interim step 1 plan performance period. The backstop could apply 

an emission standard of 750 lb CO2/MWh during the subsequent 

interim step 2 plan performance period (rather than the 900 lb 

CO2/MWh specified in the emission standard) to make up the 

emission performance shortfall that led to triggering of the 

backstop. 

 

581 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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c. Addressing emission budget trading programs under the state 

measures plan type. As described in section VIII.C.3.b(2)(a) 

above, under the emission standards plan type, a mass-based 

emission budget trading program must be designed such that 

compliance by affected EGUs would achieve the state mass-based 

CO2 goal. However, emission budget trading programs, including 

those currently implemented by California and the RGGI 

participating states, include a number of different design 

elements. If a state chose, it could apply such mass-based 

emission standards, in the form of an emission budget trading 

program that differs in design from that outlined in section 

VIII.C.3.b(2)(a) above. However, these types of emission budget 

trading programs must be submitted as a state measure, rather 

than incorporated as federally enforceable emission standards, 

as described below. 

 Such programs could include a number of different design 

elements. This includes broader program scope, where a program 

includes other emission sources beyond affected EGUs subject to 

CAA section 111(d), such as industrial sources. Programs might 

also include design elements that make allowances available in 

addition to the established emission budget. This includes 

project-based offset allowances or credits from GHG emission 

reduction projects outside the covered sector and cost 
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containment reserve provisions that make additional allowances 

available at specified allowance prices.582

 In the case where an emission budget trading program 

contains such elements, compliance by affected EGUs with the 

mass-based emission standards would not necessarily ensure that 

CO2 emissions from affected EGUs do not exceed the state’s massbased CO2 goal. 

The EPA has determined that such emission budget trading 

programs, which may include broader scope of covered emission 

sources and the types of provisions described above that 

functionally expand an established emission budget, may be 

implemented as part of a state measures plan. A description of 

the state measures plan type and related requirements is 

provided in section VIII.C.4. 

Under this type of approach, the state would be required to 

include a demonstration,583 in its state plan submittal, of how 

its plan would achieve the state mass-based CO2 goal. This 

 

582 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. 

583 A demonstration of how a plan will achieve a state’s ratebased or mass-based CO2 goal is one of the required plan 

components, as described in section VIII.D.2. 
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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.4.b.584 

d. Legal basis for state measures plan type. 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 

 

584 Achievement of the state mass-based CO2 goal would be 

determined based solely on stack CO2 emissions from affected 

EGUs. Where a state program includes the ability of an affected 

emission source to use GHG offsets to meet a portion of its 

allowance compliance obligation, no “credit” is applied to 

reported CO2 emissions by the affected EGU. The use of offset 

allowances or credits in such programs merely allows an affected 

EGU to emit a ton of CO2 in the amount of submitted offset 

allowances or credits. In all cases, there is no adjustment 

applied to reported stack emissions of CO2 from an affected EGU 

when determining compliance with its emission limit. 
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implementation and enforcement of such standards of 

performance.” Section 111(d)(2)(A) indicates that the EPA must 

approve the state plan if it is “satisfactory.” 

Under the state measures plan, a 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. Section 111(d) unambiguously allows a state to submit 

a plan that establishes standards of performance for certain 

sources, but does not mandate when such standards of performance 

must be in effect or implemented in order to meet applicable 

compliance deadlines. The EPA believes because the statute does 

not provide such a mandate, the EPA therefore has the discretion 

under section 111(d) to determine the effective date of 

standards of performance submitted under state plans to meet the 

requirements of this rule. Where the statute is silent, the EPA 

has authority to provide a reasonable interpretation, under the 

U.S. Supreme Court’s decision in Chevron U.S.A. Inc. v. NRDC,

467 U.S. 837, 842–844 (1984). The EPA’s interpretation is that 

for states that submit state plans establishing standards of 

performance under section 111(d), the effective date of such 

standards of performance may be later in time, perhaps 

indefinitely, for a number of reasons and under certain 

conditions. The Legal Memorandum discusses in more detail why 
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the EPA believes it is reasonable to defer the effective date 

for standards of performance for affected EGUs as long as 

affected EGU CO2 emissions are projected to achieve, and do 

achieve, the requisite state goal. 

Section 111(d)(2)(B) also requires a state to submit a 

program that provides for the implementation and enforcement of 

the applicable standards of performance. Under the state 

measures approach, this requirement regarding implementation is 

satisfied 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 by 

the state submitting standards of performance, in the form of 

the backstop, for inclusion as part of the federally enforceable 

state plan. 
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The state measures plan is a variation of the proposed 

portfolio approach in that both plan types allow the state to 

rely upon measures that impose requirements on sources other 

than affected EGUs in meeting the CO2 emission performance rates 

or requisite state CO2 emission performance goal. The state 

measures plan type differs from the proposed portfolio approach, 

however, in that the measures involving entities other than 

affected EGUs are not included as part of the federally 

enforceable 111(d) state plan, but the state may rely upon such 

measures that have the effect of reducing CO2 emissions from 

affected EGUs as a matter of state law. The EPA took comment on 

the proposed portfolio approach and the utilization of measures 

on entities other than affected EGUs in meeting the requirements 

of the emission guidelines and CAA section 111(d), and is 

finalizing the state measures plan type upon careful 

consideration of statutory requirements and comments received. 

On May 20, 2015, the Ninth Circuit Court of Appeals issued 

a decision in Committee for a Better Arvin et al. v. US EPA et 

al., Nos. 11-73924 and 12-71332, that, at first glance, might be 

thought to conflict with the state measures approach. The court 

held that the EPA violated the Clean Air Act by approving a 

California state implementation plan (SIP) which relied on 

emission reductions from state-only mobile source standards 
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(“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 Act, which states that SIPs “shall include” 

the emission limitations and other control measures on which a 

state relies to comply with the Act. The court then stated that 

the EPA’s action was also inconsistent with the structure of the 

Act. The EPA has the primary responsibility to protect the 

nation’s air quality, but in the court’s view, the EPA itself 

would be unable to enforce the state-only standards. In 

addition, the court stated that the EPA’s action was 

inconsistent with citizens’ right to enforce SIP provisions 

under section 304. 

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), does not specifically say that 

every emission reduction measure must be “included” in the state 

plan and be made federally enforceable. We interpret the state 

measures approach to satisfy these requirements by establishing 

a backstop that is the standard of performance and providing for 

its implementation and enforcement through the federal 
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enforceability of the trigger and backstop. 

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 

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. 

e. Legal concerns with proposed portfolio approach. The EPA is 

not finalizing the portfolio approach that was included in the 

proposed rulemaking, 79 FR 34830, 34902 (June 18, 2014). In the 

proposal, the EPA noted that the portfolio approach raised legal 

questions. 79 FR 34830, 34902-03. After reviewing comments, the 

EPA agrees with commenters that legal questions remain as to 
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whether measures that impose federally enforceable requirements 

on entities other than affected EGUs either constitute 

“standards of performance” or “provide[] for the implementation 

and enforcement of . . . standards of performance” under CAA 

section 111(d)(1). In addition, shortly after publication of the 

proposed rulemaking, the U.S. Supreme Court issued the UARG

decision, which cautions against new extensions of CAA 

jurisdiction to large segments of the economy, and raises 

additional questions as to whether entities other than affected 

EGUs may be included in section 111(d) plans and thereby subject 

to CAA enforcement authorities. Utility Air Regulatory Group v. 

EPA, 134 S. Ct. 2427 (2014) (“UARG v. EPA”) 

 The state measures plan type the EPA is finalizing is a 

logical outgrowth of the comments received on the proposed 

portfolio approach. As previously explained, legal questions 

remain as to whether federally enforceable state plans under 

section 111(d) can include measures that impose requirements on 

sources other than affected EGUs. However, a number of 

commenters and stakeholders expressed robust support for the 

ability to rely on measures and programs that do not impose 

requirements on affected EGUs themselves. The EPA is reasonably 

interpreting 111(d) as authorizing the state measures plan type, 

and believes this plan type is also responsive to, and 
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accommodating of, states and stakeholders who have expressed the 

importance of being able to rely upon various measures that have 

the effect of resulting in CO2 reductions from affected EGUs. 

5. Multi-state plans 

 The EPA views the ability of a state to implement an 

individual plan or a multi-state plan as a significant 

flexibility that allows a state to tailor implementation of its 

plan to state policy objectives and circumstances. The EPA sees 

particular value in multi-state plans, which allow states to 

implement a plan in a coordinated fashion with other states. 

Such approaches can lead to more efficient implementation, lower 

compliance costs for affected EGUs and lower impacts on 

electricity ratepayers. Coordinated approaches also will help 

states identify and address any potential electric reliability 

impacts when developing plans. 

 The EPA received broad support in comments for allowing 

states to implement multi-state plan approaches, and has made 

multiple changes in the final rule to address many suggestions 

outlining different approaches states may want to take. These 

changes are intended to provide streamlined approaches for 

multi-state coordination while maintaining transparency and 

assuring that the CO2 emission performance rates or state CO2

emission goals are achieved. 
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 The EPA is finalizing two approaches that allow states to 

coordinate implementation in order to meet the emission 

guidelines.585

 First, states may meet the requirements of the emission 

guidelines and CAA section 111(d) by submitting multi-state 

plans that address the affected EGUs in a group of states. The 

EPA is finalizing the proposed approach by which multiple states 

aggregate their rate or mass CO2 goals and submit a plan that 

will achieve a joint CO2 emission goal for the fleet of affected 

EGUs located within those states. 

 Second, the EPA is also finalizing another approach, in 

response to comments received on the proposed rule. This 

approach enables states to retain their individual state goals 

for affected EGUs and submit individual plans, but to coordinate 

plan implementation with other states through the interstate 

transfer of ERCs or emission allowances. This approach 

facilitates interstate emission trading without requiring states 

to submit joint plans.586 

 

585 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. 

586 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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 States have the option to implement this second approach in 

different ways, as discussed in section VIII.C.5.c. These 

different implementation options allow states to tailor their 

implementation of linked emission trading programs, based on 

state policy preferences, as well as economic and other 

considerations. These different options provide varying levels 

of state control over emission trading system partners and 

require varying levels of coordination in the course of state 

plan development. 

 In response to comments, the EPA is also further clarifying 

how multi-state plans with a joint goal for affected EGUs may be 

implemented. The EPA is clarifying that states may participate 

in more than one multi-state plan, if necessary, for example, to 

address affected EGUs in states that are served by more than one 

ISO or RTO. The EPA is further clarifying that a subset of 

affected EGUs in a state may participate in a multi-state plan. 

These clarifications are discussed in section VIII.C.5.d. 

a. Summary of comments on multi-state plans. Multiple commenters 

supported the EPA’s proposed approach that allows states to 

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 
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incentives that a state would have to aggregate its goal with 

other states that have different goals. 

 The EPA notes that there are multiple incentives for states 

to collaborate by implementing a multi-state plan to meet an 

aggregated joint goal, regardless of the specific level of their 

individual goals, because states share grid regions and impacts 

from plan implementation will be regional in nature. Further, 

multiple analyses, including those by ISOs and RTOs, indicate 

that regional approaches could achieve state goals at lesser 

cost than individual state plan approaches. However, the EPA 

also recognizes the value in allowing for collaboration where 

states retain individual goals. These approaches could provide 

some of the benefits of a joint goal while reducing the 

negotiations among states necessary to develop a multi-state 

plan with a joint goal. As a result, the EPA has finalized the 

additional approaches described above in section VIII.C.5 to 

provide for coordination while maintaining individual goals. 

These approaches would allow for interstate transfer of ERCs or 

emission allowances while retaining individual state goals. 

 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 
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reliability. 

 The EPA agrees with these comments, and notes that it 

encouraged such approaches in the proposal. While the EPA is not 

requiring states to join and/or form regional market-based 

programs, we note that such programs can be helpful for many 

reasons, including features that support reliability. Marketbased programs allow greater flexibility for affected EGUs both 

in the short-term and long-term. Under a market-based program, 

affected EGUs have the ability to obtain sufficient allowances 

or credits to cover their emissions in order to comply with 

their emission limits. Additionally, we continue to encourage 

states to cooperate regionally. Regional cooperation in planning 

and reliability assessments is an important tool to meeting 

system needs in the most cost-effective, efficient, and reliable 

way. 

b. Multistate coordination through a joint emission goal. 

Multiple states may submit a multi-state plan that achieves an 

aggregated joint CO2 emission goal for the affected EGUs in the 

participating states.587 The joint emission goal approach is 

 

587 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 
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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.588 

 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 

 

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. 

588 This is necessary because if the joint goal is not achieved 

during a plan performance period, different remedies would apply 

under an emission standards plan and a state measures plan. 

Under an emission standards plan, corrective measures would 

apply. Under a state measures plan, the federally enforceable 

backstop emission standards would be triggered. 
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the participating states, in cumulative tons of CO2, derived by 

summing the individual mass-based CO2 emission goals of the 

participating states. 

 Such plans could include emission standards in the form of 

a multi-state rate-based or mass-based emission trading 

program.589 Alternatively, states could submit a multi-state plan 

using a state measures approach.590 Both approaches could provide 

for implementation of a multi-state rate-based or mass-based 

emission trading program. 

c. Multi-state coordination among states retaining individual 

state goals. States that do not wish to pursue a joint CO2

emission goal with other states may pursue a second pathway to 

multi-state collaboration. States may submit plans that will 

meet an individual state goal for affected EGUs, but include 

implementation in coordination with other state plans by 

 

589 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. 

590 Under this approach, a state measure could include, if a 

state chose, a multi-state emission trading program that is 

enforceable at the state level. 
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providing for the interstate transfer of ERCs or CO2 allowances, 

depending on whether the state is implementing a rate-based or 

mass-based emission trading program. This form of coordinated 

implementation may occur under both an “emission standards” type 

of plan and a “state measures” type of plan, where states are 

implementing rate-based or mass-based emission trading 

programs.591

 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,592 through either a joint tracking system, 

interoperable tracking systems, or an EPA-administered tracking 

system.593 

 

591 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. 

592 Referred to in different programs as “surrender,” 

“retirement,” or “cancellation.” 

593 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 
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 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.594 However, the EPA 

would also assess linkages with other state plans, to ensure 

that the joint tracking system or interoperable tracking systems 

used to implement rate-based or mass-based emission trading 

programs across states are properly designed with necessary 

components, systems, and procedures to maintain the integrity of 

the linked emission trading programs. 

(1) Multi-state coordination: rate-based emission trading 

programs. Individual rate-based state plans may provide for the 

interstate transfer of ERCs, which would enable an ERC issued by 

one state to be used for compliance by an affected EGU with a 

rate-based emission standard in another state. Such plans would 

include regulatory provisions in each state’s emission standard 

 

conducting an initial scoping assessment of tracking system 

support needs and functionality.

594 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 subsection VIII.C.5.c.(2)(c). 
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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.595

 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.596

 States could implement these linkages among state plans 

with rate-based emission trading systems through three different 

applied implementation approaches: (1) plans that are “ready-

 

595 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 subsection VIII.G.3. 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. 

596 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). 
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for-interstate-trading;” (2) plans that include specified 

bilateral or multilateral linkages; and (3) plans that provide 

for joint ERC issuance among states with materially consistent 

regulations. These approaches are summarized below: 

 Ready-for-interstate-trading plans: A state plan recognizes 

ERCs issued by any state with an EPA-approved plan that 

also uses a specified EPA-approved597 or EPA-administered 

tracking system. Plans are approved individually. A state 

plan need not designate the individual states by name from 

which it would accept issued ERCs. States can join such a 

coordinated approach over time, without the need for plan 

revisions. 

 Specified bilateral linkage: States recognize ERCs issued 

by named partner states. Partner states must demonstrate 

that they use a shared tracking system, interoperable 

tracking systems, or an EPA-administered tracking system. 

Plans are approved individually, including review of the 

shared tracking system or interoperable tracking systems. 

 Joint ERC issuance: States implement materially consistent 

 

597 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 

subsection VIII.C.5.c.(1). 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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rate-based emission trading program regulations and share a 

tracking system. States coordinate their review of 

submissions for ERC issuance598 and their issuance of ERCs 

to the shared tracking system. Issued ERCs are recognized 

as usable for compliance in all states using the shared 

tracking system. Plans are approved individually, including 

review of the shared tracking system. 

 These implementation approaches are designed to streamline 

the process for linking emission trading programs, avoid or 

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.599 

 

598 This refers to eligibility applications and monitoring and 

verification reports, which are required submittals for nonaffected EGU entities seeking the issuance of ERCs. Where 

affected EGUs are issued ERCs for emission performance below a 

specified CO2 emission rate, these ERCs are issued by the 

individual state in which they are subject to a rate-based 

emission standard. Requirements for ERC issuance are discussed 

in subsection VIII.G.3. 

599 The EPA also notes that individual state plans may utilize RE 

and demand-side EE (and other eligible measures), that occur in 

other states, as described in section VIII.G.1 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 
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(2) Multi-state coordination: mass-based emission trading 

programs. An individual state may provide for the use of CO2

allowances issued by another state(s) for compliance with the 

mass-based emission standards in its plan. This type of state 

plan would include regulatory provisions that enable affected 

EGUs to use allowances issued in other states for compliance 

under the state’s emission budget trading program. This type of 

state plan must also indicate how CO2 allowances will be tracked 

from issuance through use for compliance, through either a joint 

tracking system, interoperable tracking systems, or use of an 

EPA-administered tracking system.600 

 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. 

 

implementation of rate-based plans across states while retaining 

individual rate-based state goals. 

600 The emission standards in each individual state plan must 

include regulatory provisions that address the issuance of CO2

allowances and tracking of CO2 allowances from issuance through 

use for compliance, as described in subsection 

VIII.C.3.b.(2)(c). The description here addresses how those 

regulatory provisions will be implemented through the use of a 

joint tracking system, interoperable tracking systems, or an 

EPA-administered tracking system. 
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 Interstate allowance linkages would not affect the 

approvability of each state’s individual plan. However, 

different considerations apply for the approvability of an 

individual plan with such links, based on whether the emission 

budget trading program in the plan applies only to affected EGUs 

or includes other emission sources. These considerations are 

discussed in section VIII.B.5.c.(2)(a) below. 

 Under the first “ready-for-interstate-trading” 

implementation approach, a state would indicate in its state 

plan that its emission budget trading program will be 

administered using an EPA-approved (or EPA-administered) 

emission and allowance tracking system.601 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 

 

601 The EPA would designate tracking systems that it has 

determined adequately address the integrity elements necessary 

for the issuance and tracking of emission allowances, as 

described in subsection VIII.C.5.c.(2). Under this approach, a 

state could include in its plan such a designated tracking 

system, which has already been reviewed by the EPA. 
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emission budget trading system will use a specified EPA-approved 

tracking system. The state would also indicate in the regulatory 

provisions for its emission budget trading program that it would 

recognize as usable for compliance any emission allowance issued 

by any other state with an EPA-approved state plan that also 

uses the specified EPA-approved tracking system. 

 States could also adopt such a collaborative emission 

trading approach over time (through appropriate state plan 

revisions if the plan is not already structured as ready-forinterstate-trading), without requiring all of the existing 

participating states to revise their EPA-approved plans. 

 Under the second implementation approach, a state could 

specify the other states from which it would recognize issued 

emission allowances as usable for compliance with its emission 

budget trading program. The state would indicate in the 

regulatory provisions for its emission budget trading program 

that emission allowances issued in other identified partner 

states may be used by affected EGUs for compliance. Such plans 

must indicate how allowances will be tracked from issuance 

through use for compliance, through either a joint tracking 

system, interoperable tracking systems, or EPA-administered 

tracking system. The EPA would assess the design and 

functionality of this tracking system(s) when reviewing 
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individual submitted state plans. 

 Under this approach, states could also join such a 

collaborative emission trading approach over time. However, all 

participating states would need to revise their EPA-approved 

plans. If the expanded linkage is among previously approved 

plans with mass-based emission standards, approval of the plan 

revision would be limited to assessing the functionality of the 

shared tracking system or interoperable tracking systems in 

order to maintain the integrity of the linked programs.602 

(a) Considerations for linked emission budget trading programs. 

For individually submitted plans, interstate emission allowance 

linkages would not affect the approvability of each state’s 

plan. However, approvability of an individual linked plan would 

differ based on the structure of the emission budget trading 

program included in the plan. These differences for plan 

approvability address distinctions among programs that include 

only affected EGUs and programs that cover a broader set of 

emission sources. Differences in approval criteria are necessary 

to ensure that each individual state plan demonstrates it will 

 

602 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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achieve a state’s mass-based CO2 emission goal for affected EGUs. 

The accounting applied to individual plans to assess whether a 

state achieves its mass-based CO2 goal will also differ, based on 

whether an emission budget trading program includes only 

affected EGUs or a broader set of emission sources. These 

considerations are addressed below, for both types of emission 

budget trading programs. 

(i) Links among emission budget trading programs that only 

include affected EGUs. Where the emission budget trading 

programs in each plan apply only to affected EGUs subject to CAA 

section 111(d), and include compliance timeframes that align 

with the interim and final plan performance periods, both plans 

would functionally be meeting an aggregated multi-state massbased goal, but without formally aggregating the goal. CO2

emissions from affected EGUs in both states could not exceed the 

total combined CO2 emission budgets under the emission standards 

in the two states. A net “import” of CO2 allowances from one 

state would mean that allowable CO2 emissions in the other net 

“exporting” state are less than that state’s established 

emission budget. On a multi-state basis, CO2 emissions from 

affected EGUs could not exceed the sum of the states’ emission 

budgets. 

 Under this approach, if the emission budget for the mass-
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based emission standard in each plan is equal to or lower than 

the state’s mass-based CO2 goal, compliance by affected EGUs with 

the mass emission standard in a state603 would ensure that 

cumulatively the mass CO2 goals of the linked states are 

achieved. As a result, achievement of an individual state’s mass 

CO2 goal would be assessed by the EPA based on compliance by 

affected EGUs with the mass-based emission standards in the 

state plan, rather than reported CO2 emissions by affected EGUs 

in the state.604

 The same accounting approach will apply for such plans in 

all cases, even if the state is linked to another state emission 

budget trading program that includes a broader set of emission 

sources, as described below. In all cases, where a state plan 

includes an emission budget trading program that applies only to 

affected EGUs, and includes compliance timeframes that align 

with plan performance periods, achievement of a state mass CO2

goal will be assessed by the EPA based on whether affected EGUs 

comply with the mass-based emission standard, rather than 

 

603 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. 

604 This approach is warranted because under such linked 

programs, CO2 emissions from affected EGUs in one state that 

exceed a state’s mass CO2 goal would be accompanied by CO2

emissions from affected EGUs in another linked sate that are 

below that state’s mass CO2 goal. 
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reported CO2 emissions from affected EGUs. 

(ii) Links with emission budget trading programs that include a 

broader set of emission sources. State plans may include 

emission budget trading programs that include affected EGUs as 

well as other non-affected emission sources.605 

 Generally, as described in section VIII.C.3-4 above, such 

plans must demonstrate that the mass-based CO2 goal for affected 

EGUs in a state will be achieved, as a result of implementation 

of the emission budget trading program.606 Where such a program 

is linked with other programs, the state plan must include a 

demonstration that the mass-based CO2 goal will be achieved, 

considering the emission allowance links with other programs. 

The EPA, in determining the approvability of each state’s plan 

under this approach, would evaluate the linkages between plans. 

Specifically, the EPA would evaluate whether the linkages would 

enable the EGUs in each participating state to meet the state’s 

applicable mass-based CO2 goal. 

 

605 This may apply under both an emission standards plan and a 

state measures plan. 

606 Under a program that applies to affected EGUs and other 

emission sources, compliance by affected EGUs with the emission 

standard – a requirement to surrender emission allowances equal 

to reported emissions – will not assure that a state’s CO2 mass 

goal is achieved. As a result, a further demonstration is 

required in the plan that compliance by affected EGUs with the 

program will result in CO2 emissions from affected EGUs that are 

at or below a state’s CO2 mass goal. 
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 During plan implementation, the EPA would assess whether 

the affected EGUs in a state achieved the state’s mass-based CO2

goal as follows. Reported CO2 emissions from affected EGUs under 

such plans must be at or below a state’s mass-based CO2 emission 

goal during an identified plan performance period, with the 

following state accounting adjustments for net “import” and net 

“export” of CO2 allowances: 

 Net “imports” of CO2 allowances: Reported CO2 emissions from 

affected EGUs in a state may exceed the state CO2 mass goal 

during an identified plan performance period in the amount 

of an adjustment for the net “imported” CO2 allowances 

during the plan performance period. The adjustment 

represents the CO2 emissions (in tons) equal to the number 

of net “imported” CO2 allowances.607 Under this adjustment, 

such allowances must be issued by a state with an emission 

budget trading program that only applies to affected EGUs. 

Net “imports” of allowances are determined through review 

of tracking system compliance accounts. 

 Net “exports” of CO2 allowances: Reported CO2 emissions from 

affected EGUs in a state during an identified plan 

performance period must be equal to or less than the CO2

 

607 Net “imports” and “exports” of CO2 allowances are defined and 

explained below. 
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mass goal minus an adjustment for the “exported” CO2

allowances during the plan performance period. The 

adjustment represents CO2 emissions (in tons) equal to the 

number of net “exported” CO2 allowances. Net “exports” of 

allowances are determined through review of tracking system 

compliance accounts. 

 Where CO2 emissions from affected EGUs exceed these levels 

(based on reported CO2 emissions with applied plus or minus 

adjustments for net CO2 allowance “imports” or “exports”) by 10 

percent or more, a state would be considered to not have met its 

CO2 mass goal during an identified plan performance period. As a 

result, under a state measures state plan, implementation of the 

backstop federally enforceable emission standards for affected 

EGUs in the state plan would be triggered. 

 A net transfer of CO2 allowances during a plan performance 

period represents the net number of CO2 allowances (issued by a 

respective state) that are transferred from the compliance 

accounts of affected EGUs in that state to the compliance 

accounts of affected EGUs in another state.608 This net transfer 

 

608 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 
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is determined based on compliance account holdings at the end of 

the plan performance period.609 For example, assume two states, 

State A and State B, with emission budgets of 1,000 tons of CO2. 

Each state issues 1,000 CO2 allowances. At the end of a plan 

performance period, affected EGUs in State A collectively hold 

500 CO2 allowances in their compliance accounts that were issued 

by State A. Affected EGUs in State B collectively hold in their 

compliance accounts 500 CO2 allowances issued by State A and 

1,000 CO2 allowances issued by State B. In this simplified 

example, a net transfer of 500 CO2 allowances has occurred 

between State A and State B. State A has “exported” 500 CO2

allowances to State B, while State B has “imported” 500 CO2

allowances from state A. 

d. Multi-state plans that address a subset of EGUs in a state. 

 

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. 

609 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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The EPA is clarifying in the final emission guidelines that a 

state may participate in more than one multi-state plan. Under 

this approach, the state would identify in its submittal the 

subset of affected EGUs in the state that are subject to the 

multi-state plan or plans. This could involve a subset of 

affected EGUs that are subject to a multi-state plan, with the 

remainder of affected EGUs subject to a state’s individual plan. 

Alternatively, different affected EGUs in a state may be subject 

to different multi-state plans. In all cases, the state would 

need to identify in each specific plan which affected EGUs are 

subject to such plan, with each affected EGU subject to only one 

multi-state plan or subject only to the state’s individual plan 

(if relevant). 

 These scenarios may occur where a state chooses to subject 

affected EGUs in different ISOs or RTOs to different multi-state 

plans. This will provide states with flexibility to participate 

in multi-state plans that address the affected EGUs in a 

respective grid region, in the case where state borders cross 

grid regions. 

 These scenarios may also occur where a state is served by 

multiple vertically integrated electric utilities with service 

territories that cross state lines. This will provide states 

with flexibility to participate in multi-state plans that 
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address the affected EGUs owned and operated by a utility with a 

multi-state service territory. 

e. Legal issues regarding multi-state plans. While nothing in 

section 111(d)(1) explicitly authorizes states to adopt and 

submit multi-state plans and for the EPA to approve them as 

satisfactory, nothing in section 111(d)(1) explicitly prohibits 

this, 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, 

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 
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EGU CO2 emissions; 

2. The enforceable measures must be projected to achieve 

emission performance equivalent to or better than the applicable 

CO2 emission performance rates or state-specific CO2 goal on a 

timeline equivalent to that in the emissions guidelines; 

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 

a satisfactory state plan that meets the required plan 

components discussed below will inevitably meet the proposed 

approvability criteria. The EPA, therefore, has incorporated the 

proposed approvability criteria into the section titled 

“Components of a state plan submittal” (section VIII.D.2 below), 

which results in no functional change in the approvability 

criteria or the components of a state plan addressed in the 

proposal. We do not expect this change to have a substantive 
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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.610 

The EPA also requested comment on whether the agency should 

provide guidance on enforceability considerations related to 

requirements in a state plan for entities other than affected 

EGUs, and if so, what types of entities. Comments received 

strongly suggested that the EPA provide guidance on 

enforceability considerations for non-EGU affected entities, 

particularly for RE and EE. Comments also requested additional 

guidance specific to this rulemaking, including examples of 

enforceable measures for specific activities, such as solar 

thermal programs, waste heat recovery, net-metering energy 

savings and state RPSs. 

 

610 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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These enforcement considerations arose primarily under the 

proposed portfolio approach for state plans. In this action, the 

EPA is finalizing the state measures approach instead of the 

portfolio approach described in the proposed rule. As explained 

in section VIII.C, the EPA is not finalizing the portfolio 

approach, which would have allowed state plan submittals to 

include federally enforceable measures that apply to entities 

that are not affected EGUs. However, 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 federally enforceable backstop which 

requires the affected EGUs to meet emission standards that fully 

achieve the CO2 emission performance rates or the state’s CO2

emission goal if the state measures do not meet the intended 

emission performance levels. Because the EPA is not finalizing 

the portfolio approach, which would have allowed states to 

include 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 
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might apply to such entities. As proposed, we are requiring that 

state plans include a demonstration that plan measures are 

enforceable, which for emission standard plans is discussed in 

section VIII.D.2.b.4 below and for state measures plans 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 the state CO2 emission goal. 

Additionally, a commenter requested that the enforceability 

mechanisms that the EPA requires in state plans should support 

existing programs, as well as new programs in other states, by 

minimizing program changes required purely to conform with 

federal requirements, while still providing enough additional 

program review and accounting to ensure that CO2 emission 

reductions are achieved. These and related comments contributed 

to the EPA’s decision to finalize the option for states to 

submit a state measures plan, which would be comprised, at least 

in part, of measures implemented by the state that are not 

included as federally enforceable components of the plan, with a 

backstop of federally enforceable emission standards for 

affected EGUs that fully meet the emission guidelines and that 

would be triggered if the plan failed to achieve the CO2 emission 
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performance levels specified in the plan on schedule. For more 

information on the state measures plan approach, see section 

VIII.C.4 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. The state 

plan submittal must also be consistent with additional specific 

requirements elsewhere in this final rule and with the EPA 

implementing regulations at 40 CFR 60.23-60.29, except as 

otherwise specified by this final rule. These requirements apply 

to both individual state plan submittals and multi-state plan 

submittals. When a state plan submittal is approved by the EPA, 

the EPA will codify the approved CAA section 111(d) state plan 

in 40 CFR part 62. Section VIII.D.3 discusses the components of 

the 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 approach” plan or a “state measures 

approach” plan. States may also opt to submit a plan that meets 

the CO2 emission performance rates for affected EGUs or achieves 

a state rate-based or mass-based CO2 emission goal. The content 
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of the state plan submittal will vary depending on which 

approach 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 multistate plan. 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 approach. Section VIII.D.2.c addresses additional 

components required for submittals under the state measures plan 

approach. 

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 approach) or 

VIII.D.2.c (for the state measures plan approach) of this 

section. 

(1) Description of the plan approach and geographic scope. The 

description of the plan approach must indicate whether the state 

will meet the emission guidelines on an individual state basis 

or jointly through a multi-state approach, and whether the state 

is adopting an emission standards approach plan or a state 

measures approach plan. For multi-state plans this component 

must identify all participating states and geographic boundaries 
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applicable to each component in the plan submittal. 

(2) Identification of interim period emission performance rates 

or state goal (for 2022-2029), interim step performance rates or 

interim state goals (2022-2024; 2025-2027; 2028-2029) and final 

emission performance rates or state goal (2030 and beyond). The 

state plan submittal must indicate whether the plan is designed 

to meet the CO2 emission performance rates or the state CO2

emission goal. As noted in the emission guidelines, the EPA is 

finalizing 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). The state may adopt either the 

rate-based or the mass-based state CO2 emission goal provided in 

the emission guidelines. If the state chooses the option of 

developing a plan that achieves the state CO2 emission goal, the 

state plan submittal must identify the rate-based or mass-based 

CO2 emission goal that must be achieved through the plan 

(expressed in numeric values, including the units of 

measurement, such as pounds of CO2 per net MWh of useful energy 

output or tons of CO2). The plan submittal must identify the 

state CO2 interim period goal (for 2022-2029), interim steps 

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. 
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 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-

2029.611 States are free to establish different interim step 

goals than those the EPA has specified in this final rule. If 

states choose to determine their own interim step goals, the 

state must demonstrate that it will still meet the interim goal 

for 2022-2029 finalized in this action and the plan submittal 

must include in its supporting documentation a description of 

the analytic process, tools, methods, and assumptions used to 

make this demonstration. 

The final rule allows states the opportunity to switch from 

a rate-based CO2 goal for the interim plan performance period 

(2022-2029) to a mass-based CO2 goal for the final plan 

performance period (2030 and onward). Conversely, a state plan 

may use a mass-based CO2 goal for the 2022-2029 interim period, 

and a rate-based CO2 goal for the final goal plan performance 

periods. Some commenters requested that flexibility be provided 

to allow states to switch from rate-based goals to mass-based 

 

611 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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goals either as a one-time change between the interim goal to 

the final goal, or more frequently if necessary year-by-year. 

The EPA recognizes that it may be necessary to switch between 

rate-based goals and mass-based goals, and therefore provides 

the option for states to change approaches between the interim 

plan performance period and the final plan performance period. 

To ensure progress toward the goals, maintain consistency with 

rule provisions, and minimize delays due to plan revisions, the 

EPA does not grant states the ability to change approaches more 

often than from the interim period to the final period. For 

instance, if a state plan indicates that a mass-based CO2 goal 

will be used for demonstrating achievement of the interim goal, 

then that state will be required to demonstrate achievement of 

the specified mass-based interim steps on a mass basis, and will 

have the option to change to a rate-based approach for the final 

plan performance period. 

For states participating in a multi-state plan with a joint 

goal (for interim and final periods), the individual state goals 

in the emission guidelines would be replaced with an equivalent 

multi-state goal for each period (interim and final). For a

rate-based multi-state plan this would be a weighted average 

rate-based emission goal, derived by the participating states, 

by calculating a weighted average CO2 emission rate based on the 
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individual rate-based goals for each of the participating states 

and 2012 generation from affected EGUs. For a mass-based multistate plan, the joint goal would be a sum of the individual 

mass-based goals of the participating states, in tons of CO2. The 

plan submittal must include in its supporting documentation a 

description of the analytic process, tools, methods, and 

assumptions used to calculate the joint multi-state goal. 

(3) Applicability of state plans to affected EGUs. The state 

plan submittal must list the individual affected EGUs that meet 

the applicability criteria of § 60.5805 and provide an inventory 

of CO2 emissions from those affected EGUs for the most recent 

calendar year prior to plan submission for which data are 

available. 

(4) Monitoring, reporting and recordkeeping requirements for 

affected EGUs. The state plan submittal must specify how each 

emission standard is quantifiable and verifiable by describing 

the CO2 emission monitoring, reporting and recordkeeping 

requirements for affected EGUs. The applicable monitoring, 

recordkeeping and reporting requirements for affected EGUs with 

are outlined in section VIII.F. 

In the June 2014 proposal, the EPA proposed that states 

must include in their state plans a record retention requirement 

for affected EGUs to maintain records for at least 10 years 
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following the date of each occurrence, measurement, maintenance, 

corrective action, report or record. Commenters requested 

clarification of the record retention requirements for states 

vs. for affected EGUs and also requested that the EPA clarify 

onsite vs. offsite record maintenance requirements for affected 

EGUs. Consistent with state recordkeeping requirements, the EPA 

is finalizing that states must include in their plans a record 

retention requirement for affected EGUs of not less than 5 years 

following the date of each compliance period, occurrence, 

measurement, maintenance, corrective action, report, or record., 

that affected EGUs must maintain each record onsite for at least 

2 years after the date of the occurrence of each record and may 

maintain records offsite and electronically for the remaining 

years. Each record must be in a form suitable and readily 

available for expeditious review. The EPA finds that these final 

recordkeeping requirements are appropriate and consistent with 

the requirements for other CAA section 111(d) emission 

guidelines. 

(5) State reporting and recordkeeping requirements. A state plan 

submittal must contain the process, content and schedule for 

state reporting to the EPA on plan implementation and progress 

toward meeting the CO2 emission performance rates or state CO2

emission goal. 
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The EPA is finalizing state reporting requirements based on 

the type of plan approach the state chooses to adopt and 

implement. These state reporting requirements are discussed in 

section VIII.D.2.b (for emission standards approach) and 

VIII.D.2.c (for state measures approach). 

In addition to the state reporting requirements discussed 

in section VIII.D.2.b (for emission standards approach) and 

VIII.D.2.c (for state measures approach) and as discussed below, 

states must include in the supporting material of a final state 

plan submittal a timeline with all the programmatic milestone 

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

submittal and 2022 to ensure the plan is effective as of 2022. 

The EPA is also finalizing a requirement that states must submit 

a report to the EPA in 2021 that demonstrates that the state has 

met the programmatic milestone steps that the state indicated it 

would take from the submittal of the final plan through the end 

of 2020, and that the state is on track to implement the 

approved state plan as of January 1, 2022. An approvable final 

state plan submission must include a requirement for the state 

to submit this report to the EPA no later than July 1, 2021. If 

the EPA approves a state plan that includes the required 

obligation on the state to submit this report, and the state 

either does not submit the requisite report by July 1, 2021, or 
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the state submits a report demonstrating it has not met the 

programmatic milestones, the EPA’s approval of the state plan 

will convert to a disapproval. Per the requirements of CAA 

section 111(d), the EPA will develop and implement a federal 

plan in the instance of such disapproval. As discussed in 

section VIII.B, if a state demonstrates, in its July 1, 2021 

report, that it has implemented such early action measures, the 

EPA will consider its report to be presumptively approvable. 

The EPA is finalizing a requirement for states to 

electronically submit state plan submittals, any supporting 

materials that are part of a state plan submittal, and state 

reports required by the state plan. The EPA is developing an 

electronic system to support this requirement that can be 

accessed at the EPA’s Central Data Exchange (CDX) 

(http://www.epa.gov/cdx/). See Section VIII.E.7 for additional 

information on electronic submittal requirements. 

In the June 2014 proposal, the EPA proposed that states 

must keep records at minimum for 20 years of all plan 

components, plan requirements, plan supporting documentation and 

status of meeting the plan requirements, including records of 

all data submitted by each affected EGU used to determine 

compliance with emission standards. The EPA received multiple 

comments recommending that the EPA reduce recordkeeping 
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requirements due to the burden in expenditure of resources and 

manpower to maintain records for at least 20 years. Commenters 

recommended that recordkeeping requirements be reduced to five 

years consistent with emission guidelines for other existing 

sources. 

After considering the comments received, this final rule 

requires that a state must keep records of all plan components, 

plan requirements, supporting documentation, and the status of 

meeting the plan requirements defined in the plan for the 

interim steps 1, 2 and 3 and the interim plan period from 2022-

2029. After 2029, states must keep records of all information 

relied upon in support of any continued demonstration that the 

final CO2 emissions performance rates or goals are being 

achieved. The EPA agrees with comments that a 20-year record 

retention requirement could be unduly burdensome, and has 

reduced the length of the record retention requirement for the 

final rule. During the interim period, states must keep records 

for 10 years from the date of conclusion of each compliance 

period for its EGUs and/or plan performance period. During the 

final period, states must keep records for 5 years from the date 

of conclusion of each compliance period for its EGUs and/or plan 

performance period. All records must be in a form suitable and 

readily available for expeditious review. States must also keep 
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records of all data submitted by each affected EGU that was used 

to determine compliance with each affected EGU’s emission 

standard, and such data must meet the requirements of the 

emission guidelines, except for any information that is 

submitted to the EPA electronically pursuant to requirements in 

40 CFR part 75. If the state is adopting and implementing the 

state measures approach, the state must also maintain records of 

all data regarding implementation of each state measure and all 

data used to demonstrate achievement of CO2 emission performance 

rates or CO2 emission goal and such data must meet the 

requirements of the emission guidelines. The EPA finds that 

these final recordkeeping requirements balance the need to 

maintain records while reducing the strain on state resources. 

(6) Certification of hearing on state plan. For the final plan 

submittal, states must meaningfully engage with all members of 

the public, including communities, during the plan development 

process. The existing implementing regulations regarding public 

participation requirements are in40 CFR 60.23(c)-(f). Per the 

implementing regulations, states must conduct a public hearing 

on a final state plan before such plan is adopted and submitted. 

In its plan submittal, a state must provide certification that 

the state gave reasonable notice and opportunity for public 

comment on the state plan. The state must demonstrate that the 
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public hearing on the state plan was held only after reasonable 

notice, which will be considered to include, at least 15 days 

prior to the date of such hearing, notice given to the public by 

prominent advertisement announcing the date(s), time(s) and 

place(s) of such hearing(s). For each hearing held, a state plan 

submittal must include in the supporting documentation the list 

of witnesses and their organizational affiliations, if any, 

appearing at the hearing, and a brief written summary of each 

presentation or written submission pursuant to the requirements 

of the implementing regulations at 40 CFR 60.23. Additionally, 

the EPA recommends that states work with local municipalities, 

community-based organizations and the press to advertise their 

state hearing(s). 

As previously discussed in this rule, recent studies also 

find that certain communities, including low-income communities 

and some communities of color, are disproportionately affected 

by certain climate change related impacts. Also as discussed in 

this rule, effects from this rule can be anticipated to impact 

communities in various ways. Because certain communities have a 

potential likelihood to be impacted by state plans, the EPA 

believes that the existing public participation requirements 

under 40 CFR 60.23 are effectuated for the purposes of this 

final rule by states engaging in meaningful, active ways with 
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such communities. 

The EPA notes that meaningful public involvement goes beyond 

the holding of a public hearing. In section VIII.E, the EPA 

provides states with resources on how to engage with affected 

communities in a meaningful way. With respect specifically to 

ensuring meaningful community involvement in their public 

hearing(s), however, the EPA recommends that states have both a 

website and toll-free number that all stakeholders, including 

affected communities, can access to get more information 

regarding the upcoming hearing(s). In addition, the EPA 

recommends that states provide all communities with a mechanism 

on their website and on the toll-free number to get their 

questions related to upcoming hearings answered. Furthermore, 

the EPA recommends that states work with their local government 

partners to help them in reaching out to all stakeholders, 

including affected communities about the upcoming public 

hearing(s). 

(7) Supporting documentation. The state plan submittal must 

provide supporting material and technical documentation related 

to applicable components of the plan submittal. 

(a) Legal authority. In its submittal, a state must adequately 

demonstrate that it has the legal authority 

(regulations/legislation) and funding to implement and enforce 
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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, multi-state goal calculation 

(if joint multi-state demonstration), analytical materials used 

in projecting CO2 emission performance that will be achieved 

through the plan, relevant implementation materials and any 

additional technical requirements and guidance the state 

proposes to use to implement elements of the plan. 

(c) Programmatic milestones and timeline. As part of the state 
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plan supporting documentation, the state must include in its 

submittal a timeline with all the programmatic milestone steps 

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

and 2022 to ensure the plan is effective as of 2022. The 

programmatic milestones and timeline should be appropriate to 

the overall state plan approach included in the state plan 

submittal. 

(d) Reliability. As discussed in section VIII.H.2, each state 

must demonstrate that it has considered reliability issues while 

developing its plan. 

b. Additional components required for the emission standards 

approach. The EPA is finalizing requirements that a final plan 

submittal using the emission standards approach must contain the 

following components, in addition to the components discussed in 

section VIII.D.2.a. 

(1) Identification of federally enforceable emission standards 

for affected EGUs. The state plan submittal must include 

federally enforceable emission standards that apply to affected 

EGUs. The emission standards must meet the requirement of 

component 2 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 
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periods for each emission standard for affected EGUs, on a 

calendar year basis, must be as follows for the interim period: 

January 1, 2022 – December 31, 2024; January 1, 2025 – December 

31, 2027; and January 1, 2028 – December 31, 2029. Starting on 

January 1, 2030, the compliance period for each emission 

standard is every two calendar years. States can choose to set 

shorter schedules of compliance for the emission standards but 

no longer than the compliance periods the EPA is finalizing in 

this rulemaking. 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. The state plan must also demonstrate that 
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the appropriate ERC tracking infrastructure that meets the 

requirements of the emission guidelines will be in place to 

administer the state plan requirements regarding ERCs and 

document the functionality of the tracking system. State plan 

requirements must include provisions to ensure that ERCs are 

properly tracked from issuance to submission for compliance. The 

state plan must also demonstrate that the MWh for which ERCs are 

issued are properly quantified and verified, through state EM&V 

and other verification plan requirements that meet the 

requirements in the emission guidelines. 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. All of these requirements are 

discussed in more detail in sections VIII.G.3 and 4. 

 For state plans using a mass-based emission trading program 

approach, the emission standards in the state plan must include 

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 
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affected EGUs to demonstrate compliance (allowance “true-up” 

with reported CO2 emissions.) 

(2) 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.612

An emission standard is non-duplicative with respect to an 

affected EGU if it is not already incorporated in another state 

plan, except in instances where incorporated as part of a multistate plan. An example of a duplicative emission standard would 

occur, for example, where a quantified and verified MWh from a 

wind turbine could be applied in more than one state’s CAA 

section 111(d) plan to adjust the CO2 emission rate of an 

 

612 CO2 continuous emissions monitoring system (CEMS) is the most 

technically reliable method for EGUs. CEMS provide a measurement 

method that is performance based rather than equipment specific 

which is verified based on NIST traceable standards. CEMS 

provide 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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affected EGU, except in the case of a multi-state plan where CO2

emission performance is demonstrated jointly for all affected 

EGUs subject to the multi-state plan.613 This does not mean that 

measures in an emission standard cannot also be used for other 

purposes. For example, a MWh of electric generation from a wind 

turbine could be used by an electric distribution utility to 

comply with state RPS requirements and also be used by an 

affected EGU comply with emission standard requirements under a 

state plan. Another example is when actions taken pursuant to 

CAA section 111(d) requirements can satisfy other CAA program 

requirements (e.g., Regional Haze requirements, MATS etc.) 

An emission standard is permanent if the emission standard 

must be met for each applicable compliance period. 

An emission standard is verifiable if adequate monitoring, 

recordkeeping and reporting requirements are in place to enable 

the state and the Administrator to independently evaluate, 

 

613 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 emission standards in another state, where 

states are collaborating in the implementation of their 

individual emission trading programs through interstate transfer 

of ERCs or CO2 emission allowances, or participating in a multistate plan with a rate-based or mass-based emission trading 

program. These coordinated multi-state approaches are addressed 

in subsection VIII. 
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measure, and verify compliance with it. 

An emission standard is enforceable if it: (1) represents a 

technically accurate limitation or requirement and the time 

period for the limitation or requirement is specified, (2) 

compliance requirements are clearly defined, (3) the entities 

responsible for compliance and liable for violations can be 

identified, (4) each compliance activity or measure is 

practically enforceable in accordance with EPA guidance on 

practical enforceability,614 and the Administrator and the state 

maintain the ability to enforce against violations and secure 

appropriate corrective actions pursuant to CAA sections 113(a)–

(h), and states and other third parties maintain the ability to 

enforce against violations and secure appropriate corrective 

actions pursuant to CAA section 304. 

In developing its CAA section 111(d) plan, to ensure that 

the plan submittal is enforceable and in conformance with the 

CAA, a state should follow the EPA’s prior guidance on 

enforceability.615 These guidance documents serve as the 

 

614 See prior footnote. 

615 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 
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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 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” TSD616 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 violations of an emission standard 

included in a state plan via civil action as part of the 

required plan component demonstrating enforceability. We are 

finalizing this requirement as a logical outgrowth of proposal 

preamble text, the proposal preamble citation to existing 

enforceability guidance documents that discuss this requirement, 

 

Energy Policies and Programs into State and Tribal 

Implementation Plans, Appendix F.” 

616 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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and comments received. 

(3) Demonstration that the emission standards contained in the 

plan achieve the CO2 emission performance rates or state CO2

emission goal. A state plan submittal must demonstrate that the 

federally enforceable emission standards on affected EGUs are 

sufficient to meet either the CO2 emission performance rates or 

the state’s CO2 emission goals in the emission guidelines for the 

interim and final periods. This includes the interim period of 

2022-2029, including interim step 1 2022-2024 period; interim 

step 2 2025-2027 period and interim step 3 2028-2029 period (or 

alternative CO2 emission performance step levels adopted by the 

state, provided they result in achievement of the CO2 emission 

performance rates or state CO2 emission goal during the 2022-2029 

interim period), as well as the final period of 2030 and beyond. 

The type of demonstration required for emission standards plans 

will vary depending on how the CO2 emission performance standards 

are applied across the fleet of affected EGUs in a state, as 

described below. 

(a) Demonstration for a rate-based emission standards state 

plan. The type of demonstration for a rate-based emission 

standards plan depends on the design of the plan submitted to 

the EPA. 

 When a state submits an emission standards plan that 
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establishes separate rate-based CO2 emission standards for 

affected fossil fuel-fired electric utility steam generating 

units and stationary combustion turbines (in lbs CO2/MWh) that 

are equal to or lower than the CO2 emission performance rates in 

the emission guidelines, then no additional demonstration is 

required beyond inclusion of the emission standards in the plan. 

Under this approach, compliance by affected EGUs with the 

emission standards will ensure that the CO2 emission performance 

rates or the state rate-based CO2 emission goal is achieved. 

If a state chose to instead apply rate-based emission 

performance standards to individual affected EGUs, or to subcategories of affected EGUs (such as fossil fuel-fired electric 

utility steam generating units and stationary combustion 

turbines), at a lb CO2/MWh rate that differs from the CO2

emission performance rates or the state’s rate-based CO2 goal, 

then a further demonstration is required that application of the 

CO2 emission standards will achieve the CO2 emission performance 

rates or state rate-based CO2 goal in the emission guidelines. 

The state must demonstrate through a projection that the 

weighted average CO2 emission rate of affected EGUs, when 

weighted by generation (in MWh), will be equal to or less than 

the CO2 emission performance rates or the state's rate-based CO2

emission goal. This projection must address both the interim 
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period (including interim step periods 1-3, for 2022-2024, 2025-

2027, and 2028-2029), and the final period (2030-2031, and 

subsequent two-year periods). The projection in a state plan 

must include the following key information, at a minimum: 

 a summary of each affected EGU’s anticipated future 

operation characteristics, including annual 

generation, CO2 emissions, capacity and capacity 

factors; 

 planned retirements; 

 anticipated use of ERCs to adjust the reported CO2

emission rate of affected EGUs, including but not 

limited to, anticipated use (in MWh) by technologytype (e.g., wind, solar, demand-side EE), the physical 

location of the resources providing ERCs, and any 

other relevant information (e.g., power purchase 

agreements (PPAs) and other long-term power 

contracts); and an explanation, with calculation, of 

how these measures are being used in the projection to 

adjust the CO2 emission rate of affected EGUs; 

 expected electricity demand growth at the state or 

regional level, including the source and basis for 

these estimates (e.g., based on population growth, 

GDP, adoption of demand-side EE or other applicable 
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factors); if demand growth is not from NERC, an ISO or 

RTO, EIA or other publicly available source, then the 

projection must include justification and assumptions 

that inform the demand growth used; 

 expected fuel switching at affected EGUs; 

 heat rate improvements; and 

 any other applicable assumptions used in the 

projection. 

Because electricity flows across state boundaries, single 

state plan demonstrations must explain any regional 

information considered in developing the assumptions. 

Multi-state plans or plans sharing common elements should 

use regional assumptions or demonstrate reconciliation of 

any inconsistencies between state-level assumptions. 

(b) Demonstration for a mass-based emission standards state 

plan. Under the emission standards plan type, a mass-based 

emission budget trading program must be designed such that 

compliance by affected EGUs would achieve the state mass-based 

CO2 goal. Under this approach, a state plan establishes emission 

budgets for affected EGUs during the interim and final plan 

performance periods that are equal to or lower than the 

applicable state mass-based CO2 goals specified in the final 

emission guidelines. Compliance periods for affected EGUs are 
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also aligned with the interim and final plan performance 

periods. This approach limits total CO2 emissions from affected 

EGUs during the interim and final plan performance periods to an 

amount equal to or less than the state’s mass-based CO2 goal. 

 Under this approach, compliance by affected EGUs with the 

mass-based emission standards in a plan would ensure that the 

state achieves its mass-based CO2 goal for affected EGUs. No 

further demonstration is necessary by the state to demonstrate 

that its plan would achieve the state’s mass-based CO2 goal. 

For this type of plan, where the emission budget is equal 

to or less than the state mass CO2 goal,617 the EPA will assess 

achievement of the state goal based on compliance by affected 

EGUs with the mass-based emission standards, rather than 

reported CO2 emissions by affected EGUs during the interim plan 

performance periods and final plan performance periods. This 

approach allows for allowance banking between performance 

periods, which is a typical design element for emission budget 

trading programs addressing GHG emissions. 

(4) State reporting requirements. After consideration of the 

comments received regarding state reporting requirements, the 

EPA is finalizing for state plans using the emission standards 

 

617 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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approach that a state report is due to the EPA no later than the 

July 1 following the end of each reporting period. For 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 biannual state report is required 

starting in 2030 and beyond covering the two calendar years of 

each reporting period. The EPA believes this final reporting 

schedule will reduce the reporting frequency for states 

implementing the emission standards approach. 

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. 

As discussed in more detail in section VIII.F, in each 

report during the interim period (2022-2029), the state must 

include an interim performance check. The interim performance 
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check 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 affected EGUs 

during the period. Starting in 2032, the biannual state report 

must include a final performance check to demonstrate that the 

state continues to meet the final CO2 emission performance rates 

or state rate-based or mass-based CO2 goal. 

For states using the emission standards approach, if actual 

CO2 emission performance by affected EGUs exceeds the specified 

level of CO2 emission performance in the state plan by 10 percent 

or more during any of the specified interim step reporting 

periods or during a final plan reporting period (after 2030), 

the state report must include a notification to the EPA that 

corrective measures have been triggered. Corrective measures are 

discussed in detail in section VIII.F. 

c. Additional components required for the state measures 

approach. The EPA is finalizing requirements that a final plan 

submittal using the state measures approach must contain the 

following components, in addition to the components discussed in 

section VIII.D.2.a. 

(1) Identification of federally enforceable emission standards 

for affected EGUs (if applicable). If applicable, the state plan 

submittal must include any federally enforceable CO2 emission 
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standards that apply to affected EGUs, and demonstrate that 

those emission standards meet the requirements that apply in the 

context of an emission standards approach, discussed in the 

preceding section VIII.D.2.b. Specifically, the state plan 

submittal must demonstrate that each federally enforceable 

emission standard is quantifiable, non-duplicative, permanent 

and verifiable. 

(2) 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 CO2 emission performance rates or the state’s 

interim and final CO2 emission goal if the state plan fails to 

achieve the intended level of CO2 emission performance. The 

backstop emission standards could be based on the federal plan, 

using the federal plan regulations as a model rule. 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 

and identify all necessary state administrative and technical 
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procedures for implementing the backstop (e.g. how and when the 

state would notify affected EGUs that the backstop has been 

triggered). Aspects of the backstop are discussed in detail in 

section VIII.C.4.b. 

(3) Identification of state measures. A state adopting a state 

measures plan approach must provide as a part of the supporting 

documentation of its plan submittal, a description of all the 

state enforceable measures the state will rely upon to achieve 

the requisite CO2 emission performance rates or state goal, the 

applicable state laws or regulations related to such measures, 

and identification of parties or entities implementing such 

state measures. The state must also include in its supporting 

documentation the schedule and milestones for the implementation 

of the state measures. A state measures plan submittal that 

relies upon RE and demand-side EE programs and projects must 

also demonstrate in its supporting documentation that the 

minimum EM&V requirements apply to those programs and projects. 

(4) Demonstration that the standards and/or measures are 

projected to achieve the CO2 emission performance rates or state 

CO2 emission goal. A state plan submittal must demonstrate that 

the federally enforceable emission standards for affected EGUs, 

if included, and state measures, are sufficient to attain the CO2

emission performance rates or state rate-based or mass-based CO2
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emission goal for the interim period of 2022-2029 and the final 

period of 2030 and beyond. The elements required in the state 

demonstration will vary depending on the design of the state 

plan, as described below in this section. 

(a) Demonstration for a state measures state plan. A state 

measures plan submittal must demonstrate that the state 

measures, whether alone or in conjunction with any federally 

enforceable CO2 emission standards, will achieve either the CO2

emission performance rates or the state rate-based or mass-based 

CO2 goals in the emission guidelines for the interim and final 

periods. This includes the interim period of 2022-2029, 

including interim step 1 2022-2024 period, interim step 2 2025-

2027 period, and interim step 3 2028-2029 period (or alternative 

CO2 emission performance step levels adopted by the state, 

provided they result in achievement of the CO2 emission 

performance rates or state CO2 emission goal during the 2022-2029 

interim period), as well as the final period of 2030 and beyond. 

 A satisfactory demonstration of the future CO2 performance 

of quantifiable and verifiable state-enforceable measures must 

use technically sound quantification methods that are reliable 

and replicable. The demonstration must be supported by the 

methods and measurement procedures by which the federally 

enforceable CO2 emission standards for affected EGUs are reliably 
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measured, if these standards are incorporated into the state 

measures state plan. In addition, the demonstration must include 

details about individual state-enforceable measures (or bundled 

measures), timing for implementation and future MWh impacts of 

these measures. The future performance of affected EGUs must be 

based on verifiable and quantifiable energy and emissions 

quantification methods accompanied with underlying analytical 

assumptions and verifiable data sources used to demonstrate 

future CO2 performance by affected EGUs under this type of state 

plan. 

A satisfactory state measures plan demonstration must 

include a state measures CO2 performance projection that shows 

how the measures in the state plan, alone or in conjunction with 

federally enforceable CO2 emission standards, will achieve the 

future CO2 performance at affected EGUs. Elements of this 

projection must include the following for the interim and final 

periods: 

 An explanation of the tools and emission 

quantification approaches used in the projection 

(described in section VIII.D.2.c.(4)(b). 

 State Measures Plan CO2 Performance Projection that 

includes all state measures and/or emission standards 

in the state plan (see the State Plans Technical 
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Support Document for details). 

 Underlying assumptions used in the projection (as 

described below in sections VIII.D.2.c.(4)(b),(c) and 

(d). 

 (b) Emission quantification approaches and tools. The EPA 

received comments on whether we would require specific modeling 

tools and input assumptions. Commenters raised concerns that the 

EPA may require states to use proprietary models because many 

states do not have the financial resources to conduct their own 

modeling using utility dispatch models or capacity expansion 

models. The EPA is not requiring a specific type of emission 

quantification approach or model, as long as the one chosen uses 

technically sound methods that establish a clear relationship 

between electricity grid interactions of the state enforceable 

measures, affected EGU dispatch, generation cost and operations 

within the time frame outlined in these guidelines. Emission 

quantification methodologies could range from historical 

estimates using growth rate or statistical analysis to electric 

sector energy modeling. If a state chose to include supplemental 

material on emission baseline projections, then the emissions 

quantification method used for both the baseline projection and 

state measure plan scenario should be similar. A state should 

include an explanation of how the emission quantification method 
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works and the associated tool(s) that employ the method, as well 

as an explanation for why the methodology and tool chosen is 

best suited for an electric sector analysis of affected EGUs for 

the interim period and final period. The results in the 

demonstration must be verifiable and reproducible using the 

documented assumptions described in the following paragraph. 

The projections of EGU dispatch and generation can differ 

from the EPA’s forecast in the RIA, but should have a clear 

relationship between future electricity demand, costs and 

generation capacity to establish the projected future CO2

emissions from affected EGUs. The following assumptions 

demonstrating the relationship between the state measures and CO2

emission performance of affected EGUs should be documented and 

explained: projected CO2 emission rates in lbs/MWh; projected CO2

emissions; projected generation at the EGU in MWhs; fuel prices, 

when applicable; heat rates for each affected EGU; wholesale 

electricity prices, when available; projected emission limits 

and/or rates as a result of environmental or economic 

constraints; planned retirements; planned new generation; fuel 

switches at affected EGUs; fixed operations and maintenance 

costs, when applicable; variable operations and maintenance 

costs, when applicable; and planning reserve margins, when 

applicable. 
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(c) Elements of a rate-based state measures plan. Under a ratebased state measures plan, MWh from state enforceable qualifying 

measures may be used to adjust the CO2 emission rate of affected 

EGUs when demonstrating achievement of the CO2 emission 

performance rates or the state rate-based CO2 goal in the 

emission guidelines. The state plan would include the following 

key information, at a minimum, to demonstrate the rate-based 

state measures plan for affected EGUs are commensurate with the 

state’s goal: 

 a summary of each affected EGU’s anticipated future 

operation characteristics, including annual 

generation, CO2 emissions, capacity and capacity 

factors; 

 planned retirements; 

 a detailed description of the zero CO2 emitting demandside EE savings and RE generation (and any other 

qualifying MWh) from state measures that will be 

available for use in adjusting the reported CO2

emission rates of affected EGUs, including, but not 

limited to, the amount of generation or savings by 

technology-type (e.g., wind, solar, EE), the physical 

location of the EE measures or RE generation, and any 

other relevant information (e.g., power purchase 
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agreements (PPAs) and other long-term power 

contracts); and an explanation, with calculation, of 

how these measures are being used in the projection to 

adjust the CO2 emission rate of affected EGUs; 

 expected electricity demand growth at the state or 

regional level, including the source and basis for 

these estimates (e.g., based on population growth, 

GDP, adoption of demand-side EE or other applicable 

factors); if demand growth is not from NERC, an ISO or 

RTO, EIA or other publicly available source, then the 

projection must include justification and assumptions 

that inform the demand growth used; 

 expected fuel switching at affected EGUs; 

 heat rate improvements; and 

 any other applicable assumptions used in the 

projection. 

In the state plan demonstration, the state must show the 

calculation of this adjustment from these state enforceable 

actions at their affected EGUs either in aggregate or at each 

affected EGU. As specified in section VIII.G, the zero-emitting 

MWhs of EE and RE can be added to the denominator of the 

emission rate of the affected EGUs. The demonstration should 

illustrate this arithmetic adjustment for rate-based state 
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measure plans. 

(d) Elements of a mass-based state measures plan. Under a massbased state measures plan, a state must demonstrate that the 

combined state-enforceable measures, along with any federally 

enforceable CO2 emission standards for affected EGUs, if 

included, will achieve the state mass-based CO2 goal. Because 

these measures could have varying degrees of impact on CO2

emissions from affected EGUs, the approach a state chooses to 

quantify projected emissions impacts should have the capability 

to demonstrate how the combined state enforceable measures are 

impacting CO2 emissions at affected EGUs so that the sum of 

emissions at all affected EGUs will be lower than or achieve the 

state’s CO2 emission goal for each specified time period in the 

emission guidelines. The EPA is not requiring a specific method 

or tool, but clear documentation of assumptions and explanation 

of methods used, as discussed in section VIII.D.2.c and in the 

State Plans Technical Support Document, must be included in a 

satisfactory demonstration. 

(5) State reporting requirements. After consideration of the 

comments received regarding state reporting requirements, the 

EPA is requiring in this final rule for states using the state 

measures approach that an annual state report is due to the EPA 

no later than July 1 following the end of each calendar year 
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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 should 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. 

As discussed in section VIII.F, for states using the state 

measures approach, the EPA is finalizing that at the end of each 

interim step period, 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. 

Beginning with the final period, the state must submit 

biannual reports no later than July 1 after the end of each 

reporting period that includes an actual performance check to 

demonstrate that the state continues to meet the final CO2

emission performance rates or state CO2 goal. 

If, at the time of the state report to the EPA, the state 

did not meet the programmatic milestones for the reporting 

period, or the performance check shows that actual CO2 emission 
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performance by affected EGUs exceeds the specified level of 

emission performance in the state plan submittal by 10 percent 

or more, the state must include in the state report a 

notification to the EPA that the backstop has been triggered and 

describe the steps taken by the state to inform the affected 

EGUs that the backstop has been triggered. In the event of such 

an exceedance under the state measures approach, the backstop 

federally enforceable emission standards for the EGUs must be 

effective within 18 months of the deadline for the state 

reporting to the EPA on plan implementation and progress toward 

the meeting the CO2 emission performance rates or state CO2

emission goal. For example, if a state report due on July 1, 

2025, shows that actual CO2 emission performance by affected EGUs 

exceeds the specified level of emission performance for 2022-

2024 in the state plan by 10 percent or more, the backstop 

federally enforceable emission standards for affected EGUs must 

be effective as of January 1, 2027. 

(7) Supporting documentation. 

(a) Demonstration that each state measure is quantifiable, nonduplicative, 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 
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submittal the state measures618 that are not federally 

enforceable emission standards, and describe how each state 

measure is quantifiable, non-duplicative, permanent, verifiable, 

and enforceable with respect to an affected entity. 

A state measure is quantifiable if it can be reliably 

measured, using technically sound methods, in a manner that can 

be replicated. 

A state measure is non-duplicative with respect to an 

affected entity if it is not already incorporated as a state 

measure or an emission standard in another state plan or state 

plan supporting material, except in instances where incorporated 

in another state as part of a multi-state plan. An example of a 

duplicative state measure would occur, for example, where a 

quantified and verified MWh from a wind turbine could be applied 

in more than one state’s CAA section 111(d) plan to adjust the 

CO2 emission rate of an affected EGU, except in the case of a 

multi-state plan where CO2 emission performance is demonstrated 

jointly for all affected EGUs subject to the multi-state plan. 

This does not mean that measures in a state measure cannot also 

be used for other purposes. For example actions taken pursuant 

 

618 “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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to CAA section 111(d) requirements can satisfy other CAA program 

requirements (e.g., Regional Haze requirements, MATS etc.) and 

state requirements (e.g., RPS). 

A state measure is permanent if the state measure must be 

met for each applicable compliance period. 

A state measure is verifiable if adequate monitoring, 

recordkeeping and reporting requirements are in place to enable 

the state to independently evaluate, measure and verify 

compliance with it. 

A state measure is enforceable619 if it: (1) represents a 

technically accurate limitation or requirement and the time 

period for the limitation or requirement is specified, (2) 

compliance requirements are clearly defined, (3) the affected 

entities responsible for compliance and liable for violations 

can be identified, (4) each compliance activity or measure is 

practically enforceable in accordance with EPA guidance on 

practical enforceability,620 and the state maintains the ability 

 

619 Under the state measures approach, state measures are 

enforceable only per applicable state law. 

620 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 
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to enforce against violations and secure appropriate corrective 

actions. 

The EPA will disapprove a state plan if the documentation 

is not sufficient for the EPA to be able to determine whether 

the state measures are expected to yield CO2 emission reductions 

sufficient to result in the necessary CO2 emission performance 

from affected EGUs for the CO2 emission performance rates or 

state CO2 emission goal to be achieved. 

d. Legal basis for the components. 

(1) General legal basis. Under section 111(d), state plans must 

“provide for the implementation and enforcement of [the] 

standards of 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 

 

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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should be “similar” to those in section 110, and thus a 

substantive requirement in section 110(a)(2) is not an 

independent source of authority for the EPA to require the same 

for section 111(d) plans. However, when there is a gap for the 

EPA to fill in interpreting how a section 111(d) plan should 

“provide for implementation and enforcement of the] standards of 

performance,” and Congress explicitly addressed a similar gap in 

section 110, then it may be reasonable for the EPA to fill the 

gap in section 111(d) using an analogous mechanism to that in 

section 110(a)(2), to the extent that the section 110(a)(2) 

requirement makes sense and is reasonable in the context of 

section 111(d). On the other hand, that Congress did not 

explicitly provide such details as are found in section 

110(a)(2) indicates that Congress intended to give the EPA 

considerable leeway in interpreting the 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 
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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.621 

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 

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 

 

621 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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“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 

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 
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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. 

(2) Legal issues with changes to affected EGUs. In the proposed 

rulemaking, the EPA took the position that if an existing source 

is subject to a section 111(d) state plan, and then undertakes a 

modification or reconstruction, the source remains subject to 

the state plan, while also becoming subject to the modification 

or reconstruction requirements. 79 FR 34830, 34903–4. We noted 

that section 111(d) is silent as to this issue, which we took to 

grant us authority to provide a reasonable interpretation under 
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the Supreme Court’s decision in Chevron U.S.A. Inc. v. NRDC, 467 

U.S. 837, 842–844 (1984). We stated two reasons to disallow 

existing sources to escape 111(d) through modification or 

reconstruction. First, if a source did so, that could prove 

disruptive to the state plan. Second, allowing sources to do so 

could provide them an incentive to do so that would be contrary 

to the purposes of 111(d). We then asked for comment on “whether 

this interpretation is supported by the statutory text and 

whether this interpretation is sensible policy and will further 

the goals of the statute.” 

 With respect to our request for comments on whether our 

proposed interpretation is supported by the statutory text, we 

received comments arguing that it violates the statute. The 

commenters noted that section 111(a)(6) defines “existing 

source” as “any stationary source other than a new source,” and 

section 111(a)(2) defines “new source” to include stationary 

sources that are constructed or modified after “the publication 

of regulations (or, if earlier, proposed regulations) 

prescribing a standard of performance under [section 111] which 

will be applicable to such source.” The comments concluded from 

this that the two categories are mutually exclusive, regardless 

of section 111(d)’s silence on the issue. The comments also 

noted that section 111(d)(1) only allows states to impose 
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standards of performance in 111(d) plans on existing sources “to 

which a standard of performance under [111] would apply if such 

existing source were a new source,” from which the comments 

inferred that states lacked authority under 111(d) to regulate 

sources that are regulated under 111(b). 

 We do not completely agree with these comments, which 

“prove too much.” It is not the case that a source can never be 

both an existing source and a new source within the meaning of 

sections 111(a)(6) and 111(a)(2), respectively. First, a source 

that was a new source under 111(b) standards of performance for 

one pollutant can of course later become an existing source 

under 111(d) for another pollutant when the EPA promulgates 

111(b) standards of performance and 111(d) emission guidelines 

for the second pollutant. Any other result would be 

illogical. Second, we have taken the position under section 129 

(which has similar but not identical definitions) that a new 

source can subsequently become an existing source under revised 

129(b) guidelines. E.g., 74 FR 51368, 51374-75 (Oct. 6, 2009). 

Thus, the comments’ “plain meaning” argument fails to take into 

account context such as these. 

 However, we do agree that, in the particular context here, 

i.e. when section 111(d) emission guidelines are initially 

promulgated for existing stationary sources in response to 
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corresponding section 111(b) standards of performance for the 

same pollutant, that the statute prohibits new sources 

(including under those particular 111(b) standards of 

performance from simultaneously being subject to state plans 

under those particular 111(d) emission guidelines. This 

interpretation gives meaning to the definition of “existing 

source” in section 111(a)(6) and is consistent with the 

definition of “new source” in section 111(a)(2). And, it is 

consistent with the historical treatment of modified and 

reconstructed sources in the section 111 program. The EPA plans 

to address ways to minimize disruption to state plans if such a 

modification or reconstruction were to take place. 

 We believe our final interpretation could reasonably be 

anticipated from our proposal notice. Although our notice 

proposed only a different interpretation of the statute, we did 

not indicate that the proposed interpretation was a settled 

matter (for example, based on previous EPA practice), and we 

invited comment on whether our interpretation was supported by 

the statute. Furthermore, we are basing our final position on 

the language of sections 111(a)(2) and 111(a)(6), which were 

quoted in our discussion of this exact issue in our proposal 

notice. 79 FR 34830, 34903/3. Thus, we gave adequate notice of 

the relevant provisions of the statute, and it could not be 
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unfair surprise that sections 111(a)(2) and 111(a)(6) formed the 

basis of our ultimate position. Finally, there are a very 

limited number of potential interpretations of these provisions 

with respect to this issue; thus our final position could be 

reasonably anticipated. 

(3) Legal issues regarding design, equipment, work practice or 

operational standards. In the proposal, the EPA asked for 

comment on three approaches to inclusion of design, equipment, 

work practice and operational standards in section 111(d) plans. 

79 FR 34830, 34926/3 (June 18, 2014). Under the first approach, 

states would be precluded from including these standards in 

section 111(d) plans unless the design, equipment, work practice 

or operational standard could be understood as a “standard of 

performance” or could be understood to “provide for 

implementation and enforcement” of standards of performance. We 

also asked, for the first approach, whether it was even 

possible, given the statutory language of 111(h), to consider a 

design, equipment, work practice or operational standard as a 

“standard of 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, 
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equipment, work practice and operational standards in a 111(d) 

plan without any constraints. We also asked whether, if there 

was legal uncertainty as to the status of these standards, the 

EPA should authorize states to include them in their 111(d) 

plans with the understanding that if the EPA’s authorization 

were invalidated by a court, states would have to revise their 

plans accordingly. 

The EPA is finalizing the first approach. Specifically, a 

state’s standards of performance (in other words, either the 

federally enforceable backstop under the state measures approach 

or the emissions standards under the emissions 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 cannot substitute for a mass-based limit on 

the affected EGU.622 

This follows from the statute. First, section 111(h)(1) 

 

622 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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authorizes the Administrator, when it is not feasible for 

certain reasons (specified in 111(h)(2)) to prescribe or enforce 

a standard of performance, to instead promulgate a design, 

equipment, work practice or operational standard. If a standard 

of performance could include design, equipment, work practice or 

operational standards, such authority would be unnecessary. 

Second, 111(h)(5) states that design, equipment, work practice 

or operational standards “described in” 111(h) shall be treated 

as standards of performance for the purposes of the CAA. This 

creates a strong inference that standards of performance 

otherwise should not include design, equipment, work practice, 

or operational standards. Finally, the general definition of 

“standard of performance” in 302(l) is similar to the definition 

of “emission limitation” (or “emission standard”) in 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.B.7.e(1), 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 
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performance” (except under the limited circumstances in 111(h)). 

We conclude that it is reasonable, and perhaps compelled, to 

interpret the term “standards of performance” in 111(d) to not 

include design, equipment, work practice and operational 

standards. 

However, section 111(d) requires plans to “provide for 

implementation and enforcement of [the] standards of 

performance.” This language does not explicitly prohibit a plan 

from including design, equipment, work practice and operational 

standards, and allows for them to be included so long as they 

are understood to provide for implementation of the standards of 

performance. If they are included, the 111(d) plan must still be 

“satisfactory” in other respects, in particular in establishing 

standards of performance that are not in whole or in part 

design, equipment, work practice, and operational standards. 

(4) Legal basis for engagement with communities. As previously 

discussed, section 111(d)(1) requires the EPA to promulgate 

procedures “similar” to those in section 110 under 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 
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to the legal importance of adequate public participation in the 

state plan process, including public participation by 

communities. As previously discussed in this rule, recent 

studies also find that certain communities, including low-income 

communities and some communities of color, are 

disproportionately affected by certain climate change related 

impacts. Because certain communities have a potential likelihood 

to be impacted by state plans for this rule, the EPA believes 

that the existing public participation requirements under 40 CFR 

60.23 are effectuated for the purposes of this final rule by 

states engaging in meaningful, active ways with such 

communities. By requiring states to demonstrate they have 

meaningfully engaged with affected 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 
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comment. When a state plan submittal is approved by the EPA, the 

EPA will codify the approved 111(d) state plan in 40 CFR part 

62. The following components of the state plan submittal will 

become the federally enforceable state 111(d) plan: 

 Federally enforceable emission standards for affected EGUs 

 Federally enforceable backstop of emission standards for 

affected EGUs 

 Implementing and enforcing measures for federally 

enforceable emission standards including EGU monitoring, 

recordkeeping and reporting requirements 

 State recordkeeping and reporting requirements 

E. State Plan Submittal and Approval Process and Timing 

1. Overview 

 In this action the EPA is finalizing that state plan 

submittals are due on August 31, 2016, which is 13 months after 

finalization of the emission guidelines. The EPA recognizes that 

due to state legislative schedules and rulemaking processes, 

coordination needed among states involved in multi-state plans, 

coordination with third parties, and the complex technical work 

needed to develop a state plan, states may not be able to 

develop a final plan submittal by 13 months after the final 

rule. However, various states have existing CO2 reduction 

programs in place, such as RE and demand-side EE measures, as 
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well as state and regional programs designed to reduce CO2

pollution from EGUs. Furthermore, state governments have already 

begun active discussions on how to address the final rule 

through policy forums, white papers and non-profit 

organizations. The EPA is also in the process of developing a 

federal plan that states may wish to use as a model rule. The 

EPA views these actions as positive steps that make the 13-month 

timeline achievable. In order to address the concern that 13 

months is not sufficient time for states to prepare and submit a 

final plan submittal and to allow consistent timelines for both 

a single state and multi-state approach to state plan 

submittals, the EPA is also finalizing a plan submittal process 

that provides additional time for states that need it to submit 

a final plan submittal to the EPA after August 31, 2016. This 

approach involves the option that we refer to as an initial 

submittal, followed by submittal of a final state plan submittal 

no later than August 31, 2018, for both single state and multistate plan submittals. During the initial outreach process as 

well as the public comment period on the proposed rule, 

stakeholders commented that additional time was needed to 

accommodate, among other things, state legislative and 

rulemaking schedules, coordination among states involved in 

multi-state plans, coordination with third parties, and the 
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complex technical work needed to develop a state plan. The EPA 

recognizes that state administrative procedures can be lengthy, 

some states may need new legislative authority, and states 

planning to join in a multi-state plan will likely need more 

than 13 months to get necessary elements in place. Balanced 

against that concern, however, is the urgency of addressing CO2

emissions and the fact that there are certain steps the EPA 

believes states can take within 13 months to set themselves on a 

clear path to adoption of a final plan. 

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. 

The EPA is finalizing its proposed approach where one 

multi-state plan submittal is made on behalf of all 

participating states. The joint submittal must be signed by 

authorized officials for each of the states participating in the 

multi-state plan and would have the same legal effect as an 

individual submittal for each participating state. The joint 

submittal must adequately address plan components that apply 

jointly for all participating states and for each individual 

state in the multi-state plan, including necessary state legal 

authority to implement the plan, such as state regulations and 

statutes. Because the multi-state plan functions as a single 
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plan, each of the required plan components (e.g., plan emission 

goals, program implementation milestones, emission performance 

checks, and reporting) would be designed and implemented by the 

participating states on a multi-state basis. 

The EPA is also finalizing two additional options it 

solicited comment on for multi-state plan submittals. First, 

states participating in a multi-state plan have the option of 

providing a single submittal — signed by authorized officials 

from each participating state — that addresses common plan 

elements. This option requires individual participating states 

to provide 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. 
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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. 

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, 
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or state regulations) that allow affected EGUs to use emission 

allowances or RE/EE credits issued in one state for compliance 

with an emission standard in another state.

In order to avoid a multi-state plan becoming unapprovable 

due to one state submitting an unapprovable portion of a multistate plan, withdrawing from the multi-state plan, or failing to 

implement the multi-state plan, states may include express 

severability clauses if their multi-state plan is able to stand 

without further revision if one of the situations described 

above occurs. The severability clause must specify how the 

remainder of the multi-state plan or individual state plan would 

continue to function with the withdrawal of a state or states, 

and may also include pre-specified revisions. The EPA will 

evaluate the appropriateness of such a clause as part of its 

review of the multi-state plan submittal. 

2. State plan submittal and timing 

The EPA implementing regulations (40 CFR 60.23) require 

that state plans be submitted to the EPA within 9 months of 

promulgation of the emission guidelines, unless the EPA 

specifies otherwise.623 The EPA is finalizing that each state 

must submit a final plan submittal to the EPA by August 31, 

2016, (13 months after the final rule). The state may submit a 

 

623 40 CFR 60.23(a)(1). 
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final plan submittal by this date, or seek an extension to 

submit a final plan by submitting an initial plan submittal. In 

this final rule the EPA is providing states with the option of 

up to a 2-year extension that will provide a total of 3 years 

for a state to develop and submit a final state plan to the EPA. 

To qualify for an extension of the August 31, 2016 deadline 

until August 31 2018, a state must submit an initial plan 

submittal by August 31, 2016, that documents the state’s plan 

for preparing a final plan submittal by 2018. The EPA is also 

finalizing that a state must submit one progress update by 

August 31, 2017. 

The EPA notes that the current implementing regulations at 

40 CFR part 60 do not specify who has the authority to make a 

formal submission of the state plan to the EPA for review. In 

order to clarify who on behalf of a state is authorized to 

submit an initial plan submittal, 2017 update, final state plan 

(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 
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EPA must be notified via letter from the Governor prior to the 

2016 deadline for plan submittal so that they have the ability 

to submit the initial or final plan submittal in the State Plan 

Electronic Collection System (SPeCS). If the Governor has 

previously delegated authority to make CAA submittals on the 

Governor’s behalf, a state may submit documentation of the 

delegation in lieu of a letter from the Governor. The letter or 

documentation must identify the designee to whom authority is 

being designated and must include the name and contact 

information for the designee and also identify the state plan 

preparers who will need access to SPeCS discussed in section 

VIII.E.7. A state may also submit the names of the state plan 

preparers via a separate letter prior to the designation letter 

from the Governor in order to expedite the state plan 

administrative process. Required contact information for the 

designee and preparers includes the person’s title, organization 

and email address. The EPA recommends this information be 

submitted early in the state planning process to allow 

sufficient time for completion of SPeCS registration so that 

those authorized to use the system are provided access. 

An initial plan submittal must include the components of a 

final plan submittal described in section VIII.D. Based on these 

components, potential justifications for seeking extensions 
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include, among other things, a state’s required schedule for 

legislative approval and administrative rulemaking, the need for 

multi-state coordination in the development of an individual 

state plan, additional time needed for the development of RE or 

demand-side EE programs in low-income communities, and process 

and coordination necessary to develop a multi-state plan. 

As previously discussed, because certain communities have a 

potential likelihood to be impacted by state plans, the EPA 

believes that the existing public participation requirements 

under 40 CFR 60.23 are effectuated for the purposes of this 

final rule by states engaging in meaningful, active ways with 

such communities. Therefore, as part of its overall evaluation 

of whether the initial submittal justifies granting an extension 

for submission of the final plan, the EPA is requiring that 

states seeking an extension until 2018 must actively engage with 

communities with a potential likelihood of being adversely 

impacted by state plans, including low income communities and 

communities of color, throughout the state plan development 

process. In order to demonstrate to the EPA that states are 

actively engaging with affected communities, states must provide 

in their initial plan submittal a summary of how they have been 

engaging with community stakeholders and how they intend to 

meaningfully engage with community stakeholders during the 
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additional time (if an extension is granted) for development of 

the final plan. In particular, states must document meetings and 

interactions that they have had with affected communities. 

Furthermore, states in their initial plan submittal and 2017 

update must show how they identified low income and communities 

of color that they are conducting meaningful community 

engagement with in the state plan development process. 

For some recommendations on the steps that states could 

take to engage communities in a meaningful way, the agency 

recommends that states consult the EPA’s Interim Guidance on 

Considering Environmental Justice During the Development of an 

Action. In this document, the EPA defines meaningful 

involvement, as ensuring that, “potentially affected community 

members have an appropriate opportunity to participate in 

decisions about a proposed activity that will affect their 

environment and/or health; the public’s contribution can 

influence the regulatory agency’s decision; the concerns of all 

participants involved will be considered in the decision-making 

process; and the decision-makers seek out and facilitate the 

involvement of those potentially affected.”624 Additionally, this 

 

624 Interim Guidance on Considering Environmental Justice During 

the Development of an Action. 

http://www.epa.gov/environmentaljustice/resources/policy/ejrulemaking.html. July 2010. 
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guidance document also encourages those writing rules consider 

the positive impacts that a rulemaking will have on 

communities).625 Another resource that the EPA recommends that 

states consult when devising their state plans is the 

Considering Environmental Justice in Permitting resources 

available on the agency’s website.626 Both of the resources 

discussed above will provide states with assistance on how to 

effectively engage communities in the rulemaking process. 

The EPA recommends that as part of their meaningful 

engagement with affected communities, that states work with 

affected communities to ensure that they have a clear 

understanding of the benefits and potential adverse impacts that 

a state plan might have on their communities and that there is a 

clear process for states to respond to input from communities. 

If no affected EGU is located within a state, the state 

must submit a letter to the EPA certifying that no such 

facilities exist by August 31, 2016.627 The EPA will publish a 

notice in the Federal Register to notify the public of receipt 

of such letters. 

If a state submits an acceptable initial plan submittal by 

 

625 Ibid. 

626 Considering Environmental Justice in Permitting. 

http://www.epa.gov/environmentaljustice/planej/permitting.html#actions. 

627 40 CFR 60.23(b). 
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August 31, 2016, as specified in the plan guidelines, then the 

deadline extension for submitting a final plan submittal that 

the state requested will be deemed granted. If the EPA 

determines that the initial plan submittal does not meet the 

guidelines, the EPA will notify the state by letter, within 90 

days, that the agency cannot approve the extension request based 

the state’s initial plan submittal as submitted. The EPA will 

notify a state by letter only if the initial plan submittal does 

not meet the guidelines. An extension for submitting a final 

plan submittal will be deemed granted if the EPA does not deny 

the extension request based on the initial plan submittal. The 

EPA has determined this approach is authorized by, and 

consistent with, 40 CFR 60.27(a) of the implementing 

regulations. 

 In the proposal, EPA proposed an initial 13 month 

submittal, with a 1-year possible extension for states 

submitting plans on their own and a 2-year possible extension 

for states submitting as part of a multi-state region. The EPA 

received substantive comment on the achievability of these 

proposed deadlines for state plan. Multiple commenters expressed 

concern that due to timing of legislative cycles (some of which 

are every 2 years), regulatory processes, and other necessary 

tasks, states would find it extremely difficult, if not 
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impossible, to submit plans in 1 or 2 years, whether or not they 

were planning to submit as part of a multi-state region. The EPA 

agrees that a schedule shorter than 3 years will be extremely 

challenging for many — though not all - states. We note that the 

CAA provides multiple years for states to complete other types 

of plans, such as those under CAA section 110, that are similar 

(or less) in scope and complexity than these plans. In light of 

the comments received and in order to provide maximum 

flexibility to states while still taking timely action to reduce 

CO2 emissions, in this final rule the EPA is allowing for an 

extension until 2018 for both individual and multi-state plans. 

This 2-year extension is contingent upon a state submitting a 

detailed description of steps already taken, a detailed 

description of additional actions to be taken in order to meet 

the 2018 plan submittal date and the initial 2022 compliance 

deadline and a schedule for those actions. This 2-year extension 

is also contingent upon the state submitting an acceptable 2017 

update by August 31, 2017 that documents the state’s continued 

progress towards meeting the 2018 submittal deadline. If the 

state does not submit an acceptable 2017 update by August 31, 

2017, the state will have failed to meet the conditions for the 

2-year extension and the EPA will develop a federal plan unless 

the state submits a final plan during this time. The EPA is also 
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clarifying the requirements for approvable initial plan 

submittals and 2017 updates, which can be found in section 

VIII.E.3. 

3. Components of an initial state plan submittal and 2017 update 

and approvability criteria 

As noted, if a state is unable to prepare and submit a 

final plan submittal by August 31, 2016, the state must make an 

initial plan submittal by that date and may request up to a 2-

year extension to submit a final plan. To be approved, the EPA 

is finalizing that the initial plan submittal must address all 

components of a final plan submittal, including identifying 

which components are not complete. For incomplete components, an 

approvable initial plan submittal must contain a comprehensive 

roadmap outlining the path to completion, including milestones 

and dates. 

During the public comment period, multiple commenters 

stated that the proposed timeframe for states to submit an 

approvable initial state plan submittal was not achievable, 

citing, among other things, the amount of decisions needed to be 

made by a state or states, and that the EPA needed to clarify 

the requirements for submitting an approvable initial state plan 

submittal. Multiple commenters also expressed concern that the 

requirements for an approvable initial plan submittal required 
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final decisions to be made by states, and that the initial plan 

submittal deadline was not enough time for states to make these 

decisions. In order to address the commenters’ concerns, the EPA 

is finalizing that in order to be approvable, an initial state 

plan submittal must address all components of a final plan 

submittal, including identifying which components are not 

complete, and include the following information: 

 All components of a final plan, including which 

components are not complete. 

 A justification for seeking an extension. 

 A description of the plan approach (e.g., single or 

multi-state, CO2 emission performance rates or state CO2

rate or mass emission goal) 

 A commitment to maintain existing measures that limit or 

avoid CO2 emissions (e.g., RE standards), at least until 

the final plan is approved. 

 A comprehensive roadmap with a schedule and milestones 

for completing the plan, including progress to date in 

developing a final plan and steps taken in furtherance of 

actions needed to finalize a final plan. 

 Demonstration of opportunity for public comment on 

submittal and response to significant comments, and 

meaningful engagement with affected communities likely to 
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be impacted by the state plan. 

As stated above, the EPA is finalizing that the initial 

plan submittal must address all components of a final plan 

submittal, including identifying which components are not 

complete. For incomplete components, an approvable initial plan 

submittal must contain a comprehensive roadmap outlining the 

path to completion, including milestones and dates. 

The EPA proposed that approvable justifications for seeking 

an extension beyond 2016 for submitting a final plan include: a 

state’s required schedule for legislative approval and 

administrative rulemaking, the need for multi-state coordination 

in the development of an individual state plan, or the process 

and coordination necessary to develop a multi-state plan. In 

this final rule, the EPA is finalizing these as acceptable 

justifications for seeking an extension beyond 2016. Although 

legislation and/or regulations do not need to be passed prior to 

the initial plan submittal in order to be granted an extension, 

the initial plan submittal must include any concrete steps the 

state has already taken on legislation and/or administrative 

rulemaking and detail what the remaining steps are in those 

processes before a final plan submittal can be submitted. The 

EPA also sought comment on other circumstances for which an 

extension of time would be appropriate, and also whether some 
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justifications for extensions should not be permitted. 

Commenters stated that states should be able to seek extensions 

whenever an extension can be reasonably justified, and that the 

EPA should take at face value states’ good faith efforts by 

accepting any state assertion that more time is needed to 

develop a plan unless there is clear evidence to the contrary. 

The EPA does not agree with the assertion that any reason 

provided by a state should automatically be deemed as an 

acceptable justification for being granted an extension. The EPA 

is not finalizing other justifications in this final rule, 

however, the EPA will evaluate the appropriateness of other 

justifications not listed here during review of the initial 

state plan submittals. 

For descriptions of plan approaches, states must include a 

basic outline of the approach used to meet the state’s CO2

emission goals or the CO2 emission performance rates. This should 

include, at a minimum, whether the state is choosing the option 

of the CO2 emission performance rates, a rate-based CO2 goal, or 

a mass-based CO2 goal, and whether the state is pursuing a 

single-state or multi-state plan. Stakeholders commented that 

states will not be far enough along in the rule development 

process to have made these decisions. Commenters also stated 

that many state legislatures would need to pass legislation 
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giving state environmental agencies legal authority and 

direction before they could begin to make decisions such as rate 

or mass-based approach or single or multi-state plan submittal. 

In order to address the commenters’ concerns, the EPA wishes to 

clarify that state approaches in the initial state plan 

submittal do not need to be final and/or formalized through a 

state legislature, and that states may opt to pursue more than 

one approach at the same time. In order to fulfill the 

requirement for a description of the plan approach, the initial 

plan submittal may include the various compliance options a 

state or group or states is exploring and a detailed schedule 

outlining the process for making decisions necessary to meet the 

deadline for final plan submittal. 

The EPA received substantive comment regarding the 

potential adverse consequences for states pursuing a multi-state 

approach and receiving an extension until 2018, where, for 

various reasons, a state or states then decide(s) to back out of 

the multi-state plan and pursue the single state approach. 

Commenters viewed this as being potentially problematic since, 

as proposed, a single state could only receive an extension 

until 2017, and if a multi-state plan effort does not work out 

the deadline for seeking the extension until 2017 would have 

passed. Finalizing a 2-year extension that is available for any 
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state, whether they are pursuing an individual state plan or a 

multi-state plan resolves the commenters’ concern about 

conflicting extension deadlines if states involved in a multistate effort decide not to pursue the multi-state approach. 

In order for a state’s initial plan submittal to be 

approvable, the EPA is finalizing that the initial submittal 

must contain a commitment to maintain existing measures, such as 

RE standards and demand-side EE programs, at least until the 

final plan is approved. The EPA could not in good faith agree 

with a state’s rationale for needing more time to develop a 

final state plan while at the same time the state was removing 

already in place measures that reduce CO2 emissions from EGUs. 

An initial state plan submittal must also include a 

description of the progress a state has made in the development 

of a final plan submittal as well as a comprehensive roadmap for 

completing the plan. This includes a schedule with milestones 

and dates. The milestones should outline the state’s path to 

submitting a final plan by August 31, 2018. 

The EPA is finalizing the public comment requirements that 

were outlined in the proposal for initial plan submittals. Prior 

to submittal to the EPA, the state must provide an opportunity 

for public comment on a substantial draft of its initial plan 

submittal. This public comment opportunity will not be governed 
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by the procedural requirements of the implementing regulations 

that apply to the state’s adoption of a final plan, such as the 

requirement that the state hold a public hearing. 40 CFR 

60.23(c)-(f). An initial plan submittal might not include any 

legally enforceable provisions that the state would have adopted 

through its administrative or legislative processes, which 

generally provide for public input. Therefore, to ensure that 

the public has an opportunity to understand and inform the 

initial plan submittal, the final rule requires that prior to 

submittal on August 31, 2016, the state must have provided a 

reasonable opportunity for public comment on a substantial draft 

of the initial plan submittal, with notice to the EPA of that 

comment period. 

The EPA can use this comment opportunity to advise the 

state whether it is on track to submit an approvable initial 

plan submittal. The comment period on the initial plan submittal 

is only one opportunity the EPA has to assist a state in the 

state plan development process. The EPA has historically worked 

with states throughout the state plan development process to 

help ensure that the state plan is approvable once submitted to 

the EPA, and expects this level of engagement with states to 

continue for this final rule. When the state submits its initial 

plan submittal, it must provide the EPA with a response to any 
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significant comments it received on issues relating to the 

approvability of the initial plan so that the EPA can fully 

assess whether it is approvable. 

For states participating in a multi-state program, the 

initial plan submittal must include the elements described above 

as well as any executed agreements among the participating 

states and a road map for both design of the multi-state program 

and its implementation at the state level. A multi-state initial 

plan submittal should also address situations where states may 

join together on only certain elements, such as RE, or standards 

on subsets of EGUs. 

In this final rule, the EPA is allowing states up to 3 

years to submit a final plan. This is contingent upon submitting 

an acceptable initial plan submittal and 2017 update. The 2017 

updates will ensure that a state is making continuous progress 

on its initial plan and that a state is on track to meet the 

final plan submittal deadline of August 31, 2018. The EPA is 

requiring that the 2017 update must contain the following 

components: 

 A summary of the status of each component of the final 

plan, including an update from the 2016 initial plan 

submittal and a list of which components are not 

complete. 
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 A commitment to a plan approach (e.g., single or multistate, rate or mass emission performance level), 

including draft or proposed legislation and/or 

regulations. 

 An updated comprehensive roadmap with a schedule and 

milestones for completing the plan, including progress to 

date in developing a final plan and steps taken in 

furtherance of actions needed to finalize a final plan. 

In order to assess if a state is on track to submit a final 

plan by the 2018 extension deadline, the EPA is requiring that 

the 2017 update must contain a summary of all components of a 

final plan, including a progress update on any incomplete 

components from the initial plan submittal, and a list of which 

components are still not complete. This progress update must 

demonstrate that state has met the milestones and dates it 

outlined in its initial plan submittal. If a state has not met a 

milestone and date that it set in the initial plan submittal, or 

is not on pace to meet a future date, the state may revise its 

schedule in the 2017 update, provided that the schedule meets 

the 2018 deadline for final plan submittal. 

The EPA is also requiring that the 2017 update include a 

commitment to the type of plan approach the state will take in 

the final plan submittal. During the public comment period, many 
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commenters stated that legislative action would be required to 

enact this final rule at the state level, and that the proposal 

did not provide enough time for legislative action or other 

regulatory actions needed for a state to be granted an 

extension. In order to respond to these comments, the EPA 

clarified that proposed or passed legislation or regulations are 

not required in the initial plan submittal. While a state may 

pursue multiple types of state plans in the initial plan 

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. 

Finally, the EPA is requiring that the 2017 update include 

an updated comprehensive roadmap with a schedule and milestones 

for completing the plan. Similar to the requirement that the 

2017 update must include all components of a final plan, the 

update must include a demonstration that the state met the 
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milestones for submitting a final plan that were outlined in the 

initial plan submittal. For any milestones that were not met, 

the state must provide a justification for not meeting the 

milestone and an updated schedule that demonstrates that the 

state is still on pace to meet the 2018 final plan submittal 

deadline. 

The EPA will assess a state’s 2017 update and, similar to 

the process for the initial plan submittal, notify the state 

within 90 days if the EPA determines that the state is not 

likely or able to meet the 2018 final plan submittal deadline. 

In the event that the EPA makes this determination for a state, 

the EPA will begin the federal plan development process to 

enforce and implement in the state. 

4. Process for EPA review of state plans 

Our proposal laid out the basic steps for EPA’s review and 

action on submitted state plans and, at some length, discussed 

the required components of state plans, as further described in 

the preceding sections. We received a number of thoughtful and 

helpful comments on these issues. We are finalizing the basic 

requirements in this rule and are proposing, in the companion 

proposed federal plan under section 111d, some additional 

procedural elements we believe will be helpful to states, 

stakeholders and the EPA moving forward. 
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Following the August 31, 2016 deadline for state plan 

submittals, the EPA will review plan submittals for 

approvability. For a state that submits an initial plan 

submittal by August 31, 2016, and requests an extension of the 

deadline for the submission of a final state plan submittal, the 

EPA will determine if the initial plan submittal meets the 

minimum requirements for an initial plan submittal. If the 

initial plan 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 August 31, 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, similar to that used for approving 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 
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generally consistent with the timing requirements of section 110 

with respect to complete SIP submittals. Such a timeline would 

also provide the EPA with adequate time for review and 

rulemaking procedures, and ensuring an opportunity for public 

notice and opportunity for comment. We note, however, that we 

did not propose this timeline for review and action on state 

plans in our proposal, and, in particular, starting the 12 month 

review period from the date of receipt of a complete 

submission.628 Therefore, we intend to propose the appropriate 

revisions to the implementing regulations as part of the 

upcoming federal plan proposal for section 111(d). 

 In addition, while the CPP proposal and this final rule 

lay out in considerable detail the required components of a 

state plan, the EPA believes that it would also be helpful to 

include in the rule a completeness determination process, 

similar to that used for SIP submittals in section 110, which 

will allow the EPA to determine whether a final plan submittal 

contains the components necessary to enable the EPA to determine 

through notice and comment rulemaking whether such submittal 

complies with the requirements of section 111(d). This is a 

procedural requirement under CAA section 110(k)(1), and the EPA 

 

628 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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believes this requirement is appropriate to establish under 

section 111(d)’s direction of the EPA to prescribe through 

regulations a procedure similar to that provided by section 110. 

However, because the EPA did not propose such regulations as 

part of the proposal for this action, the EPA intends to do so 

as part of the upcoming Federal Plan proposal for section 

111(d). The EPA notes the components of state plans as laid out 

in section VIII.D and the final rule are 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 allow the EPA to identify whether there are 

absent or insufficient components in the plan submittal that 

would render the EPA unable to act on such submittal because it 

is incomplete. As will be further explained in the upcoming 

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 

approval/disapproval and conditional approval mechanisms in 

section 110(k)(3) and (4) to the procedure for acting on section 
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111(d) plans. The input the agency got in response to the 

proposal for these guidelines indicated that the flexibility 

provided by these mechanisms could be useful getting state plans 

in place. So, the EPA expects to propose to amend the 

implementing regulations as part of the rulemaking for the 

federal 111(d) plan. The EPA is not taking final action on these 

changes in this action. 

 Deferring 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. 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 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. 

5. Failure to submit a plan 
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If a state fails to submit a final plan submittal by the 

applicable deadline, or submits a final plan the EPA determines 

to be incomplete, the EPA will notify the state by letter of its 

failure to submit. The EPA will publish a Federal Register

notice informing the public of its finding of failure to submit. 

Upon a finding of failure to submit for a state, a statutory 

clock will run requiring the EPA to promulgate a federal plan 

for such state no later than 2 years after the EPA makes the 

finding unless the state submits, and the EPA approves, a state 

plan during this time. 

6. 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 measures with new 

measures. The EPA received broad support for allowing states to 

submit modifications to approved state plans. In this 

rulemaking, the EPA is finalizing that a state or states may 

revise its state 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 compliance timeframes in this 

final rule and flexibility provided to states in developing 
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state plans will lessen the need for modifications to approved 

state plans. 

The EPA solicited comment on whether, for new projections 

of emission performance, 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; 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. 

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 may be adjusted to 

address inventory changes within a state’s fleet. If these 
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changes occur before a state submits its initial or final plan, 

the state should indicate in its submittal the circumstance that 

necessitates the goal adjustment and the revised interim or 

final CO2 emission goal. If the circumstances occur after a state 

has an approved plan, a state must submit a modification to its 

approved plan. The plan revision submittal must indicate the 

circumstance that necessitates the goal adjustment, the revised 

interim and/or final CO2 emission goal, and the adjustments to 

the enforceable measures in the plan. 

As discussed in more detail in section VIII.H, the final 

rule has several measures to ensure reliability. One such 

measure is that if a state cannot address a reliability issue 

within the boundaries of an approved state plan and the built-in 

reliability contingencies are not adequate to address 

reliability related issues that arise, the state can submit a 

request to the EPA to amend the timeframe over which reductions 

must be made in its plan. See section VIII.H for a more detailed 

discussion of this issue. 

7. Plan templates and electronic submittal 

The EPA is finalizing the requirement for states to 

electronically submit a negative declaration, state plan 

submittals, including any supporting materials that are part of 

a state plan submittal and any state reports required by the 
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state plan. The rule provides that files that are submitted to 

the EPA in an electronic format may be maintained by states in 

an electronic format. The submission of the information by the 

authorized official must be in a non-editable format. In 

addition to the non-editable version, the EPA is also requiring 

that all plan components designated as federally enforceable 

must be submitted in an editable version as well, as discussed 

below. 

a. Submittal of an editable version of federally enforceable 

plan components. To ensure that the EPA has the ability to 

identify, evaluate, merge, update and track federally 

enforceable plan components in a timely and comprehensive 

manner, the EPA is requiring states to submit an editable copy 

of the specific plan components in their submittal 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. Plan revisions. Following initial plan approval, 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 
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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. 

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 will preregister 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. 
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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 

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 
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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/. If a 

plan submittal includes confidential business information (CBI) 

it will also be required to be electronically submitted. 

Although the likelihood that CBI will be submitted as part of 

the state plan submittal is low, the EPA intends to ensure that 

the system is capable of supporting submittal of all the types 

of information that may be associated with a state plan. 

Material claimed as CBI will be flagged by the state in the 

electronic system as such, then uploaded and stored separately 

in the encrypted CROMMERR archive. Authorized staff will 

retrieve CBI for storage and management at the EPA’s CBI Office. 

The EPA received a number of comments on the electronic 

submittal of state plans. Some commenters preferred the option 

to submit electronically rather than the requirement to do so. 

In the final rule, for the reasons discussed below, the EPA is 

requiring electronic submittal of state plans and not allowing 

alternate options for plan submittal (e.g. paper submittal). 

Requiring electronic submittal is in keeping with current 
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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. 

In the proposal, the EPA requested comment on the creation 

of templates for initial and final state plan submittals. 

Multiple commenters requested the EPA provide state plan 

templates. One commenter requested templates for different plan 
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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 decided not to develop templates for 

state plan submittals at this time given the broad range of 

approaches states may take in preparing individual or multistate plans. However, the EPA does believe that states may use 

the Federal Plan as a template when preparing state plan 

submittals. The EPA will continue extensive outreach to states 

and work closely with states on the need for additional tools 

and guidance to facilitate the development of approvable state 

plans. 

8. Legal issues regarding state plan process 

Section 111(d)(1) requires the EPA to promulgate procedures 

“similar” to those in section 110 under which states adopt and 

submit 111(d) plans. The EPA has interpreted this provision 

previously in the implementing regulations found in 40 CFR part 

60 subpart B. As discussed above, the EPA intends that planned 

revisions to the part 60 implementing regulations will clarify 

(among other things) whether certain procedures are appropriate 

for the EPA’s action on 111(d) state plans, and if so, precisely 
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how those procedures should apply. The EPA is proposing these 

revisions to the 111(d) implementing regulations in the notice 

of proposed rulemaking for the federal plan being issued 

concurrent with this final rule. In this section we discuss the 

legal basis for procedures that the EPA is finalizing in this 

action: initial plan submittals, extensions, and plan revisions. 

 First, we generally discuss the ambiguous word “similar.” 

“Similar” does not have an identical meaning as the word “same.” 

Webster’s Third New International Dictionary defines “similar” 

as “having characteristics in common, very much alike” or “alike 

in substance or essentials.” Webster’s Third New International 

Dictionary 2120 (1993). On the other hand, “same” is defined as 

“resembling in every way, not different in relevant essentials,” 

“conforming in every respect,” or “corresponding so closely as 

to be indistinguishable.” Id. at 2007. 

 Thus, 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” 
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certain other procedures). Therefore, Congress must have 

intended to give the EPA leeway to create procedures for section 

111(d) state plans that somewhat vary from those in section 110, 

so long as the section 111(d) procedures are reasonably tied to 

the purpose and text of section 111(d). In other words, 

“similar” creates a gap in the statute that the EPA may 

reasonably fill. 

a. Initial plan submittals and extensions. Section 110 does not 

provide for initial plan submittals. As explained above, though, 

we are not bound under section 111(d)(1) to follow exactly the 

same procedures. Initial plan submittals in this instance are a 

reasonable gap-filling device. As explained in our proposal, 

certain aspects of section 111(d) plan development for these 

particular guidelines warrant our creation of this device. 

 With respect to the timing of initial plan submittals, 

final submittals, and extensions, we note that section 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. Section 110(a)(1) does not provide any particular 

factors for the Administrator to consider in prescribing a 

shorter period. Thus, the EPA’s prescription of a shorter period 

for either an initial plan submittal or a final plan submittal 
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is consistent with the discretion granted in section 110(a)(1). 

We also note that section 110(b) provides for extensions of up 

to 2 years for plans to implement secondary NAAQS, that other 

provisions in part D provide for extensions of due dates of 

attainment plans in certain circumstances, and that the section 

111(d) implementing regulations provide for extensions 

generally. We conclude, in view of the above discussion of 

“similar,” that the device of initial plan submittals and 

extensions of due dates as proposed is a reasonable procedure 

that, while not identical to the procedures in section 110, is 

still similar. 

 Some commenters argued that the 1-year period for initial 

plan submittals and, even assuming an extension, the additional 

1- to 2-year period for final submittals were unreasonable, 

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 plan 

submittals by allowing states to identify remaining legislative 

action in those submittals. 

 With respect to the overall period of up to 3 years for 

submittals, we continue to find it reasonable and consistent 
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with other deadlines in the CAA. First, section 110(a)(1) 

requires states to submit a plan for implementation, 

maintenance, and enforcement of new NAAQS within 3 years of 

promulgation of that NAAQS. This is true even if the EPA 

promulgates a NAAQS for a previously non-criteria pollutant. In 

that case, it is possible and even likely that at least some 

state agencies will lack statutory authority to regulate the new 

pollutant. Nonetheless, Congress dictated that states should 

submit section 110(a)(1) plans within 3 years. 

 Furthermore, we note that under subpart 1 of Part D of 

Title 1, attainment plans are generally due no later than 3 

years after designation of a nonattainment area, and under other 

subparts of Part D, plans are due even more quickly. For 

example, under subpart 4, attainment plans for particulate 

matter are generally due 18 months after designation, and under 

subpart 5, the same deadline applies for attainment plans for 

sulfur oxides, nitrogen dioxide and lead. While developing 

attainment plans may not require states to seek additional 

legislative authority, 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), 
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control measures for those sources (including individualized 

control measures for the larger sources), and modelled 

demonstrations of attainment (which in some instances requires 

photochemical grid modeling). Thus, it is reasonable to have the 

same timeline for these section 111(d) plans as Congress 

generally provided for attainment plans in section 172(b). 

b. State plan modifications. Section 110(l) provides for states 

to revise their SIPs, as does 40 CFR 60.28 for section 111(d) 

plans. Section 110(l) also sets out a standard for revisions: it 

prohibits the EPA from approving a SIP revision that would 

interfere with any applicable requirement concerning attainment 

or reasonable further progress, or any other applicable 

requirement of the CAA. Under the existing section 111(d) 

implementing regulations, the Administrator will disapprove 

section 111(d) plan revisions as unsatisfactory when they do not 

meet the requirements of subpart B to part 60. See 40 CFR 

60.27(c)(3). However, the implementing regulations do not set 

forth a substantive standard like that in section 110(l). 

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. It is reasonable, at a minimum, that the state 
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plan as revised should continue to provide for implementation 

and enforcement of the standards of performance, and to achieve 

the CO2 emission performance rates or state CO2 emission 

performance goal. This is analogous to the substantive 

requirements of section 110(l), which as explained above for 

section 110(a)(2), we may consider in determining how to 

reasonably fill statutory gaps for section 111(d) plans. 

In our proposal, we proposed 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 
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taken a similar approach to tailoring the requirements for a 

technical demonstration that, under section 110(l), a SIP 

revision does not interfere with any applicable requirement 

concerning attainment of the NAAQS. If a SIP revision does not 

relax the stringency of any SIP measure, then the demonstration 

is simple. If the SIP revision does relax the stringency of SIP 

measures, then a qualitative or quantitative analysis may be 

necessary to show non-interference, depending on the nature of 

the revision, the current air quality in the area, and other 

factors. 

Finally, we proposed that revisions “should not result in 

reducing the required emission performance for affected EGUs 

specified in the original approved plan. In other words, no 

‘backsliding’ on overall plan emission performance through a 

plan modification would be allowed.” 79 FR 34917/1. We received 

adverse comments that this standard did not have a basis in 

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 

performance emission rates or goal, the same standard should 

apply to revisions. In other words, the standard for revisions 

should be whether the plan as revised is satisfactory. We 
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believe that our proposal was unclear as to this point and we 

agree that the same standard for revisions should be the same as 

for submittals. We have finalized this position. 

F. State Plan Performance Demonstrations 

This section describes state plan requirements related to 

compliance periods, monitoring and reporting for affected EGUs; 

plan performance demonstrations; and consequences if the CO2

emission performance rates or state CO2 emission goals are not 

met. 

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 
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period for the backstop emission standards must begin no later 

than January 1, 2027, and end on December 31, 2027. The next 

compliance period for the backstop emission standards would be 

January 1, 2028-December 31, 2029. 

In the June 2014 proposal, the EPA proposed that the 

appropriate averaging time for any rate-based emission standard 

for affected EGUs be no longer than 12 months within a plan 

performance period and no longer than 3 years for a mass-based 

standard. The EPA solicited comments on longer and shorter 

averaging times for emission standards included in state plans. 

The EPA received comments stating that the proposed 12 month 

averaging was too short and that there was no reason why the 

compliance period under a rate-based plan should be different 

from a mass-based plan. Comments stated that a multi-year 

averaging period is appropriate for rate-based and mass-based 

plans to account for variations that can occur in a single year, 

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 indicated above, which 

respond to the comments by applying to both rate- and mass-based 
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programs, providing compliance periods longer than one year, and 

establishing block compliance periods rather than a rolling 

average approach. We agree with comments that longer averaging 

periods allow for operational and seasonal variability to even 

out and provide a basis for emissions reductions that are more 

realistic than short term averaging might otherwise demonstrate. 

The EPA finalizes that states can choose to set shorter 

compliance periods for their emission standards but no longer 

than the compliance periods the EPA is finalizing in this 

rulemaking. The EPA recognizes that the compliance periods 

provided for in this rulemaking are longer than those 

historically and typically specified in CAA rulemakings. As 

reflected in long-standing CAA precedent, “[t]he 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.” 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, 
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and this rulemaking is focused on performance standards related 

to those long-term impacts. The distinction between these unique 

characteristics and the EPA’s long-standing practice regarding 

compliance periods is bolstered by the EPA guidance on 

appropriate averaging periods for emission limitations in NAAQS 

implementation. For example, the EPA guidance has stated that in 

implementation of the ozone standards, which have a short 

averaging period, the averaging period for VOC emission 

limitations should be correspondingly short. See 51 FR 43857. A 

longer averaging period for VOC emission limitations 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 longlived 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 
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the applicable reporting requirements for sources under the 

state plans in the final rule. States must require all affected 

EGUs to monitor and report hourly CO2 emissions and net energy 

output (including total net MWh output that is comprised of 

generation, and where applicable, useful thermal output 

converted to net MWhs) to the EPA on a quarterly basis in 

accordance with 40 CFR part 75. Note that this requirement 

applies for all types of state plans, regardless of whether the 

state chooses the option of the CO2 emission performance rates, a 

state rate-based CO2 emission goal, or a state mass-based CO2

emission goal. 

In the June 2014 proposal, the EPA proposed that state 

plans must include monitoring, reporting and recordkeeping 

requirements for useful energy output from affected EGUs. 

Multiple commenters questioned whether gross rather than net 

electrical production should be reported by affected EGUs and 

recommended that the EPA should utilize gross rather than net 

generation. Many commenters recommended electricity to be 

reported in the form used in the 111(b) rules for consistency 

between reporting requirements and simplification of calculation 

of emission limitations between new and old sources. Commenters 

also stated that to the extent the EPA seeks to provide guidance 

to states regarding its preferred monitoring and reporting 
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procedures, the EPA should encourage states to avoid imposing 

additional monitoring and reporting burdens by taking advantage 

of the monitoring requirements that already exist to the 

greatest extent possible. For example, the commenters noted that 

the 40 CFR part 75 monitoring procedures used to comply with 

other programs, such as the Title IV Acid Rain Program, provide 

much of the data that would be needed to demonstrate compliance 

under the rule. Comments stated that the June 2014 proposal 

appeared to mandate a monitoring approach that would eliminate 

key flexibilities provided in the part 75 regulations, thus 

requiring utilities to maintain separate document collection and 

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) 
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address the issue of duplicative requirements and alleviate 

concern about lost flexibilty raised by commenters. 

2. Plan performance demonstrations 

The state plan must include emission performance checks, 

and for state measures plans, periodic program implementation 

milestones. The state plan must provide for tracking of emission 

performance, and for measures to be implemented if the emission 

performance of affected EGUs in the state does not meet the 

applicable CO2 emission performance rates or state CO2 emission 

goal during a performance period. 

 As discussed previously 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 on average over the 

2022-2029 interim period, and over three interim steps of 2022-

2024, 2025-2027 and 2028-2029. 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 
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section VIII.F.3 below. States must demonstrate that the interim 

steps were achieved, on average during the interim step periods, 

at the end of each interim step. 

 In 2032 and every 2 years thereafter, states must 

demonstrate that affected EGUs achieved the final performance 

rates or state goal on average 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 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 output629 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 of the 

 

629 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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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). 

 The EPA notes that for certain types of emission standards 

plans, with mass-based emission standards in the form of an 

emission budget trading program, achievement of a state’s massbased CO2 goal (including interim step goals and final goal) will 

be assessed by the EPA based on compliance by affected EGUs with 

their emission standards under the program, rather than CO2

emissions during a specific interim step period or final period. 

As discussed in section VIII.C.3.b.(2)(a), 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.630 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 massbased CO2 goal during an individual plan performance period, but 

 

630 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 

two-year plan performance periods. 
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on a cumulative basis CO2 emissions from affected EGUs would not 

exceed what is allowable if the interim and final CO2 goals are 

achieved. 

 Also as discussed in section VIII.D, states that choose a 

state measures plan must submit an annual report no later than 

July 1 following the end of each calendar year in the interim 

period. This annual report must include the status of the 

implementation of programmatic milestones identified in the 

state plan submittal. The annual report that follows the end of 

each reporting period (i.e., 2022-2024, 2025-2027, and 2028-

2029) must also include an emissions performance comparison for 

the reporting period, as described above for the emissions 

standards plan. Beginning with the final period of 2030 and 

onward, states using a state measures plan must submit a 

biannual report no later than July 1 following the end of each 

reporting period with an emission performance comparison for 

each reporting period, consistent with the reporting 

requirements for emission standards plans. 

In the June 2014 proposal, the EPA proposed that a state 

report is due to the EPA no later than the July 1 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 
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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 

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 
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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 

actual emission performance under a state plan does not meet, or 

is not on track to meet, the applicable interim and interim step 
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CO2 emission performance rates or state goals in 2022–2029, or 

does not meet the applicable final CO2 emission performance rates 

or state CO2 emission goal in 2030–2031 or later. For emission 

standards plans, the final rule specifies that corrective 

measures must be enacted once triggered.631 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 states using the emission standard approach, if actual 

CO2 emission performance by affected EGUs exceeds the specified 

level of emission performance in the state plan by 10 percent or 

more during any of the specified interim step reporting periods 

or during a final plan reporting period (after 2030), the state 

report must include a notification to the EPA that corrective 

 

631 As in the proposal preamble, the EPA continues to note that 

some types of plans are “self-correcting” in that they 

inherently would assure interim performance and full achievement 

of the state plan’s required level of emission performance 

through requirements that are enforceable against affected EGUs. 

One example is a state plan with a rate-based emission 

performance level that requires affected EGUs collectively to 

meet an emission rate consistent with the state’s required 

emission performance level, and allows EGUs to comply through an 

emission trading program. Such plans presumably would not 

trigger or require corrective measures. 
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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. 

After an exceedance by 10 percent or more, 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 deficiency that occurred during a performance 

period. The state must submit the revised plan to the EPA within 

24 months after submitting the state report indicating the 

exceedance. 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. 

For states using the state measures approach, the EPA is 

finalizing the backstop requirement as described in section 

VIII.C.4.b 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–
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2031 or later, or the CO2 emission performance rates, is based on 

checks that must be included in state reports that must be 

submitted annually during the interim period and biannually 

during the final period. The state must report any failure to 

meet programmatic milestones during the interim period. In 

addition, the state must report actual performance checks, 

similar to the requirements discussed above for emission 

standards plans. 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 actual CO2

emission performance by affected EGUs exceeds the specified 

level of emission performance in the state plan submittal by 10 

percent or more, 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.

Multiple commenters requested that corrective measures not 

be required in the case of a catastrophic, uncontrollable event. 

We recognize the possibility that an un-anticipatable system 

emergency could cause a severe stress on the electricity system 

for a length of time such that the multi-year requirements in a 
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state plan may not be achievable by given EGUs without posing an 

otherwise unmanageable risk to reliability. We are finalizing a 

reliability safety valve that will allow a state to modify the 

emission standards for such EGUs for a maximum of 90 days. The 

reliability safety valve will allow such EGUs to operate under 

the modified emission standards rather than the emission 

standards specified in the relevant state plan for that time 

period (including an exceedance that would otherwise trigger 

corrective measures under an emission standard plan type or an 

exceedance that would trigger a backstop under a state measures 

plan type), while still requiring the CO2 emission performance 

rates or the state CO2 emission goal to be met. While use of the 

reliability safety valve would preclude an applicable event from 

triggering corrective measures or a backstop during the safety 

valve period, the state must still make up for any emission 

reductions that were lost during the safety valve period. See 

section VIII.H.2.e of this preamble. 

Multiple commenters supported the inclusion of strong 

enforcement measures for ensuring the interim and final goals 

are met, including the required use of corrective measures when 

triggered. Other commenters provided feedback as to the 

percentage that actual emission performance would need to exceed 

the level of emission performance specified in the statewide 
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plan to trigger corrective measures. Some commenters supported 

the proposed trigger (actual emission performance that is not 

within 10 percent of the projected performance) that we are 

finalizing, while some recommended a lower trigger and others 

recommended a trigger higher than 10 percent exceedance. We have 

decided to finalize the trigger at 10 percent exceedance because 

we view 10 percent as both low enough to ensure that states that 

need corrective measures implement them before they exceed their 

specified level of emission performance to a degree that might 

be irreversible, and high enough that corrective measures are 

not triggered by fluctuations in emissions that do not indicate 

that a state may not be able to achieve its projected goal. 

The EPA requested comment on whether the agency should 

promulgate a mechanism under CAA section 111(d) similar to the 

SIP call mechanism in CAA section 110. Under this approach, 

after the agency makes a finding of the plan’s failure to 

achieve the CO2 emission performance rates or state CO2 emission 

goal during a performance period, the EPA would require the 

state to cure the deficiency with a new plan within a specified 

period of time. If the state still lacked an approved plan by 

the end of that time period, the EPA would have the authority to 

promulgate a federal plan under CAA section 111(d)(2)(A). 79 FR 

34830, 34908/1-2 (June 18, 2014). 
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The EPA intends that planned revisions to the part 60 

implementing regulations will clarify (among other things) 

whether the EPA has authority to call for plan revisions under 

section 111(d) when a state’s plan is not complying with the 

requirements of this guideline, and if so, precisely what 

procedures should apply. The EPA plans to propose these 

revisions to the 111(d) implementing regulations in the 

forthcoming notice of proposed rulemaking for the federal plan. 

The EPA is not taking final action now on this issue or the 

related change to the implementing regulations. 

a. Legal basis for corrective measures. The EPA discussed the 

concept of corrective measures in our 1992 General Preamble for 

the Implementation of Title I of the CAA Amendments of 1990. 57 

FR 13498 (Apr. 16, 1992). The General Preamble sets out four 

general principles that apply to all SIPs, “including those 

involving emissions trading, marketable permits and allowances.” 

Id. at 13568. The fourth principle, accountability, means (among 

other things) that “the SIP must contain means ... to track 

emission changes at sources and provide for corrective action if 

emissions reductions are not achieved according to the plan.” In 

the General Preamble, we noted that Part D of Title I explicitly 

provided for this in certain instances by requiring milestones 

and contingency measures. 
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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 

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 from the corrective 

measures in these guidelines in one important respect. Under 

these guidelines, the corrective measures must make up the 

difference by which the plan fell short of the goal. There is no 
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corresponding requirement in attainment planning to increase the 

stringency of the plan by an amount that somehow matches an 

amount by which the area failed to attain; instead the revised 

plan must demonstrate attainment, 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 

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.632 

 

632 Similar considerations apply to the requirement under the 

state measures approach to revise the plan to make up the 

shortfall. 
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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 certain types of 

emission standards plans to fill this gap with corrective 

measures. 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 
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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. 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. 

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 
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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 permanent or, through 

silence, authorized the EPA to reasonably require permanence. 

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 should continue to be maintained in the years after 2030. 

 As noted above, the state plan must demonstrate that plan 

measures are projected to achieve the final emission performance 

level by 2030. In addition, the state plan must identify 

requirements that continue to apply after 2030 and are likely to 

maintain affected EGU emission performance meeting the final 

goal. The state plan would be considered to provide for 

maintenance of emission performance consistent with the final 

goal if the plan measures used to demonstrate projected 

achievement of the final goal by 2030 will continue in force and 

not sunset. After implementation, the state is required to 

compare actual plan performance against the final goal on a 2-

year average basis starting in 2030, and to implement corrective 

measures or a backstop if triggered. 
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 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 

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 
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“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 

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, 
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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. 

G. Considerations for Incorporating CO2 Emission Reduction 

Measures in State Plans 

1. Accounting for emission reduction measures in state plans 

This section describes how measures that reduce CO2

emissions from affected EGUs may be counted in state plans. This 

includes accounting for measures that occur directly at affected 

EGUs, as well as measures that provide substitute generation for 
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affected EGUs or avoid the need for generation from affected 

EGUs. This latter category of measures may be used to adjust the 

CO2 emission rate of an affected EGU under a rate-based state 

plan. This adjustment may occur when an affected EGU is 

demonstrating compliance with a rate-based emission standard, or 

when a state is demonstrating achievement of the CO2 emission 

performance rates or applicable state CO2 emission goal in the 

emission guidelines.633 

It should be noted that under a mass-based plan, measures 

that provide substitute generation for affected EGUs or avoid 

the need for generation from affected EGUs are automatically 

accounted for to the extent that these measures reduce reported 

CO2 emissions from affected EGUs. Unlike under a rate-based plan, 

no additional accounting is necessary in order to recognize 

these emission reductions. 

Section VIII.G.1.a below addresses how emission reduction 

measures that occur at affected EGUs are counted in state plans. 

This includes measures that result in CO2 emissions reductions 

that are automatically accounted for in reported CO2 emissions 

and CO2 emission rates for affected EGUs, as well as other 

 

633 Under a state measures plan, as described in section 

VIII.C.4, a state may adjust the reported CO2 emission rate of 

affected EGUs when demonstrating achievement of the CO2 emission 

performance rates or applicable state CO2 emission goal in the 

emission guidelines. 
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emission reduction measures, in particular the use of CCS, CCU 

and biomass, that require additional accounting and reporting. 

Section VIII.G.1.b below addresses how emission reduction 

measures that provide substitute generation for affected EGUs or 

avoid the need for generation from affected EGUs are counted in 

rate-based state plans. This section describes the basic 

accounting method for adjusting a CO2 emission rate. The section 

also describes general eligibility requirements for measures 

that may be used for adjusting a CO2 emission rate, such as the 

requirement that the emissions-reducing action occur after 2012, 

which is necessary to maintain the integrity of the performance 

rates and state emission goals established in the guidelines. In 

addition, this section clarifies the treatment of the following 

measures that may be used to adjust a CO2 emission rate: 

 RE, including electric generating technologies using RE 

resources, such as wind, solar, geothermal, hydropower, 

biomass and wave and tidal power. Additional requirements 

are specified for the following RE resources: 

o hydropower; 

o biomass; and 

o waste-to-energy 

 Demand-side EE 

 Demand-side management (DSM) 
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 Transmission and distribution (T&D) measures that 

increase T&D efficiency or reduce electricity end-use 

 Energy storage 

 Water system efficiency 

 CHP 

 Waste heat to power (WHP) 

 Nuclear power 

Where applicable, this section includes additional eligibility 

requirements and accounting methods that apply to specific 

categories of measures, in order to determine the MWh of 

electricity generation or electricity savings that may be used 

to adjust a CO2 emission rate. 

Section VIII.G.1.c addresses measures that may not be used 

to adjust the CO2 emission rate of an affected EGU in a state 

plan, and explains the basis for this exclusion. This includes 

new, modified, and reconstructed fossil fuel-fired EGUs subject 

to emission standards under CAA section 111(b) and other 

existing and new fossil fuel-fired EGUs that are not subject to 

emission standards under CAA section 111(b). Section VIII.G.1.d 

addresses measures that reduce CO2 emissions outside the electric 

power sector. Such measures may not be counted under either a 

rate-based or mass-based state plan. 

The categories of measures included in sections VIII.G.1.a-
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b represent a wide range of actions that may be taken to reduce 

CO2 emissions at an affected EGU, as well as actions taken in the 

generation, transmission, distribution, and end-use of 

electricity that reduce CO2 emissions from affected EGUs. The EPA 

anticipates that the categories described, including their 

eligibility requirements and accounting methods, represent the 

broad range of actions that states may seek to include in their 

state plans to meet the emission guidelines. However, it does 

not necessarily represent an exclusive list. A measure that is 

not specifically discussed in this section may be included in a 

state plan, provided the measure meets all requirements 

specified in the emission guidelines. This includes the 

requirements that a measure be quantifiable and verifiable, as 

described in section VIII.D.2.b. 

a. Affected EGU actions that reduce CO2 emissions. Multiple 

actions may be taken at affected EGUs that reduce CO2 emissions 

from an affected EGU and/or improve its CO2 emission rate. This 

section describes this range of emission reduction actions and 

their accounting treatment in a state plan. Some of these 

actions do not necessitate additional accounting, monitoring or 

reporting requirements. Such actions are discussed in section 

VIII.G.1.a.(1) below, and include heat rate improvements, fuel 

switching from one fossil fuel to another, integration of RE 
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into EGU operations, and 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.G.1.a.(2) below. 

(1) Actions without additional accounting and reporting 

requirements. Many actions will reduce the reported CO2 emissions 

or CO2 emission rate of an affected EGU, without the need for 

additional accounting or monitoring and reporting requirements 

beyond the required CEMS tracking of actual stack CO2 emissions 

and tracking of actual energy output.634 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;635 and 

 CHP, including retrofit of an affected EGU to a CHP 

configuration, or revising the useful energy outputs 

 

634 Monitoring and reporting requirements for affected EGU CO2 

emissions and useful energy output are addressed in section 

VIII.F.

635 “Integrated RE” refers to RE that is directly incorporated 

into the mechanical systems and operation of the EGU. An example 

is a solar thermal energy system used to preheat boiler 

feedwater. Such approaches reduce the amount of fossil fuel heat 

input per unit of useful energy output. 
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(electrical and thermal) at an affected EGU already 

operating in a CHP configuration.636

 Heat rate improvements, fuel switching, integrating RE and 

CHP would not require any additional accounting or monitoring 

and reporting, because under the emission guidelines affected 

EGUs are already required to monitor and report CO2 emissions at 

the stack level. Stack monitoring would reflect reductions in CO2

emissions from efficiency improvements, changes in fuel use 

(including incorporation of RE), and other on-site changes. 

Where states are implementing a rate-based plan, affected EGUs 

must also report useful energy output. 

(2) Actions with additional accounting and reporting 

requirements. Certain actions that may be taken at an affected 

EGU to reduce CO2 emissions, specifically application of CCS and 

CCU, and use of biomass, require additional accounting and 

reporting. 

 

636 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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(a) Application of CCS. Affected EGUs may utilize retrofit CCS 

technology to reduce reported stack CO2 emissions from the EGU.637

Affected EGUs that apply CCS under a state plan must meet the 

same reporting and sequestration requirements for sequestered CO2

as new units with CCS capability subject to the final CAA 

section 111(b) rule for new EGUs.638 Specifically, the final CAA 

section 111(b) rule for new sources requires that, if a new 

affected EGU uses CCS to meet the applicable CO2 emission limit, 

the EGU must report in accordance with 40 CFR part 98 subpart PP 

(Suppliers of Carbon Dioxide), and the captured CO2 must be 

injected at a facility or facilities that report in accordance 

with 40 CFR part 98 subpart RR (Geologic Sequestration of Carbon 

 

637 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. 

638 Standards of Performance for Greenhouse Gas Emissions from 

New, Modified, and Reconstructed Stationary Sources: Electric 

Utility Generating Units. 
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Dioxide).639,640 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 national-levels, and that the status of the CO2 in 

its sequestration site will be monitored, including air-side 

monitoring and reporting. As detailed in the preamble for the 

CAA section 111(b) standards for new EGUs, the EPA is convinced 

that there is ample evidence that CCS is technically feasible 

and that partial CCS can be implemented at a new fossil fuelfired steam generating EGU at a cost that is consistent with the 

cost of 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 

 

639 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 emissions limit must transfer the captured CO2 to a 

facility that reports under 40 CFR part 98 subpart RR. 

640 Under final requirements in the CAA 111(b) NSPS, any well 

receiving CO2 captured from an affected source, 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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cost of integrating a retrofit CCS system into an existing 

facility would be expected to be substantial, and some existing 

EGUs might have space limitations and thus might not be able to 

accommodate the expansion needed to install CCS. Further, the 

EPA noted that aggregated costs of applying CCS as a component 

of the BSER for the large number of existing fossil fuel-fired 

steam EGUs would be substantial and would be expected to affect 

the cost and potentially the supply of electricity on a national 

basis. For those reasons 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 

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 modelling. 

Some commenters noted that there are opportunities to 
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reduce the cost of CCS implementation by selling the captured CO2

for use in Enhanced Oil Recovery (EOR) operations. One commenter 

expressed concern that federal requirements under the Greenhouse 

Gas Reporting Program – specifically the requirement (mentioned 

above) to report under 40 CFR part 98 subpart RR – would 

foreclose, rather than encourage, the use of captured CO2 for 

EOR. The EPA received similar public comments on the CAA 111(b) 

proposal for new EGUs and has addressed those in the preamble 

for the final standards of performance and in the Response-toComments (RTC) document for that rulemaking. 

(b) Application of CCU. The EPA received comments suggesting 

that carbon capture and utilization (CCU) technologies should 

also be allowed as a CO2 emission rate adjustment measure for 

affected EGUs. 

Potential alternatives to storing CO2 in geologic formations 

are emerging and these relatively new potential alternatives may 

offer the opportunity to offset the cost of CO2 capture. For 

example, captured anthropogenic CO2 may be stored in solid 

carbonate materials such as precipitated calcium carbonate (PCC) 

or magnesium or calcium carbonate, bauxite residue carbonation, 

and certain types of cement through mineralization. The 

carbonate materials produced can be tailored to optimize 

performance in specific industrial and commercial applications. 
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For example, these carbonate materials have been used in the 

construction industry and, more recently and innovatively, in 

cement production processes to replace Portland cement. 

The Skyonics Skymine® project, which opened its 

demonstration project in October 2014, is an example of captured 

CO2 being used in the production of carbonate products. This 

plant converts CO2 into commercial products. It captures over 

75,000 tons of CO2 annually from a San Antonio, Texas, cement 

plant and converts the CO2 into other products including sodium 

carbonate and sodium bicarbonate.641 Other companies – including 

Calera642 and New Sky643 – 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 

 

641 http://skyonic.com/technologies/skymine. 

642 http://www.calera.com/beneficial-reuse-of-co2/process.html.

643 http://www.newskyenergy.com/index.php/products/carboncycle. 
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(i.e., the use of algae to convert captured CO2 to useful 

products – especially biofuels) should be recognized for its 

potential to reduce emissions from existing fossil-fueled EGUs. 

Unlike geologic sequestration, there are currently no 

uniform monitoring and reporting mechanisms to demonstrate that 

these alternative end uses of captured CO2 result in overall 

reductions of CO2 emissions to the atmosphere. As these 

alternative technologies are developed, the EPA is committed to 

work collaboratively with stakeholders to evaluate the efficacy 

of alternative utilization technologies, to address any 

regulatory hurdles, and to develop appropriate monitoring and 

reporting protocols to demonstrate CO2 reductions. 

In the meantime, state plans may allow affected EGUs to use 

qualifying CCU technologies to reduce CO2 emissions that are 

subject to an emission standard, or those that are counted when 

demonstrating achievement of the CO2 emission performance rates 

or a state rate-based or mass-based CO2 emission. State plans 

must include analysis supporting how the proposed qualifying CCU 

technology results in CO2 emission mitigation and provide 

monitoring, reporting, and verification requirements to 

demonstrate the reductions. The EPA would then review the 

appropriateness and basis for the analysis and the verification 

requirements in the course of its review of the state plan. 
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(c) Biomass co-firing and repowering. Affected EGUs may use 

qualifying biomass in order to reduce CO2 emissions that are 

subject to an emission standard requirement, or those that are 

counted when demonstrating achievement of the CO2 emission 

performance rates or a state rate-based or mass-based CO2

emission goal. Not all forms of biomass are expected to be 

approvable (see section below for considerations pertaining to 

biomass use in state plans). A state would propose qualifying 

biomass feedstocks or categories of biomass feedstocks in its 

plan and the proposed treatment of biogenic CO2 emissions, 

including measures to ensure emission reduction benefits. State 

plans must include analysis supporting how proposed qualifying 

feedstocks or feedstock categories are considered appropriate as 

a CO2 emission mitigation approach as well as the proposed 

treatment of biogenic CO2 emissions (i.e., the proposed level of 

biogenic CO2 emissions from use of the biomass feedstock that 

would not be counted when demonstrating compliance with an 

emission standard, or when demonstrating achievement of the CO2

emission performance rates or a state rate-based or mass-based 

CO2 emission goal) and quality control measures. The EPA would 

review the appropriateness and basis for such determinations and 

accounting measures in the course of its review of a state plan. 

The EPA received multiple comments supporting the use of 
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biomass feedstocks as a means of reducing CO2 emissions within 

state plans. Several commenters also asserted that states should 

be able to determine how biomass can be used in their plans. 

Additionally, the EPA received a range of comments regarding the 

valuation of CO2 emissions from biomass combustion. Some argued 

that all biomass feedstocks should be considered “carbon 

neutral,” while others maintained that only the full stack 

emissions from biomass combustion should be counted. As 

discussed in the next section, the revised Framework for 

Assessing Biogenic Carbon Dioxide for Stationary Sources644 and 

the 2012 Science Advisory Board peer review of the 2011 Draft 

Framework find that it is not scientifically valid to assume 

that all biogenic feedstocks are “carbon neutral.”645 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, states can propose qualifying 

biomass feedstocks or feedstock categories in state plans. The 

EPA will review the appropriateness and basis for determining 

 

644 www.epa.gov/climatechange/downloads/Framework-for-AssessingBiogenic-CO2-Emissions.pdf.

645 www.epa.gov/climatechange/ghgemissions/biogenicemissions.html.
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qualifying biomass feedstocks or feedstock categories in its 

review of a state plan. 

(i) Considerations for use of biomass in state plans. As 

detailed in the President’s Climate Action Plan,646 part of the 

strategy to address climate change includes efforts to protect 

and restore our forests, as well as other critical landscapes 

including grasslands and wetlands, in the face of a changing 

climate. This country’s forests currently play a critical role 

in addressing carbon pollution, removing nearly 12 percent of 

total U.S. greenhouse gas emissions each year. 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.

The EPA recognizes that some biomass-derived fuels can play 

a role in CO2 emissions reduction strategies. The EPA also 

anticipates that some states may consider biomass-derived fuels 

used in electricity generation as a way to mitigate CO2

emissions, and will include them as part of their state plans to 

meet the emission guidelines. 

With regard to assessing qualifying biomass specified in 

 

646 www.whitehouse.gov/sites/default/files/image/ 

president27sclimateactionplan.pdf. 
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state plans, the EPA generally acknowledges the CO2 emissions 

reduction and climate policy benefits of waste-derived biogenic 

feedstocks647 and certain forest- and agriculture-derived 

industrial byproduct feedstocks, based on the conclusions 

supported by a variety of technical studies, including the 

revised Framework for Assessing Biogenic Carbon Dioxide for 

Stationary Sources. Such waste-derived and certain industrial 

byproduct biomass feedstocks would likely be approvable as 

qualifying biomass in a state plan. In addition, given the 

importance of sustainable land management in achieving the 

carbon reduction goals of the President’s Climate Action Plan, 

sustainably-derived agricultural and forest biomass feedstocks 

may also be acceptable as qualifying biomass in a state plan, if 

the state-supplied analysis of proposed qualifying feedstocks or 

feedstock categories can adequately demonstrate that such 

feedstocks or feedstock categories are considered appropriate as 

a CO2 emission mitigation approach. 

Many states have recognized the importance of forests and 

 

647 Types of waste-derived biogenic feedstocks may include: 

landfill gas generated through the decomposition of MSW in a 

landfill; biogas generated from the decomposition of livestock 

waste, biogenic MSW, and/or other food waste in an anaerobic 

digester; biogas generated through the treatment of waste water, 

due to the anaerobic decomposition of biological materials; 

livestock waste; and the biogenic fraction of MSW at waste-toenergy facilities (as discussed in section VIII.G.1.b(3)(c) 

below). 
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other lands for climate resilience and mitigation, and have 

developed a variety of sustainable forestry policies, RE 

incentives and standards, and GHG accounting procedures. Some 

states, for example Oregon and California, have programs that 

recognize the multiple benefits that forests provide, including 

biodiversity and ecosystem services protection as well as 

climate change mitigation through carbon storage. Oregon has 

several programs focused on best forest management practices and 

sustainability, including the Oregon Indicators of Sustainable 

Forests, that promote environmentally, economically and socially 

sustainable management of state forests. California’s Forest 

Practice Regulations support sustained production of highquality timber while considering ecological, economic and social 

values, and the state’s Greenhouse Gas Reduction Fund provides 

resources for forestry projects to improve forest health, 

maintain carbon storage and avoid GHG emissions from pests, 

wildfires and conversion to non-forest uses. 

Several states focus on sustainable bioenergy, as seen with 

the sustainability requirements for eligible biomass in the 

Massachusetts RPS, which, among other requirements, limits old 

growth forest harvests. Many states employ complementary 

programs that together work to address sustainable forestry 

practices. For example, Wisconsin uses a state forest 
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sustainability framework that provides a common system to 

measure the sustainability of the state’s public and private 

forests, in conjunction with a series of voluntary best 

management guideline manuals for sustainable woody biomass and 

agriculturally-derived biomass. In addition to state-specific 

programs, some states also actively participate in sustainable 

forest management or certification programs through third-party 

entities such as the Sustainable Forestry Initiative (SFI) and 

the Forest Stewardship Council (FSC). For example, in addition 

to other state sustainability programs, New York has certified 

more than 780,000 acres of state forestland to both SFI and 

FSC’s sustainable forest management programs. SFI and FSC have 

certified more than 63 and 35 million acres of forestland across 

the U.S., respectively. 

These examples demonstrate how states already use diverse 

strategies to promote sustainable forestry and agricultural 

management while realizing their unique economic, environmental 

and RE goals. As states evaluate options for meeting the 

emission guidelines, they may consider how the role of wastederived feedstocks as well as sustainably-derived biomass and 

sustainable forestry and agriculture programs, such as the 

examples highlighted above, may help them meet their emission 

reduction goals. In addition, the EPA’s work on assessing 
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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.

 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.648 The EPA is engaging in a second round of 

targeted peer review with the SAB in 2015.649 Information in the 

revised Framework and the second SAB peer review process, 

including stakeholder comments, should assist both states and 

the EPA in assessing qualifying biomass feedstocks included in 

state plans. 

(ii) Biomass co-firing. Affected EGUs may use qualifying biomass 

 

648 www.epa.gov/climatechange/ghgemissions/biogenicemissions.html. 

649 www.epa.gov/sab. 
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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 qualifying biomass 

feedstocks and treatment of biogenic CO2 emissions in state 

plans, along with supporting analysis and quality control 

measures. The EPA will review the appropriateness and basis for 

such determinations and accounting measures in the course of its 

review of a state plan. 

 An affected EGU using qualifying biomass as a fuel must 

monitor and report both its overall CO2 emissions and its 

biogenic CO2 emissions. If biomass is to be used as an emission 

reduction measure in a state plan, the plan must specify 

requirements for reporting biogenic CO2 emissions from affected 

EGUs. Reporting requirements for biogenic CO2 emissions under 40 

CFR 98(§§ 98.3(c), 98.36(b)-(d), 98.43(b), and 98.46) are an 

acceptable default reporting approach that would be approvable 

when combined with other state plan components. However, the EPA 

may approve other approaches included in a state plan. 

(iii) Biomass repowering. Affected EGUs could fully repower to 

use primarily qualifying biomass. The characteristics of 

affected sources, as discussed in Section IV.D., include the use 

of at least 10 percent fossil fuel for applicability of these 

emission guidelines. An EGU repowering with at least 90 percent 
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biomass fuels instead of fossil fuels becomes a non-affected 

EGU.650 An EGU repowering with less than 90 percent biomass would 

remain an affected EGU and provide a reduction option similar to 

that described earlier in this section, with the same processes 

for proposing qualified biomass feedstocks or feedstock 

categories and biogenic CO2 emissions evaluation, monitoring and 

reporting requirements. Entities switching to significantly 

higher amounts of biomass use may be subject to other permitting 

requirements outside of this rule. 

b. Actions taken to adjust the CO2 emission rate of an affected 

EGU. This section describes how measures that substitute for 

generation from affected EGUs or avoid the need for generation 

from affected EGUs may be used in a state plan to adjust the CO2

emission rate of an affected EGU. This section discusses the 

required accounting method for adjusting a CO2 emission rate, as 

well as general eligibility requirements that apply to different 

categories of measures that may be used to adjust a CO2 emission 

rate. Where relevant, this section also discusses additional 

specific accounting methods and other relevant requirements that 

apply to different categories of measures. 

 

650 For such an EGU to be considered non-affected, the EGU should 

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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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.651 Alternatively, under a state measures plan that 

does not employ rate-based trading, adjustments may be applied 

by the state to the reported CO2 emission rate of the affected 

fleet of EGUs. Regardless of the type of plan in which an 

adjustment is applied, the same basic accounting and general 

eligibility requirements described in this section will apply. 

 As discussed in this section, a wide range of actions may 

be taken to adjust the reported CO2 emission rate of an affected 

EGU in order to meet a rate-based emission standard and/or 

demonstrate achievement of a state CO2 rate-based emissions goal. 

All of the measures described in this section will substitute 

for generation from affected EGUs or avoid the need for 

generation from affected EGUs, thereby reducing CO2 emissions. 

This includes RE measures included in the EPA’s determination of 

the BSER, as well as other measures that were not included in 

the determination of the BSER, such as other RE resources, 

 

651 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.G. That section 

addresses the accounting method for ERC issuance to affected 

EGUs that perform below their assigned CO2 emission rate. 
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demand-side EE, CHP, WHP, electricity transmission and 

distribution improvements, nuclear energy, and international 

energy imports. 

 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.652 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. Those additional MWh are based on 

quantified and verified electricity generation or electricity 

 

652 These requirements are discussed in section VIII.D. 
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savings from eligible measures. 

This section also addresses general eligibility 

requirements for resources that are used to adjust an affected 

EGU’s CO2 emission rate. Specific eligibility and accounting 

methods that apply in order to determine MWh generation or 

savings from different types of resources are also addressed, 

where relevant, including for: 

 hydropower; 

 biomass; 

 waste-to-energy; 

 demand-side EE and other efficiency measures; 

 transmission and distribution (T&D) measures that 

increase T&D efficiency or reduce electricity end-use; 

 CHP at non-affected sources; 

 waste heat to power (WHP); and 

 nuclear power. 

(1) General accounting approach for adjusting a CO2 emission 

rate. 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.G.1.b.(2)-(9) 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. 
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 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 demand-side management). In both of these cases, 

generation from an affected EGU is replaced, through substitute 

generation or a reduction in electricity demand. To the extent 

that qualifying zero-emitting and low-emitting resources result 

in reduced generation and CO2 emissions from an individual 

affected EGU, those emission impacts are reflected in lower 

reported CO2 emissions and a reduction in MWh generation from the 

affected EGU. However, while there will be a reduction in CO2

emissions, 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 CO2 emission rate allows mass CO2 emission 

reductions from these measures to be fully reflected in an 

adjusted CO2 emission rate. 
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 The following provides a simple calculation example of how 

MWh of replacement generation added to the denominator of an 

affected EGU’s reported CO2 emission rate results in a lower 

adjusted CO2 emission rate. Assume an affected EGU with CO2

emissions of 200,000 lb and electric generation of 100 MWh 

during a reporting period. The affected EGU’s reported CO2

emission rate is 2,000 lb/MWh (200,000 lb CO2/100 MWh = 2,000 

lb/MWh). When complying with its rate-based emission limit, the 

affected EGU submits 10 ERCs, representing 10 MWh of replacement 

generation.653 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.654 In the case of a state 

measures plan, quantified and verified MWh from eligible state 

 

653 Requirements for the issuance of ERC and a further discussion 

of how ERCs are used in compliance with rate-based emission 

limits are addressed in section VIII.G.3. 

654 Any ERCs used to adjust a CO2 emission rate must meet 

requirements in the emission guidelines, which are described in 

section VIII.D. 
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measures are used by the state to administratively adjust the 

reported CO2 emission rate of affected EGUs in the aforementioned 

manner. The CO2 emission performance rates or rate-based CO2 goal 

in the emission guidelines are met if the adjusted CO2 emission 

rate of affected EGUs in a state is at or below the specified CO2

emission rate in a state plan that applies for an identified 

plan performance period. 

Numerous commenters requested that the EPA ensure 

consistency between goal-setting calculations and the 

methodology used to demonstrate achievement of a CO2 emission 

rate under a state plan. This approach for adjusting a CO2

emission rate corresponds with how RE, the one component of the 

BSER that involves adjustment of a CO2 emission rate, is 

represented in the CO2 emission performance rates in the emission 

guidelines. Specifically, in the calculation of final CO2

emission performance rates, the MWh 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 
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added.655 

 When demonstrating achievement of a CO2 emission performance 

rate, the reported CO2 emissions already reflect the actual 

emission reductions from the deployment of qualifying nonemitting 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. 

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. 

 

655 For a detailed discussion of this method, see Section VI.C.3. 

Form of the Performance Rates, in the Equation subsection. 
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Consistent with assumptions used in calculating the CO2 emission 

performance rates in the emission guidelines, affected EGUs and 

states can take full credit for the MWh resulting from eligible 

measures they are responsible for deploying, no matter where 

those measures are implemented. CO2 emission reductions from the 

eligible measures may occur across the region, however, an 

affected EGU or a state may only take credit for avoided CO2

emissions at that affected EGU or set of EGUs in question, as 

reflected in the reported stack CO2 emissions of affected EGUs. 

Because of the separate accounting of MWhs and CO2

emissions, with emission impacts inherent in reported stack CO2

emissions and zero-emitting MWh impacts requiring explicit 

adjustments, the accounting method corresponds with the use of 

MWh-denominated ERCs in the rate-based emission trading 

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 
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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.G.3. 

This MWh accounting method also addresses interstate 

effects, because it inherently accounts for how generation 

replacement and CO2 emission reduction impacts may cross state 

borders. For example, if the accounting method was informed by 

avoided CO2 emission rates, it could create perverse incentives 

for development of zero- or low-emitting resources in states 

that result in the greatest calculated estimate of CO2 emission 

reductions for each replacement MWh. Instead, this accounting 

method is indifferent to avoided CO2 emission rates and creates 

the same number of zero-emitting credits or adjustment for each 

MWh of energy generation or savings, wherever they occur. For a 

detailed discussion on how the accounting method addresses 

interstate effects, see section VIII.G.2. 

(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 
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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. These requirements are 

appropriate, as they align measures that may be used in a state 

plan with the EPA’s assessment of the BSER.656 These general 

requirements also address potential interactions among rate and 

mass plans, as discussed more fully in section VIII.G.2. 

 As discussed in the subsections that follow, the general 

eligibility criteria address: 

 the date from which MWh from eligible measures may be 

counted, and applied toward adjusting a CO2 rate; 

 the date from which eligible measures may be installed 

(e.g., installation of RE generating capacity and 

installation of EE measures); and 

 the need to demonstrate that eligible measures replace or 

avoid generation from affected EGUs. 

(a) Eligibility date for MWh generation and savings. Electricity 

generation and electricity savings that occur during a plan 

performance period may be applied to adjust a CO2 emission rate. 

 

656 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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Specifically, this means that any quantified and verified MWh of 

electricity generation or electricity savings that occur in 2022 

and future years, from an eligible measure, may be applied 

toward adjusting a CO2 emission rate. The eligible measures 

themselves may be installed in any year after 2012, as described 

below.657 For example, MWh generation in 2022 from a wind turbine 

installed in 2013 may be applied toward adjusting a CO2 emission 

rate. 

Further, 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.658 These MWh may be banked from the 

interim to final compliance periods. 

The EPA notes that states can submit a rate-based state 

plan that encourages early action by allowing MWhs generated 

from 2013-2021 to be used to adjust the CO2 rate of affected EGUs 

during the plan performance period (2022 and subsequent years). 

In order for this type of provision to be approvable in a state 

 

657 For demand-side EE, this eligibility date may require special 

considerations for EM&V plans. EM&V requirements are addressed 

in subsection VIII.C.3. 

658 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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plan, it must meet certain conditions. These MWhs must be from 

eligible measures implemented after 2012. The state must provide 

provisions for adjustment of CO2 emission performance rates or 

rate-based state CO2 goals (applied during the plan performance 

periods in 2022 and future years) downward based upon the number 

of MWhs that are issued from 2013-2021, such that the level of 

emission reductions is equivalent to or more stringent than that 

which would have been achieved had eligible MWh been limited to 

those generated during the plan performance periods in 2022 and 

future years. This downward adjustment of CO2 emission 

performance rates or rate-based state CO2 goals must be 

calculated based upon a projection of total CO2 emissions, total 

MWh generation from affected EGUs, and total ERCs that would 

have been used to demonstrate compliance if the state had 

elected to meet the CO2 emission performance rates or rate-based 

state CO2 goals using only eligible MWh issued in 2022 and 

subsequent years. 

(b) Eligibility date for installation of RE/EE and other 

measures. RE generating capacity and demand-side EE measures 

that are installed after 2012 are eligible for use in adjusting 

a CO2 emission rate. This aligns with treatment of RE in the 

BSER. Other eligible measures, such as CHP, nuclear power and 

DSM, also must be installed after 2012. This 2012 date applies 
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consistent eligibility requirements to all forms of zero- and 

low-emitting eligible generating capacity that may be used to 

adjust a CO2 emission rate. As described above, only the MWh of 

energy savings that occur in 2022 and subsequent years as a 

result of these measures may be applied toward adjusting a CO2

emission rate. 

This eligibility date criterion is consistent with the date 

of installation for “incremental” RE capacity that is included 

in BSER building block 3, which is the basis for RE MWh 

incorporated in the CO2 emission performance rates for affected 

EGUs in the emission guidelines. For more information on RE in 

the BSER, see section V.E. Many commenters asserted that 

proposed state goals did not sufficiently account for actions 

states take that reduce CO2 emissions prior to the first plan 

performance period, and therefore requested that MWhs of 

electricity generation or electricity savings that occur prior 

to the first plan performance period be eligible to apply toward 

adjusting the CO2 emission rates of affected EGUs. 

 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 
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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. 

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. 

First, affected EGUs that have maximized their CO2 emission 

reduction opportunities available through early action will be 

better positioned to meet the BSER technology-source specific CO2

emission rate that is uniformly applied to all affected EGUs in 

a technology category. For example, a steam generating unit that 

has already reduced its CO2 emission rate through a heat rate 

improvement may have a CO2 emission rate of 2,000 lb/MWh whereas 

its rate was 2,100 lb/MWh prior to the improvement. Therefore, 

it has less distance to cover to meet the technology-specific CO2

emission performance rate for steam generating units finalized 

in this action. 
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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 and will better position states and 

affected EGUs to meet the CO2 performances rates or state rateor mass-based CO2 goals. 

Third, commenters expressed concern that demand-side EE 

targets as part of proposed state goals reflected an assumption 

of installation of increased EE measures starting 2017. Because 

demand-side EE is not used in calculating the CO2 emission 

performance rates in the emission guidelines, this is no longer 

the case. Furthermore, eligible demand-side EE actions that 

occur after 2012 can be applied toward adjusting the CO2 emission 

rates of affected EGUs. 

(c) 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 equipment that is connected 

to the electricity grid. EE measures only avoid electric 
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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. 

(d) Geographic eligibility. RE generation and demand-side EE 

measures may occur in any state or territory, with certain 

limitations, as described below. To the extent these measures 

are tied to a state plan,659 these measures may be used to adjust 

a CO2 emission rate, regardless of whether the RE generation or 

demand-side EE savings occur inside or outside the state or 

territory.660 This approach is generally consistent with the 

 

659 As used here, a measure is “tied to a state plan” if it is 

issued an ERC under a rate-based emission standard, or under a 

state measures plan represents quantified and verified MWh 

energy generation or energy savings achieved by an approved 

state measure. 

660 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 
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approach used in building block 3 of the BSER, which reflects 

regionally available RE and interstate effects. This approach 

recognizes that RE and demand-side EE 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 RE and 

EE is provided below. 

 For consistency, this geographic eligibility criterion 

applies to all other eligible measures that are used to adjust a 

CO2 emission rate under a state plan. These measures will have 

similar interstate impacts as RE and demand-side EE on 

electricity generation across the interconnected electricity 

system. 

 State plans must demonstrate that emission standards and 

state measures (if applicable) are non-duplicative. Given the 

geographic eligibility approach described here, this includes 

demonstration that a state plan does not provide for recognition 

of a MWh, for use in adjusting the CO2 emission rate of an 

 

requirements of EPA-approved state regulations and the provider 

applies to the state for the issuance of ERCs. Similarly, under 

a state measures plan, a state might include state requirements 

such as an RPS, where compliance with the RPS can be met through 

out-of-state RE generation. In this plan context, MWh of RE 

generation used to comply with the state RPS could be used by 

the state to adjust the CO2 emission rate of the fleet of 

affected EGUs in the state when demonstrating that its plan has 

achieved the state’s rate-based CO2 goal. 
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affected EGU, if the MWh is being 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. 

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. 

Commenters argued that this approach makes sense based on the 

nature of the interconnected electricity grid and allows states 

and utilities to fully account for their RE and demand-side EE 

efforts, whether that RE or EE, and its related impacts, occurs 

inside or outside of their state. Some commenters expressed 

concerns that, at proposal, states with significant RE resources 

had large amounts of existing RE capacity included in their 

state CO2 goals, but that RE was functionally credited to other 

states for use in meeting their goals because it was associated 

with measures (such as an RPS) likely to be included in another 

state’s plan. This concern has been addressed through changes in 

the BSER RE assumptions in the final rule. This includes 

regionalization of the RE building block, and removal of 

existing RE capacity constructed prior to 2012 from the building 

block. The result of these changes is that the RE incorporated 
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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 eligible measures that occur in a 

state with an EPA-approved plan that is meeting a state massbased CO2 goal. However, measures that occur in such mass-based 

states must meet additional eligibility criteria to be used to 

adjust the CO2 emission rate of an affected EGU in a state with a 

rate-based plan. 

 These criteria are intended to address the fact that 

eligible measures should lead to substitution of generation from 

affected EGUs, with related impacts on CO2 emissions from 

affected EGUs. Where states with mass-based plans implement 

mass-based CO2 emission standards, CO2 emissions reductions from 

affected EGUs must occur in order to comply with these emission 

standards and, unlike the rate-based approach, zero- and lowemitting MWhs do not play a specified role in demonstrating that 

the mass-based standards have been met.661 Since they are not 

counted in the mass-based demonstration, eligible measures 

 

661 Where such measures substitute for generation from affected 

EGUs subject to a mass CO2 emission limit, such measures reduce 

the cost of meeting those mass emission limits, but do not 

result in incremental CO2 emission reductions. 
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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.662 The result 

would be a loss in net CO2 emission reductions that would 

otherwise occur across the two states. These dynamics are 

further addressed in section VIII.G.2. 

 For measures providing zero- or low-emitting generation 

located in a mass-based state, it must be demonstrated that the 

energy generated is delivered to meet electricity load in a 

state with a rate-based plan.663 Some examples of documentation 

that can serve as a demonstration include a power delivery 

 

662 As used here, incremental emission reductions refers to 

emission reductions that are above and beyond what would be 

achieved solely through compliance with the emission standards 

in the mass-based state. 

663 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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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 measure seeking ERC issuance 

under the rate-based emission standards in a rate-based state, 

as part of the eligibility application for the measure.664 Under 

a state measures plan, this demonstration must be made by the 

rate-based state as part of its demonstration of how its state 

measures meet the CO2 emission performance rates or achieve the 

state rate-based CO2 emission goal for affected EGUs.665 In the 

case of either an emission standards plan or state measures 

plan, the rate-based state must include in its state plan 

provisions that describe what it will consider a sufficient 

demonstration of geographic eligibility for zero- or lowemitting generation under rate-based emission standards, or 

geographic eligibility of state measures that can be used to 

adjust the reported CO2 emission rate of affected EGUs. 

 

664 Requirements for ERC issuance are addressed in subsection 

VIII.C.2. 

665 This demonstration is part of a state’s annual report to the 

EPA, outlining the eligibility of MWh used to adjust the 

reported CO2 emission rates of affected EGUs under a rate-based 

state measures plan. 
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 Further examples of eligible demonstrations and how they 

should be outlined in state plans is provided in section 

VIII.G.2. 

(ii) Measures that occur in states and territories that are not 

interconnected to the grid or do not have affected EGUs. States 

and territories that are not interconnected to the grid in the 

continental U.S. or that do not have any affected EGUs within 

their borders may be providers of credits to adjust CO2 emission 

rates. In its supplemental proposal for this proposed 

rulemaking, the EPA sought comment on whether or not 

jurisdictions without affected fossil fuel generation units 

subject to the proposed emission guidelines should be authorized 

to participate in state plans. Commenters were supportive of 

allowing those jurisdictions without affected EGUs the 

opportunity to participate in state plans. CO2 reduction measures 

in areas without affected EGUs have the potential to provide 

cost-effective opportunities to reduce emissions and should be 

available on a voluntary basis to affected EGUs. Commenters 

noted that some tribes, for example, have many untapped RE 

resources that could be developed, and they should be able to 

realize the benefits of contributing to a state plan. Commenters 

stated that because of the integrated nature of the U.S. 

electricity grid, it is appropriate to allow all jurisdictions 
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with the ability to contribute to and benefit from CO2 emission 

reductions or CO2 emission rate adjustments. 

For rate-based states and territories, they must adhere to 

EM&V standards, installation dates, and any other criteria that 

apply to all states. Section VIII.G.3 below identifies and 

discusses the EM&V criteria used to quantify MWh savings from 

demand-side EE and generation from zero-emitting sources. 

States, including areas of Indian country, that do not have any 

affected EGUs may provide ERCs to adjust CO2 emissions provided 

they are connected to the continental U.S. grid and have a power 

purchase agreement or contract for delivery of the zero- or lowemission power, along with meeting the other requirements for 

eligibility. Mass-based states and territories are not allowed 

to provide ERCs for zero- or lower-emission power generation if 

they are not connected to the continental U.S. grid and, hence, 

not able to also deliver the power. For demand-side EE 

adjustments where there is no power delivery, the emission 

reductions must meet the demonstration criteria that also 

applies to demand-side EE reductions in all other mass-based 

states. 

(iii) Measures that occur outside the U.S. The EPA will work 

with states using the rate-based approach and interested in 

allowing the use of RE and demand-side EE from outside the U.S. 
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to adjust CO2 emission rates. In these cases, certain conditions 

must be demonstrated including: the country generating the ERCs 

must be connected to the U.S. grid; resources must be 

incremental and installed after 2012 for RE and demand-side EE; 

all EM&V standards that apply to domestic measures must be met; 

and, specifically for RE, there must be a power purchase 

agreement or other contract for delivery of the power with an 

entity in the U.S. For demand-side EE adjustments where there is 

no power delivery, the emission reductions must meet the 

demonstration criteria that also applies to demand-side EE 

reductions in mass-based states. RE generation capacity 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. See 

below 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 
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development to increase generating capacity, which could be 

called upon as a base load resource to supplement intermittent 

forms of RE generation. Commenters said that the EPA should 

permit the use of all incremental hydropower—both domestic and 

international—towards EGU CO2 emission rate adjustments providing 

that double-counting can be prevented; and the EPA acknowledges 

this may be allowable, as long as the specified criteria have 

been met. 

(3) RE and demand-side EE. RE666 and demand-side EE measures may 

be used to adjust a CO2 emission rate, provided they meet the 

general eligibility requirements outlined above and the MWh 

electricity generation or electricity savings are properly 

quantified and verified.667 

 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 

 

666 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. 

667 All state plans must demonstrate that measures included in 

the plan are quantifiable and verifiable. See section VIII.C.2 

for discussion of requirements for the issuance of ERCs, and 

section VIII.C.3 for discussion of EM&V requirements for use of 

RE and demand-side EE in a state plan. 
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existing RE that are already embedded in the baseline emissions 

and generation mix. A significant number of commenters supported 

the integration of RE into a rate-based credit trading system. 

 Certain additional requirements apply for hydropower and 

biomass (including waste-to-energy), as described below. 

(a) Hydroelectric power. Consistent with other types of RE, new 

hydroelectric power generating capacity installed after 2012 is 

eligible for use in adjusting a CO2 emission rate. In addition, a 

capacity uprate at an existing hydroelectric power resource 

(i.e., an uprate to generating capacity originally installed as 

of 2012 or earlier) is also eligible to adjust a CO2 emission 

rate. The capacity uprate must occur after 2012. Such uprates to 

capacity represent incremental capacity added after 2012, which 

we refer to as “incremental hydroelectric power.” 

 Generation (in MWh) from incremental hydroelectric power 

generating capacity is determined as follows. The incremental 

generating capacity (in nameplate MW) is divided by the total 

uprated generating capacity (in nameplate MW) and then 

multiplied by generation output (in MWh) from the uprated 

generator. For example, if a hydroelectric power plant expands 

generating nameplate capacity from 100 MW to 125 MW and 

generation output increased to 1,000 MWh, then 200 MWh ((25 

MW/125 MW) * 1,000 MWh) is eligible for use in adjusting a CO2
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emission rate, regardless of the overall level of generation for 

the period.668 

 Relicensed facilities are considered existing capacity and, 

therefore, are not eligible for use in adjusting a CO2 emission 

rate, unless there is a capacity uprate as part of the 

relicensed permit. In such a case, only the incremental capacity 

is eligible for use in adjusting a CO2 emission rate. 

 The EPA noted that many commenters preferred that 

generation from hydropower displace generation from fossil 

sources. One commenter suggested that existing zero-emitting 

sources, including hydropower, do not reduce emissions from 

existing fossil generation, but that new or uprated zeroemitting sources would, because of their low variable rate, 

reduce fossil emissions. Several commenters recommended allowing 

incremental generation from new or uprated zero-emitting 

sources, including hydropower, be available for compliance. One 

commenter recognized the difficulty of quantifying emission 

reductions due to uprated zero-emitting sources. The EPA 

believes the approach described is appropriate. 

(b) Biomass. RE generating capacity installed after 2012 that 

 

668 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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uses qualifying biomass as a fuel source is eligible for use in 

adjusting a CO2 emission rate.669 As discussed in section 

VIII.G.1.a.(2)(c), a state should propose qualifying biomass 

feedstocks and treatment of biogenic CO2 emissions in its plan, 

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 a state plan. 

Where an RE generating unit uses qualifying biomass, as 

designated in an approved state plan, MWh generation from the 

unit could be used to adjust a CO2 emission rate. Considerations 

for the use of biomass in state plans are discussed in section 

VIII.G.1.a(2)(c)(i). 

(c) Waste-to-energy. Use of qualifying biomass may include the 

biogenic portion of MSW combusted in a waste-to-energy 

facility.670 With regard to assessing qualifying biomass 

specified in state plans, the EPA generally acknowledges the CO2

emission reduction and climate policy benefits of waste-derived 

biomass, based on the conclusions supported by a variety of 

technical studies, including the revised Framework for Assessing 

 

669 As with other RE, only generating capacity installed after 

2012 would be eligible for use in adjusting a CO2 emission rate. 

670 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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Biogenic Carbon Dioxide for Stationary Sources.671 Such wastederived biomass feedstocks would likely be approvable as 

qualifying biomass in a state plan. As described in Section 

VIII.G.1.a.(2)(c), states should propose qualifying biomass 

feedstocks and treatment of biogenic CO2 emissions in state 

plans, along with supporting analysis, and the EPA would review 

the appropriateness and basis for such determinations in the 

course of its review of a state plan. Considerations for the use 

of biomass in state plans are discussed in section 

VIII.G.1.a.(2)(c)(i). 

 MSW can be directly combusted in waste-to-energy facilities 

to generate electricity as an alternative to landfill disposal. 

In the U.S., almost all incineration of MSW occurs at waste-toenergy facilities or industrial facilities where the waste is 

combusted and energy is recovered.672 Total MSW generation in 

2012 was 251 million tons, but of that total volume generated, 

almost 87 million tons were recycled and composted.673 Increasing 

demand for electricity generated from waste-to-energy facilities 

could increase competition for waste stream materials - 

 

671 http://www.epa.gov/climatechange/downloads/Framework-forAssessing-Biogenic-CO2-Emissions.pdf.

672 Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-

2012. 

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

html. 

673 http://www.epa.gov/osw/nonhaz/municipal/pubs/2012_msw_fs.pdf. 
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including discarded organic waste materials, which could cause 

diversion of these materials from existing or future efforts 

promoting waste reduction, composting, and recycling. The EPA 

and many states have recognized the importance of integrated 

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.674

For example, Oregon and Vermont have strategies that emphasize 

waste prevention, followed by reuse, then recycling and 

composting materials prior to treatment and disposal.675

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) 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.676 

 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 

 

674 http://www.epa.gov/wastes/nonhaz/municipal/hierarchy.htm.

675

http://www.anr.state.vt.us/dec/wastediv/WastePrevention/main.htm

. 

676 http://epa.gov/epawaste/conserve/tools/warm/Warm_Form.html. 
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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. 

Only electric generation at a waste-to-energy facility that 

is related to the biogenic fraction of MSW and that is added 

after 2012 is eligible for use in adjusting a CO2 emission rate. 

Total electric generation from the facility must be prorated 

based on the proportion of biogenic content of MSW. This can be 

achieved through periodic sampling of the biogenic fraction of 

the MSW used as fuel at a waste-to-energy facility, or based on 

the proportion of biogenic CO2 emissions to total CO2 emissions 

from the facility. Measuring the proportion of biogenic to 

fossil CO2 emissions can be performed via ASTM D-6866-06 testing 

or other methods (ASTM, 2006; Bohar, et al. 2010).For example, 

where the biogenic fraction of MSW is 50 percent by 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, where 

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 
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facility that may be used to adjust an affected EGU CO2 emission 

rate. A state plan must propose a method for determining the 

proportion of total MWh generation from a waste-to-energy 

facility that is eligible for use in adjusting a CO2 emission 

rate. 

 Where biogenic CO2 emissions as a proportion of total CO2

emissions from a waste-to-energy facility are used to prorate 

total MWh output that may be used to adjust a CO2 emission rate, 

the state plan must specify requirements for reporting biogenic 

CO2 emissions from the facility. Reporting requirements for 

biogenic CO2 emissions under 40 CFR 98 (§§ 98.3(c), 98.36(b)-(d), 

98.43(b), and 98.46) are an acceptable default reporting 

approach that would be approvable. However, the EPA may approve 

other approaches included in a state plan. 

The EPA received multiple comments supporting the use of 

waste-to-energy as part of a state’s plan for reducing CO2

emissions. 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 wasteto-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 
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recycling and waste reduction efforts, while other commenters 

asserted that waste-to-energy practices encourage recycling 

programs. Some commenters also expressed concern about what 

treatment would be approvable for emissions from waste-to-energy 

practices. As discussed above, potential negative impacts from 

waste-to-energy production on recycling, waste reduction, and 

composting programs should be evaluated and efforts to mitigate 

negative impacts must be discussed in state plans. 

(4) Demand-side management. Avoided MWh of electricity use that 

result from demand-side management may be used to adjust a CO2

emission rate. Eligible DSM actions are those that are nonemitting and avoid, rather than shift, the use of electricity by 

an electricity end-user.677 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.C.3. 

 

677 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 are not 

eligible, as these measures do not avoid electricity use from 

the grid. Use of emitting generators as a DSM measure are also 

not eligible. 
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(5) Energy storage. Energy storage may not be directly 

recognized as an eligible measure that can be used to adjust a 

CO2 emission rate, because storage does not directly substitute 

for electric generation from the grid or avoid electricity use 

from the grid.678 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.679 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 

 

678 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). 

679 This approach focuses on counting the qualifying electric 

generation, which may be an input to an energy storage unit. 

Counting both the generation input to energy storage and the 

output from the energy storage unit would be a form of double 

counting. The electric generation that is stored may be counted; 

the subsequent output from the storage unit may not. 

Furthermore, it may be impossible in certain instances to 

determine the specific EGUs that supplied an energy storage 

unit, in some utility-scale applications of energy storage. 
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enable greater use of RE to meet on-site electricity demand.680 

The EPA received multiple comments regarding the overall 

merits of energy storage. Consistent with the discussion above, 

the majority of commenters observed that storage technology 

enables greater grid penetration of RE and supports more 

efficient and effective operations of both RE and fossil-fuel 

plants. Commenters further noted that energy storage can provide 

RE to the grid when it is most needed, while simultaneously 

taking pressure off fossil-fuel plants to respond to sudden 

shifts in demand. Despite broad acknowledgment of the benefits 

of storage, public comments underscore its indirect and 

supporting role in providing zero-emission MWh to the grid 

(consistent with the EPA’s decision to exclude energy storage as 

an eligible measure that can be used to adjust a CO2 emission 

rate). 

(6) Transmission and distribution measures. Electricity T&D 

measures that improve the efficiency of the T&D system and/or 

reduce electricity use may be used to adjust a CO2 emission rate. 

This includes T&D measures that reduce losses of electricity 

during delivery from a generator to an end-user (sometimes 

 

680 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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referred to as “line losses”681) and T&D measures that reduce 

electricity use at the end-user, such as conservation voltage 

reduction (CVR).682 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, 

 

681 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% of the 

electricity that is transmitted and distributed in the United 

States each year. 

682 Volt/VAR optimization (VVO) refers to coordinated efforts by 

utilities to manage and improve the delivery of power in order 

to increase the efficiency of electricity distribution. VVO is 

accomplished primarily through the implementation of smart grid 

technologies that improve the real-time response to the demand 

for power. Technologies for VVO include load tap changers and 

voltage regulators, which can help manage voltage levels, as 

well as capacitor banks that achieve reductions in transmission 

line loss. VVO efforts are often closely related to conservation 

voltage reduction (CVR), which are actions taken to reduce 

initial delivered voltage levels in feeder transmission lines 

while remaining within the 114 volt to 126 volt range required 

at the customer meter (based on ANSI C84.1 standards). 
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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. 

For T&D measures, the same eligibility date for measure 

installation applies as that which applies to demand-side EE 

installed after 2012. This general eligibility requirement is 

discussed above in section VIII.C.1.b.(2)(b). The MWh of avoided 

losses or reduction in end-use that result from T&D measures 

must be appropriately quantified and verified, as discussed in 

section VIII.C.3. To this point, the predominant view expressed 

in public comments was broad acknowledgement that EM&V for T&D 

strategies is maturing in tandem with their increasing adoption 

by states and utilities. For example, several commenters 

referenced protocols and procedures currently under development 

and already in usage for quantifying MWh savings from CVR. This 

development in EM&V for T&D strategies was cited as a rationale 

for their inclusion as an eligible measure that can be used to 

adjust a CO2 emission rate. 

(7) Water system efficiency. Water efficiency programs that 

improve EE at water and wastewater treatment facilities also 

provide demand-side EE savings opportunities. The EPA received 
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comments supporting the use of water sector EE programs and 

projects. Commenters identified water and wastewater utilities 

as particularly well-suited for participating in EE programs and 

providing a source of electricity savings. Investments such as 

replacing pumps and other aging equipment and repairing leaks 

can result in greater EE. The EPA agrees that these electricity 

savings should be eligible for adjustments to CO2 emission rates 

at affected EGUs. 

For water efficiency measures, the same eligibility date 

for measure installation applies as that which applies to 

demand-side EE--installed after 2012. This general eligibility 

requirement is discussed above in section VIII.C.1.b.(2)(b). The 

MWh of avoided electricity use that result from water efficiency 

measures must be appropriately quantified and verified, as 

discussed in section VIII.C.3. 

(8) Nuclear power. As is discussed in section V.A.3., upon 

consideration of comments received, the EPA does not include 

either nuclear generation from existing or under construction 

units in the determination of the BSER. In addition to comments 

received on the provisions for determining the BSER, the EPA 

also received comments requesting that the EPA allow all 

generation from nuclear generating units to be recognized as an 

eligible measure that can be used to adjust a CO2 emission rate. 
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Commenters also recommended that the EPA consider nuclear 

generating units and RE generating units in a consistent manner 

for CO2 emission rate adjustments in state plans. We agree with 

comments that nuclear generation and RE should be treated 

consistently when it comes to CO2 emission rate adjustments. 

The EPA has determined that generation from new nuclear 

units and capacity uprates at existing nuclear units will be 

eligible for use in adjusting a CO2 emission rate. However, 

consistent with the reasons discussed for not including the 

preservation of existing nuclear capacity in the BSER – namely, 

that such preservation does not actually reduce existing levels 

of CO2 emissions from affected EGUs – preserving generation from 

existing nuclear capacity is not eligible for use in adjusting a 

CO2 emission rate. 

In contrast, any incremental zero-emitting generation from 

new nuclear capacity would be expected to replace generation 

from affected EGUs and, thereby, reduce CO2 emissions; and the 

continued commitment of the owner/operators to completion of the 

new units and improving the efficiency of existing units through 

uprates can play a key role in state plans. Therefore, 

consistent with treatment of other low- and zero-emitting 

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. Additionally, existing nuclear units (i.e., those 

that originally commenced operation in 2012 or earlier years) 

that receive operating license extensions are not eligible for 

use in adjusting a CO2 emission rate, except where such units 

receive a capacity uprate as a result of the relicensing 

process. Only the incremental capacity from the uprate is 

eligible for use to adjust a CO2 emission rate. Applicable 

generation (in MWh) from incremental nuclear power is determined 

in the same manner as that described for incremental 

hydroelectric power above. 

(9) CHP units. Electric generation from non-affected CHP units683

may be used to adjust the CO2 emission rate of an affected EGU, 

as CHP units displace emissions from an on-site boiler and 

electricity from the grid. Non-affected CHP units that meet the 

eligibility criteria under section VIII.G.1.b.(2) can be 

 

683 The accounting treatment described in this section is 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 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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considered under this option. In most cases, a CHP unit would be 

a low-emitting CO2 source and therefore the MWh output would need 

to be prorated to account for the emissions. A denominator 

approach consistent with the accounting approach for EE and RE, 

can be taken. 

The CHP unit’s electrical output would be prorated based on the 

CO2 emission rate of the electrical output associated with the 

CHP unit.684 The incremental rate would be relative to the 

applicable CO2 emission rate for affected EGUs in the state and 

would be limited to values between 0 and 1. 

Prorated MWh = (1-incremental CHP emission rate/applicable 

affected EGU emission limit rate)* CHP MWh output 

Where the ratio is limited to values between 0 and 1. 

The CHP electrical emission rate is the net emission rate 

when the CHP unit’s thermal output emissions are deducted from 

the CHP unit’s total emissions. It can be derived as follows 

[CHP fuel input * fuel emission factor – (UTO/boiler 

efficiency) * fuel emission factor]/CHP MWh 

Non-affected CHP units can use qualifying biomass fuels. As 

 

684 The applicable CO2 emission limit rate depends on the type of 

state plan being implemented. Where a state plan includes a 

single CO2 emission limit rate for the fleet of affected EGUs, 

the applicable rate is the rate that applies to all affected 

EGUs. Where a state plan includes subcategorized rates for 

different categories of affected EGUs, the applicable rate is 

the rate that applies to affected NGCC EGUs. 
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described in Section VIII.G.1.a.(2)(c), states should propose 

qualifying 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 a state plan. Considerations for qualifying 

biomass included in state plans are discussed in section 

VIII.G.1.a.(2).(c).(i). 

The measurement of the fuel and MWh output of the CHP unit 

are based on standard industry practice and discussed in section 

VIII.G.d.5. 

In order to determine the incremental CO2 emission rate, a 

CHP unit would monitor requirements for CO2 emissions and energy 

output.685 The monitoring requirements are standard methods 

currently in use and the requirements would depend on the size 

of the CHP units and the fuel used in the unit. 

Non-affected CHP facilities686 with electric generating 

capacity greater than 100 MW would follow the same monitoring 

and reporting protocols for CO2 emissions and energy output as 

 

685 Where a CHP unit uses biomass fuel, it must report both total 

CO2 emissions and biogenic CO2 emissions. Requirements for 

reporting biogenic CO2 emissions are discussed in section 

VIII.G.1.a.(2)(c) above. 

686 A CHP facility may consist of one or more electric 

generators. 
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are required for affected EGU CHP units. These requirements are 

discussed in section VIII.F. For non-affected CHP facilities 

with electric generating capacity less than 100 MW, which use 

only natural gas and/or distillate fuel oil, the low mass 

emission unit CO2 emission monitoring and reporting methodology 

outlined in 40 CFR 75, or a similar fuel tracking and emission 

factor approach, is acceptable. For non-affected CHP facilities 

with an electric generating capacity less than 100 MW, which use 

all other fuels, the CO2 emissions monitoring and reporting 

protocols for affected EGU CHP units would be used. These 

requirements are discussed in section VIII.G.5. 

Most comments received on CHP recommended that the EPA 

explicitly call out how CHP can be accounted for in a state 

plan. Some commenters pointed out that without such a 

description, states would not be able to readily take advantage 

of the CO2 emissions reduced by the use of CHP. Other commenters 

weighed the advantages to considering a numerator-based approach 

versus a denominator-based approach. The EPA believes that a 

denominator approach is appropriate because it is consistent 

with the accounting approach used for RE and demand-side EE. 

(10) WHP. WHP units that meet the eligibility criteria under 

section VIII.G.1.b.(2) may be used to adjust the CO2 emission 

rate of an affected EGU. There are several types of WHP units. 
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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.687 Emissions from these WHP 

facilities would be based on the initial fuel combustion process 

that produced the waste heat and would be accounted in the same 

way as non-affected CHP units under section VIII.G.1.b.9. 

 There are WHP facilities where the waste heat from the 

initial combustion process is used to generate additional power. 

There is no additional fuel used to generate this additional 

power as so there are no incremental emissions associated with 

that additional power. As a result, the incremental electric 

generation output from the WHP facilities could be considered 

non-emitting and the MWh of electrical output used to adjust the 

CO2 emission rate of an affected EGU. 

 Most commenters noted the benefits for WHP at the same time 

they discussed the benefits of CHP. The commenters reflected 

that WHP is another compliance option and requested it be called 

out explicitly as a compliance option. The comments discussed 

WHP benefits but did not elaborate on a preferred accounting 

 

687 This configuration is sometimes referred to as a “bottoming 

cycle” CHP unit. In such a configuration, the waste heat stream 

could also be generated from a mechanical process, such as at 

natural gas pipeline compressors. 
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method. 

c. Measures that may not be used to adjust a CO2 emission rate. 

This section addresses measures that may not be used to adjust a 

CO2 emission rate. Other new and existing non-affected fossil 

fuel-fired EGUs that are not subject to CAA section 111(b) or 

111(d) may not be used to adjust the CO2 emission rate of an 

affected EGU. While generation from such units could substitute 

for generation from affected EGUs, the EPA has determined that 

additional incentives for such generation, in the form of an 

explicit adjustment to the CO2 rate of an affected EGU, are not 

necessary or warranted. Providing for such an adjustment could 

create perverse incentives for the construction of new simple 

cycle CTs that are not subject to the applicability criteria of 

final Standards of Performance for Greenhouse Gas Emissions from 

New Stationary Sources: Electric Utility Generating Units rule. 

For example, such units could provide only limited adjustment 

credit, as operation beyond a certain capacity factor threshold 

would trigger applicability under CAA section 111(b). Further, 

providing for the ability to generate adjustment credits would 

provide incentives for construction of less efficient fossil 

generating capacity than would likely otherwise be constructed 

(e.g., addition of a simple cycle combustion turbine rather than 

a NGCC unit). In addition, providing for the ability to generate 
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adjustment credits could create perverse incentives for the 

continued operation of less efficient existing fossil generating 

capacity. Such outcomes run counter to the objectives of this 

final rule. 

d. Measures that reduce CO2 emissions outside the electric power 

sector. Measures that reduce CO2 emissions outside the electric 

power sector may not be counted toward meeting a CO2 emission 

performance level for affected EGUs or a state CO2 goal, under 

either a rate-based or mass-based approach, because all of the 

emission reduction measures included in the EPA’s determination 

of BSER reduce CO2 emissions from affected EGUs. Examples of 

measure 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,688 direct air capture, 

and crediting of CO2 emission reductions that occur in the 

transportation sector as a result of vehicle electrification. 

 

688 We note, however, that the final emission guidelines allow 

state measures like emission budget trading programs to include 

out-of-sector GHG offsets. For example, both the California and 

RGGI programs allow for the use of allowances awarded to GHG 

offset projects to be used to meet a specified portion of an 

affected emission source’s compliance obligation. The RGGI 

program contains a cost containment allowance reserve that makes 

available additional allowances up to a certain amount, at 

specified allowance price triggers. See section VIII.C.3.b(2)(a) 

of this preamble.
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2. Treatment of interstate effects 

In the June 2014 proposal, the EPA acknowledged that 

emission reduction measures implemented under a state plan will 

likely have impacts across state boundaries due to the 

interstate nature of the electric grid, as is discussed above in 

section VIII.G. These interactions, herein called interstate 

effects, may be driven in part due to differences in power 

sector dynamics across states, including the types of affected 

EGUs in a state, the availability of eligible non-emitting 

resources, and the costs of different compliance options and 

existing policies in states. These state-level characteristics 

play out across dynamic regional grids that provide electricity 

across state borders. EGUs are dispatched both within and across 

state borders and are constantly adjusting behavior in response 

to generation and electricity demand on the regional grid. 

Whenever CO2 emission reduction measures, such as RE or demandside EE, are implemented, the RE or demand-side EE can affect 

EGU generation and CO2 emissions across the regional grid. These 

dynamics can change across multiple affected EGUs on a minuteto-minute, hour-to-hour, and day-to-day basis as electricity 

demand changes and different generating resources are 

dispatched. These dynamics will also change in the long-term, as 

the generating fleet and load behavior change over a period of 
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years. Interactions among 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 state 

policies and interstate grids, commenters expressed concern 

about the risk of double-counting of measure impacts across 

states and the potential for distortionary incentives between 

states that could undermine overall CO2 emission reductions 

(i.e., emissions “leakage”). Commenters requested that the EPA 

ensure that states avoid double-counting when demonstrating 

achievement of state goals and minimize leakage effects. 

The EPA acknowledges that some amount of interstate effects 

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. The EPA has incorporated elements into the rule that seek 

to minimize interstate effects. First, states have the option to 

adopt multi-state compliance that reflects regional 

interactions. Second, in the method for rate-based plan 

compliance, the rule provides a general accounting approach for 

adjusting a source or state’s CO2 rate that inherently acts to 

minimize state differences. Third, the final CO2 performance 

rates uniformly apply the same standard for affected source 
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sectors across the states and also account for the regional 

supply of RE available to states. These points are further 

discussed below. 

For both rate-based and mass-based approaches, the rule 

provides states with the option of creating either multi-state 

plans or trading-ready plans. Both strategies can be effective 

in minimizing interstate effects because the regional impacts of 

emission reduction actions across states contribute to meeting 

aggregate rate-based or mass-based CO2 emission goals. 

 Under all types of state plans, states must ensure that the 

measures and associated CO2 emission reductions counted as part 

of meeting their plan requirements are not duplicative of any 

measures that are counted by another state. Interstate effects 

make this more difficult because states may be responsible for 

the deployment of measures that have effects on generation and 

emissions beyond the state borders. 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 general accounting approaches for both 

mass-based and rate-based plans minimize the risk of double 

counting. 

Mass-based plans rely exclusively on reported stack 
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emissions for determining whether a mass-based CO2 emission goal 

is achieved. This means that under a mass-based plan any 

emission reduction measures that are implemented are 

automatically accounted for in reduced stack emissions of CO2

from affected EGUs, which avoids concerns about counting the 

same mass reductions in two different 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 the RE and demandside EE that they use to adjust their CO2 emission rate are nonduplicative. The proposal attempted to address this issue in 

part by limiting demand-side EE that states could claim to instate measures. In fact, those in-state measures still have an 

impact outside of the state and states are 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-ofstate measures, while addressing interstate effects through the 

structure of its accounting approach for adjusting the CO2

emission rate of an affected EGU, detailed in section VIII.C.1 

above, used to show that the state has met its obligation under 
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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 

following discussions refer to the substituting generation and 

energy savings in question as RE and demand-side EE, but this 

method can apply to other non-BSER technologies that substitute 

for affected EGU generation. The adjusted CO2 emission rate gives 

credit to the affected EGU or state for the MWhs of RE and 

demand-side EE it is responsible for deploying, by allowing 

those MWhs to be added to the denominator of the CO2 rate, but 

makes no adjustment to the numerator. Instead, the numerator 

reflects reported stack emissions, which will reflect the extent 

to which RE and demand-side EE reduced the affected EGU’s 

generation and emissions, without needing to account for the 

state in which the RE or demand-EE originated, or exactly how it 

impacted the regional grid. 

Across states with rate-based plans, the accounting method 

avoids potential double-counting of both components of a CO2

emission rate: CO2 emission reductions and generation. Doublecounting of CO2 emission reductions is prevented because there is 

no explicit adjustment to the numerator of the reported CO2
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emission rate that could be redundant to CO2 emission reductions 

already represented in reported CO2 emissions from the affected 

EGU, resulting in double-counting.689 Double-counting of MWhs in 

the denominator can be avoided because adding the MWh that the 

affected EGU is responsible for deploying to the denominator is 

relatively straightforward to quantify and assign, and aligns 

well with the MWh-denominated trading system described in this 

final rule. As long as it is assured that the MWhs of RE and 

demand-side EE are only being claimed by one state, as is 

outlined in section VIII.C.2, 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. 

 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 

 

689 If a MWh of substitute generation or avoided generation 

replaced generation at another affected EGU, CO2 emission 

reductions would be represented in reduced reported CO2 emissions 

from that affected EGU. Again, a double-counting of emission 

reduction effects would occur. 
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mass-based resources in a rate-based state would result in 

double-counting of emission reductions. 

Commenters provided analyses specifying how two states can 

benefit from the same RE and demand-side EE measures as a result 

of rate- and mass-based plan interactions. Some commenters 

considered this double-counting of emission reductions, and 

requested specific mathematical adjustments of reported 

generation or CO2 emissions from affected EGUs under either ratebased or mass-based state plans in order to eliminate doublecounting. 

The EPA has determined that, in the context of interactions 

among rate-based and mass-based plans, there is not explicit 

double-counting of the CO2 emission reductions associated with 

counting measures located in mass-based states, considering the 

accounting methods outlined in this final rule. First, as 

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 
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EGUs in a mass-based state, the effect of those measures is 

reflected in lower reported CO2 emissions. The CO2 emission 

reductions reflected in the rate and the mass state will 

necessarily be mutually exclusive, because both are based on 

reported stack emissions. Additionally, the mechanism in the 

mass-based state that is assuring CO2 emission reductions is the 

mass goal or cap, which is met by affected sources adjusting 

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 eroded 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. As a result, 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. 

While the EPA understands this concern, we do not believe 

it is appropriate to restrict RE and demand-side EE crediting 
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unilaterally between rate-based and mass-based states. Such a 

restriction could cut some states off from regional RE supplies 

that are assumed in BSER building block 3 and incorporated in 

the CO2 emission performance rates or state rate-based CO2 goals 

in the emission guidelines. Allowing crediting between rate- and 

mass-based states, as long as the risk of foregone CO2 emission 

reduction actions in rate-based states are minimized, will 

assure a supply of eligible low- and zero-emitting 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 or 

demand-side EE measures, or similar low- or zero-emitting 

measures, located in mass-based states only if the measure is 

implemented to meet electricity load in a state with a ratebased plan.690 To assure that measures used to adjust a CO2

emission rate meet this condition, the EPA is requiring that 

measures providing zero- or low-emitting generation from nonaffected EGUs located in a mass-based state, such as RE, can 

only be counted if the energy generated is delivered to meet 

load in a state with a rate-based plan. This can be demonstrated 

through, for example: 1) the provision of a power delivery 

 

690 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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contract or power purchase agreement in which an entity in the 

rate-based state contracts for the supply of the mass-based MWhs 

in question and 2) documentation that this was done specifically 

to serve rate-based state load. The EPA is providing flexibility 

to states regarding the nature of the required demonstration, 

though the state must specify eligible demonstrations for 

approval in state plans. 

Under an emission standards plan, this demonstration would 

be made by the provider of the measure seeking ERC issuance to 

the rate-based state. Under a state measures plan, the ratebased state will need to provide the demonstration of geographic 

eligibility as part of its demonstration that it is meeting its 

CO2 emission performance rates or achieving the state CO2

emission goal for affected EGUs. 

 The following are examples of how requirements for a 

demonstration could be established in state plans and used to 

allow a resource in a mass-based state to be counted in a ratebased state. For an emissions 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 a 

provider of RE that seeks the issuance of ERCs to show that 

entities in the rate-based state have contracted for the 

delivery of the RE generation that occurs in a mass-based state 
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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 energy savings were procured by the 

utility, and were treated as comparable to a generation resource 

used to serve regional load that included the rate-based state. 

This documentation would be sufficient demonstration to allow 

the RE generating resource to meet the additional geographic 

eligibility requirement for generation of ERCs. All quantified 

and verified MWhs submitted for ERC issuance would need to be 

associated with that power purchase contract or agreement, and 

this fact would need to be demonstrated in the monitoring and 

verification reports submitted for issuance of ERCs. 

 Under a state measures rate-based plan, a state could 

require that any eligible MWhs that the state claims from a 

mass-based state are the result of contracted arrangements 

between entities in the rate-based state and providers in the 

mass-based state. If the state plan was approved by the EPA, 

such demonstrations would need to be submitted with the state’s 

demonstration of how its state measures meet the CO2 emission 

performance rates or achieve the state rate-based CO2 emission 

goal for affected EGUs. 

 The ability for a rate-based state to count MWhs located in 
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a mass-based state under the above conditions is limited to nonaffected generating resources that are considered low- or zeroemitting, such as RE. This treatment does not apply to fossilfuel fired EGUs, such as NGCC. If a mass-based emission limit 

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. 

 As stated earlier, commenters also expressed concern about 

the potential for a loss of emission reductions to occur given 

relative differences between states. These differences could 

include states’ goals under either the rate- or mass-based 

approaches, or states’ accounting of new sources. These 

differences could induce increased generation in one state over 

another because the costs of compliance and relative costs of 

generation would vary between states. There was particular 

concern regarding how these differences would provide incentives 

for building new generation and expanding utilization of 

affected EGU generation in states that have less stringent 

goals. This could potentially result in the achievement of 

performance rates but with fewer overall CO2 emissions reductions 

than projected nationally under the proposal. 

 In order to address these concerns, the EPA has determined 

final performance rates that serve to reduce relative 
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differences between state goals, and thus the risk of leakage 

based upon those effects. In the proposal, goals differed 

significantly between states based upon individual assumptions 

included in the calculation. In the final rule, we are 

finalizing CO2 emission performance rates for fossil fuel-fired 

electric utility steam generating units and stationary 

combustion turbines that are applied consistently across all 

affected EGUs. Additionally, these finalized performance rates 

were calculated regionally, further narrowing the differences 

across states. As the same sector performance rates are applied 

to all states, any differences stem from the relative prevalence 

of fossil fuel-fired electric utility steam generating units and 

stationary combustion turbines. 

Commenters also suggested that the 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. 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-
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emitting MWhs would create more mass-denominated credits in 

those states, and thus RE and demand-side EE would be more 

valuable. 

 The incentive to target the location of zero-emitting 

generation or energy savings between states based on variation 

in its emission reduction value has been minimized by the nature 

of the accounting method finalized in this rule. As explained 

above on the general accounting approach and on the trading 

framework, we are adjusting rates using calculated MWhs, not 

based upon an emission reduction approximation as commenters 

outlined above. Not only does the method allow emission 

reductions to be accounted for as they occur across the grid, 

but it means the ERCs being traded across states represent one 

MWh of 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 zeroemitting ERCs in a particular state based upon the rates that 

apply to that state. 

3. Requirements for rate-based emission trading approaches 

 As with all approaches under the emission standards plan 

type, emission standards in a state plan that include a ratebased emission trading program must be quantifiable, verifiable, 
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enforceable, non-duplicative and permanent.691 A state plan using 

a rate-based emission trading approach must include emission 

standards for affected EGUs that include requirements specifying 

the rate-based emission standards and related implementation and 

compliance requirements and mechanisms.692 These related 

requirements include those applicable to rate-based emission 

standards more broadly: CO2 emission monitoring, reporting, and 

recordkeeping requirements for affected EGUs, including 

requirements for monitoring and reporting of useful energy 

output. Related requirements for a rate-based emission trading 

program more specifically include provisions for issuance of 

ERCs by the state and/or its designated agent; provisions for 

tracking ERCs, from issuance through submission for compliance; 

and the administrative process for submission of ERCs by the 

owner or operator of an affected EGU to the state, in order to 

adjust its reported CO2 emission rate when demonstrating 

compliance with a rate-based emission standard.693 These 

requirements specific to rate-based emission trading programs 

are design elements the EPA has determined are necessary to 

 

691 These requirements are described in detail in section 

VIII.D.2.

692 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. 

693 See section VIII.G.1 for a discussion of the accounting 

method used to adjust a CO2 emission rate. 
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assure the integrity of a rate-based approach that includes an 

emission trading program, and therefore assures a state plan 

utilizing such an approach appropriately provides for the 

implementation of rate-based emission standards in accordance 

with CAA section 111(d). 

The EPA will review a state plan submittal including a 

rate-based emission trading program to assure that the plan 

contains the design elements necessary to assure the integrity 

of a rate-based approach, and therefore provide for the 

implementation of rate-based emission standards. These design 

elements are discussed in more detail in this subsection, and 

the EPA for each design element has also provided what it views 

as an appropriate way for states to meet each such element so as 

to provide for the implementation of rate-based emission 

standards through an emission trading program. The EPA expects 

that state plans containing a rate-based emission trading 

program that includes components as substantively described for 

each of the design elements will be presumptively approvable (so 

long as the rate-based emission standards are also appropriately 

demonstrated to achieve the CO2 emission performance rates or 

state CO2 goal). States may submit a rate-based emission trading 

program with alternative components other than those described, 

so long as the program includes each of the required design 
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elements and the state satisfactorily demonstrates in the state 

plan submittal that such alternative means of addressing the 

design elements are as adequately stringent as the presumptively 

approvable approach as described, and therefore provide for the 

implementation of the state plan’s rate-based emission 

standards. 

A state may issue ERCs to an affected EGU that performs at 

a CO2 emission rate below a specified CO2 emission rate, as well 

as to providers of qualifying measures that provide substitute 

generation for affected EGUs or avoid the need for generation 

from affected EGUs. This latter category includes providers of 

qualifying RE and demand-side EE measures, as well as other 

types of measures, as discussed in section VIII.G.1.b.694 

 ERCs may be used by an affected EGU to adjust its reported 

CO2 emission rate when demonstrating compliance with a rate-based 

emission limit. This adjustment is made by adding MWh to the 

denominator of an affected EGU’s reported CO2 emission rate, in 

the amount of submitted ERCs, resulting in a lower adjusted 

 

694 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 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 and add the MWh the ERCs represent to the 

denominator of the affected EGU’s reported CO2 lb/MWh emission 

rate. If the affected EGU’s adjusted CO2 emission rate is equal 

to or lower than its applicable emission rate standard, the 

affected EGU would be in compliance. 

a. Issuance of ERCs to affected EGUs. ERCs may be issued to 

affected EGUs that emit below a specified CO2 emission rate. For 

issuance of ERCs to affected EGUs, the state plan must specify 

the accounting method and administrative process for ERC 

issuance. This includes the calculation method for determining 

the number of ERCs to be issued to an affected EGU, based on 

reported CO2 emissions and MWh energy output, in comparison to a 

reference CO2 emission rate. The reference rate is a specified 

CO2 lb/MWh emission rate that an affected EGU’s reported CO2

emission rate is compared to, when determining the amount of 

ERCs that may be issued to an affected EGU. 

Following determination of the number of ERCs an affected 

EGU is eligible to receive, based on an affected EGU’s reported 
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CO2 emission rate compared to a specified reference rate, the 

state regulatory body would issue those ERCs into a tracking 

system account held by the owner or operator of the affected 

EGU. Tracking system requirements are addressed below at section 

VIII.G.3.c. 

The accounting method that may be applied in a state plan 

differs depending on whether a state plan includes a single 

rate-based emission standard that applies to all affected EGUs 

(e.g., if a plan is designed to meet a state rate-based CO2 goal) 

or separate rate-based emission standards that apply to 

subcategories of affected EGUs, namely fossil fuel-fired 

electric utility steam generating units and stationary 

combustion turbines. In both cases, ERCs are issued in MWh, 

based on the difference between an affected EGU’s reported CO2

emission rate (in CO2 lb/MWh) and a specified CO2 lb/MWh emission 

rate that the reported rate is compared to (referred to as a 

“reference rate”). The reference rate may be an affected EGU’s 

assigned CO2 emission limit rate or another CO2 emission rate, as 

described below. Where an affected EGU’s reported CO2 emission 

rate is lower than the specified reference CO2 emission rate, 

ERCs may be issued. 

Where a state plan includes emission standards in the form 

of a single rate-based emission standard that applies to all 
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affected EGUs, the reference rate is the CO2 emission rate limit 

for affected EGUs. In this instance, ERCs may be issued based on 

an affected EGU’s reported CO2 emission rate as a proportion of 

the emission limit rate. For example, if the emission rate limit 

is 2,000 lb CO2/MWh and the affected EGU emits at a rate of 1,000 

lb CO2/MWh, 0.5 MWh would be awarded for every MWh generated by 

the affected EGU. ERCs would be issued to affected EGUs in whole 

MWh increments. The calculation method is as follows: 

ERCs695 = reported MWh by affected EGU696 x ((CO2 emission 

rate limit for affected EGUs697 – affected EGU reported CO2

emission rate698)/ 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 

 

695 For all calculations in this section, where the result is a 

negative value, no ERCs would be issued.

696 This term represents the reported MWh by the affected EGU on 

an annual basis. 

697 This term represents the “reference rate.” 

698 This term represents the annual reported CO2 emission rate of 

the affected EGU.
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stationary combustion turbines, the reference rate differs for 

affected fossil fuel-fired electric utility steam generating 

units and stationary combustion turbines. 

For affected steam generating units, the reference CO2

emission rate is the assigned CO2 emission rate limit for steam 

generating units. 

For affected steam generating units, the following 

accounting method for generating ERCs applies: 

ERCs699 = reported MWh x ((steam generating unit CO2 emission 

rate limit700 – steam generating unit reported CO2 emission rate)/ 

steam generating unit CO2 emission rate limit). 

For affected stationary combustion turbines, the reference 

CO2 emission rate differs for “non-incremental” generation and 

“incremental” generation from the affected stationary combustion 

turbine. Incremental generation by an affected EGU is defined as 

annual energy generation, in MWh, that is greater than reported 

MWh generation by the EGU in 2012. For example, assume an 

affected stationary combustion turbine generated 1,000,000 MWh 

in 2012 and 1,100,000 MWh in 2022; the stationary combustion 

turbine’s incremental generation in 2022 is 100,000 MWh and its 

non-incremental generation is 1,000,000 MWh. 

 

699 For all calculations in this section, where the result is a 

negative value, no ERCs would be issued. 

700 The “reference rate.” 
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For affected stationary combustion turbines, the following 

accounting method for generating ERCs applies for nonincremental generation: 

ERCs = reported MWh x ((stationary combustion turbine CO2

emission rate limit701 – stationary combustion turbine reported 

CO2 emission rate)/ stationary combustion turbine CO2 emission 

rate limit) 

Under this approach, ERC issuance is assessed based on the 

difference between the CO2 emission rate limit for affected 

stationary combustion turbines702 and the reported CO2 emission 

rate of the affected stationary combustion turbine. 

For affected stationary combustion turbines, the following 

accounting method for generating ERCs applies for incremental

generation: 

ERCs = reported MWh x [((steam generating unit CO2 emission 

rate limit703 – stationary combustion turbine reported CO2

emission rate)/ steam generating unit CO2 emission rate limit) + 

((stationary combustion turbine CO2 emission rate limit704 - 

stationary combustion turbine reported CO2 emission rate)/ 

stationary combustion turbine CO2 emission rate limit)] 

 

701 The “reference rate.” 

702 This is the CO2 emission performance level for affected 

stationary combustion turbines in the emission guidelines.

703 The “reference rate.”

704 The “reference rate.”
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Under this approach, ERC issuance is assessed based in part 

on the difference between the CO2 emission performance level for 

fossil steam generating units and the reported CO2 emission rate 

of the affected stationary combustion turbine. The calculation 

also accounts for the difference in an affected stationary 

combustion turbine’s reported CO2 emission rate and the CO2 rate 

limit for affected stationary combustion turbines.705 This avoids 

over-crediting where an affected stationary combustion turbine 

emits above its assigned CO2 emission rate limit. Overall, this 

calculation method allows for issuance of ERCs based on the 

ability of incremental generation from affected stationary 

combustion turbines to substitute for generation from affected 

steam generating units (as represented in building block 2), 

while also respecting the fact that affected stationary 

combustion turbines must also meet an assigned CO2 emission rate 

limit for the entirety of its MWh energy output. 

For example, assume an affected stationary combustion 

turbine with a CO2 emission rate of 800 lb CO2/MWh; a stationary 

combustion turbine CO2 emission rate limit of 700 lb CO2/MWh; and 

a steam generating unit CO2 emission rate limit of 1,300 lb 

CO2/MWh. For every incremental MWh of reported energy generation 

 

705 This is the CO2 emission performance level for affected 

stationary combustion turbines in the emission guidelines. 
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by an affected stationary combustion turbine, ERCs would be 

issued in the following amount: 

ERCs = reported incremental MWh x [(1,300 – 800)/1,300 + 

(700 – 800)/700] = reported incremental MWh x [0.38 + (-0.14)] = 

reported MWh x 0.24706

Thus, for every incremental MWh of reported energy 

generation by an affected stationary combustion turbine, 0.24 

ERCs would be generated. ERCs would be issued in whole MWh 

increments. 

These accounting requirements maintain consistency with the 

EPA’s application of BSER when calculating CO2 emission 

performance rates for affected stationary combustion turbine and 

steam generating units. In particular, this accounting treatment 

maintains consistency of accounting in a state rate-based CO2

emission standard with the EPA’s application of building block 2 

in calculating CO2 emission performance rates for affected fossil 

 

706 This calculation accounts for incremental generation from the 

affected stationary combustion turbine, while acknowledging that 

stationary combustion turbine generation is low-emitting, but 

not non-emitting. The calculation also acknowledges that in this 

instance, the affected stationary combustion turbine’s reported 

CO2 emission rate is higher than its applicable emission rate 

limit. As a result, for every MWh of generation, the stationary 

combustion turbine accrues a compliance debit that must be met 

through submission of ERCs. This calculation avoids overcrediting for incremental generation by affected stationary 

combustion turbines, where an affected stationary combustion 

turbine emits above its assigned CO2 emission rate limit. 
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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.707 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 project708 to the 

administering state regulator (or its agent709). The state 

regulator reviews the application to determine whether, in this 

example, an EE/RE program or project meets eligibility 

 

707 Qualifying measures that can be used to adjust the CO2

emission rate of an affected EGU are discussed at subsection 

VIII.G.1, and include RE, demand-side EE, and other measures, 

such as DSM, CHP and incremental nuclear generation.

708 For example, for an EE/RE program or project, as described in 

this section for illustrative purposes. The requirements 

described in this section for EE/RE programs and projects also 

apply for all other eligible qualifying measures discussed in 

subsection VIII.G.1. 

709 As used here, an agent is a party acting on behalf of the 

state, based on authority vested in it by the state, pursuant to 

the legal authority of the state. A state could designate an 

agent to provide certain limited administrative services, or 

could choose to vest an agent with greater authority. Where an 

agent issues an ERC on behalf of the state, such issuance would 

have the same legal effect as issuance of an ERC by the state. 
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requirements for the issuance of ERCs.710 An eligibility 

application must include a description of the program or 

project, a projection of the MWh generation or energy savings 

anticipated over the life of the program or project, and an EM&V 

plan that meets state requirements. The EM&V plan must describe 

how MWh of RE generation or energy savings resulting from the 

program or project will be quantified and verified.711 A state, 

in its emission standard regulations, must include requirements 

for EM&V plans that are consistent with the requirements in the 

emission guidelines for EE/RE measures and other eligible 

measures, as discussed in section VIII.G.1 above, and section 

VIII.C.4 below. 

 The EPA has determined that state requirements for an 

eligibility application must include review of the application 

by an accredited independent verifier prior to submittal. This 

 

710 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, and 

administrators of state EE programs, among others. 

711 The verification process includes confirmation that 

quantified MWh are non-duplicative and permanent (i.e., are not 

being used in any other state plan to demonstrate compliance 

with an emission standard or achievement of a state CO2 goal). 
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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.712 An assessment by 

an accredited independent verifier would be included as a 

component of an eligibility application. 

 The EPA has determined that independent verification 

requirements are necessary to ensure the integrity of state 

rate-based emission trading programs included in a state plan, 

given the wide range of eligible measures that may generate ERCs 

and the broad geographic locations in which those measures may 

occur. Inclusion of an independent verification component 

provides technical support for state regulatory bodies to ensure 

that eligibility applications and monitoring and verification 

reports are thoroughly reviewed prior to issuance of ERCs. 

 Rate-based emission trading programs used in a state plan 

must include requirements for independent verifiers that specify 

necessary qualifications and codes of conduct when providing 

 

712 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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verification services. State requirements must include 

accreditation requirements for independent verifiers that 

specify that only accredited verifiers may provide verification 

services and detail the requirements for accreditation and 

maintenance of accreditation status.713 

 These requirements must ensure that verifiers have 

sufficient knowledge of the rate-based emission trading program 

rules, technical expertise, and knowledge of auditing, 

accounting, and information management practices. Accredited 

verifiers must be independent. Accredited verifiers may not 

provide verification services for any ERC provider for which 

they have a financial, management, or other interest.714 Such 

 

713 In this subsection, the term “verifier” is used 

interchangeably to refer to both a “verification body” (i.e., a 

verification company or organization) and a “verifier,” which is 

an individual that is a principal or employee of a verification 

body. 

714 Accredited verification bodies and individual verifiers may 

not have any direct or indirect organizational or personal 

relationships with an ERC provider that would impact their 

impartiality in assessing the validity and accuracy of the 

information in an eligibility application or M&V report. In 

addition to this general requirement, the following specific 

requirements also apply. Accredited verifiers must have no 

direct or indirect financial interest in, or other financial 

relationships with, an ERC provider or any related program or 

project that seeks issuance of ERCs. Accredited verifiers must 

have no relationship with the implementer of a program or 

project that seeks the issuance of ERCs, or any related ERC 

provider, that would represent a COI. Accredited verifiers must 

have no role in the development and implementation of a program 

or project that seeks issuance of ERCs, beyond the provision of 
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relationships constitute a conflict of interest (COI). COI 

situations may also arise as a result of personal relationships 

among individuals representing an ERC provider and an accredited 

verifier. State requirements must specify that a verification 

report will not be accepted as part of an eligibility 

application or M&V report where the accredited verification body 

or any individual verifier has a COI. Accredited verification 

bodies must have management protocols in place to identify and 

remedy any COI prior to provision of verification services. 

State requirements should specify that failure of an accredited 

verifier to identify and adequately address any COI prior to 

provision of verification services is grounds for revocation of 

accreditation. State accreditation requirements should include 

periodic performance reviews by the administering state 

regulatory body of accredited verifiers, to ensure that 

verifiers are maintaining necessary technical and professional 

 

verification services. Accredited verifiers must not be 

compensated, directly or indirectly, in relation to the 

quantified and verified MWh in an M&V report or on the basis of 

program or project approval, ERC issuance, or the number of ERCs 

issued. Accredited verifiers may not hold ERCs, or other 

financial derivatives related to ERCs, or have a financial 

relationship with other parties that hold ERCs or other related 

financial derivatives. Verification reports must include an 

attestation by the accredited verifier that it assessed 

potential COI related to an ERC provider and adequately 

addressed any identified COI. 
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qualifications and are meeting program requirements for 

provision of verification services. State accreditation 

requirements may recognize in part accreditation by an outside 

organization other than the state, where such outside 

accreditation demonstrates that certain state requirements are 

met.715 

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.716 These 

provisions will ensure that actions that are eligible for the 

issuance of ERCs are “non-duplicative.”717 The tracking system 

used to administer a state’s rate-based emission trading system 

must provide transparent, electronic, public access to 

information about program and project eligibility applications, 

including EM&V plans, and regulatory approval status. 

 In the second step of the process, following implementation 

 

715 An example is ANSI accreditation under ISO 14065:2013 for GHG 

validation and verification bodies. More information is 

available at 

https://www.ansica.org/wwwversion2/outside/GHGgeneral.asp?menuID

=200. 

716 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. 

717 Emission standards must be “non-duplicative” as described in 

section VIII.D.2. 
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of the RE/EE program or project, in this example, that was 

approved in step one, the RE/EE provider periodically submits a 

monitoring and verification (M&V) report to the state regulatory 

body documenting the results of the program or project in MWh of 

electric generation or energy savings.718 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 requirements must ensure that only one ERC is issued 

for each verified MWh. This is addressed through registration in 

the tracking system of programs and projects that have been 

qualified for the issuance of ERCs, to ensure that documentation 

 

718 State rate-based emission trading program regulations should 

specify the frequency for submission of monitoring and 

verification reports for approved qualified measures that have 

been deemed eligible to generate ERCs. 
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is submitted only once for each RE/EE action, and to only one 

state program.719 The tracking system must provide transparent 

electronic public access to submitted M&V reports and regulatory 

approvals related to such reports.720 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,721 and an accompanying tracking system 

infrastructure design based on business rules specified in the 

emission trading program regulations. Each issued ERC must have 

 

719 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. 

720 This must include electronic Internet access to such 

information in the tracking system. 

721 “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 limit. 
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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. 

It is thus essential that the ultimate responsibility for 

the validity of the ERC rest with the entity that must achieve 

compliance with an emission standard. An approvable state plan 

that allows affected EGUs to comply with their emission 

standards in part through reliance on ERCs must include 

provisions making clear that an affected EGU may only use 

properly issued, valid ERCs to demonstrate compliance with its 

emission standard. An EGU that submits for compliance with its 

emission standard an ERC that does not actually represent an 

eligible MWh of zero-emission generation is subject to CAA 

liability for failure to meet its emission standard for each day 

of the relevant compliance period, and must submit two properly 

issued, valid replacement ERCs to the state regulatory body 

within a specified period of time, in accordance with the 

emission guidelines. This is true regardless of the good faith 

of the EGU in purchasing or obtaining the ERC. The state plan 

must also make clear that the EGU is also subject to CAA 

liability for failure to timely submit replacement ERCs. 

e. Considerations for ERC issuance. The EPA notes that stateadministered and state-overseen EE programs, such as those 

administered by state-regulated electric distribution utilities, 
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could play a key role in supplying energy savings to a ratebased emission trading system in the form of ERCs. These 

programs have been the primary means for delivering EE programs 

and energy savings at scale, and also allow for a state to 

conduct a portfolio planning process to guide EE program design 

and focus in a manner that best provides multiple benefits to 

electricity ratepayers in a state. Such portfolio planning 

processes typically treat EE as an energy resource comparable to 

electricity generation. 

 The EPA also notes that non–ERC certificates may be issued 

by states and other bodies for MWh of energy generation and 

energy savings that are used to meet other state regulatory 

requirements, such as state RPS and EERS, or by individuals to 

make environmental or other claims in voluntary markets. 

 The EPA defines an ERC in the emission guidelines as a 

tradable compliance instrument that represents a zero-emission 

MWh from a qualifying measure that may be used to adjust the 

reported CO2 emission rate of an affected EGU subject to a ratebased emission standard in an approved state plan under CAA 

section 111(d). The sole purpose of an ERC is for use by an 

affected EGU in demonstrating compliance with a rate-based 

emission standard in such an approved state plan. 

 An ERC is issued separately from any other instruments that 
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may be issued for a MWh of energy generation or energy savings 

from a qualifying measure. Such other instruments may be issued 

for use in meeting other regulatory requirements (e.g., such as 

state RPS and EERS requirements) or for use in voluntary 

markets. An ERC may be issued based on the same data and 

verification requirements used by existing REC and EEC tracking 

systems for issuance of RECs and EECs. 

4. Evaluation, measurement and verification (EM&V) requirements 

for RE and demand-side EE resources used to adjust a CO2 rate 

This section identifies and discusses the EM&V criteria 

used to quantify MWh savings from demand-side EE and generation 

from zero-emitting RE.722 These criteria apply in the context of 

both emission standard plans and state measures plans, as 

described below. The EPA is finalizing these criteria as 

applicable requirements in the context of state plans that 

employ a rate-based emission trading program. These criteria are 

described below. State plans must require that MWh savings from 

demand-side EE and generation from zero-emitting RE are 

quantified per these criteria.723 

 

722 EM&V is defined to mean the set of procedures, methods, and 

analytic approaches used to quantify the MWh from demand-side EE 

and RE, and thereby ensure that the resulting savings and 

generation are quantifiable and verifiable. 

723 For a rate based emission standards plan type, the 

requirement to quantify the MWh from demand-side EE and RE per 
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Additionally, with respect to these criteria, the EPA 

describes certain established standard industry practices that 

would be presumptively approvable as an approach to include 

these criteria in state plans. States must submit these criteria 

as specified, or alternatively, states may submit the standard 

industry practices described as presumptively approvable. States 

may also submit other means of meeting the criteria so long as 

the state satisfactorily demonstrates in the state plan 

submittal that such alternative means of addressing criteria are 

as adequately stringent as the presumptively approvable approach 

described here. 

As discussed in VIII.G.3., quantified and verified MWh of 

RE generation, and quantified and verified MWh avoided from 

implementing demand-side EE measures,724 may be used to adjust a 

CO2 emission rate when demonstrating compliance with the emission 

 

the EM&V criteria must be included in the federally enforceable 

state plan. For a state measures plan implementing rate based 

state measures, applicable state laws must reflect the 

requirement to quantify the MWh from demand-side EE and RE per 

the EM&V criteria, and such state only requirements must be 

adequately described in the supporting documentation submitted 

with the state plan. 

724 In the context of demand-side EE, “measure” refers to an 

installed piece of equipment or system at an end-use energy 

consumer facility, a strategy intended to affect consumer energy 

use behaviors, or a modification of equipment, systems or 

operations that reduces the amount of energy that would 

otherwise have been used to deliver an equivalent or improved 

level of end-use service. 
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guidelines. In states implementing emission standard type plans 

with rate-based trading, affected EGUs adjust their reported 

emission rate using ERCs, which represent MWh that are 

quantified and verified according to the EM&V criteria included 

in this section. Providers of EE and RE who seek to earn ERCs 

must develop EM&V plans outlining how they will quantify and 

verify the results of their efforts. These providers are then 

required to submit EM&V plans as part of their application to 

the state regulatory body for project approval.725 

In states implementing state measures type plans, 

quantified and verified MWh of RE and EE may be used to adjust 

an emission rate through two pathways. First, if the state 

measures plan enables rate-based trading, the affected EGUs may 

use ERCs to adjust their reported rate (per the rate-based 

emission standard approach). Alternatively, if the state 

measures plan elects to incorporate RE and demand-side EE 

outside of an ERC trading program – for example through adoption 

and implementation of an EERS or RPS – the state itself, rather 

than the project provider, uses the quantified and verified MWh 

of RE and EE to adjust the rate. 

If a state elects to implement a rate-based ERC trading 

 

725 A full discussion of applicable requirements for the 

establishment and functioning of rate-based emissions trading 

systems is provided above, at section VIII.G.3. 
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program as part of its state measures approach, state 

regulations and project provider requirements must be identical 

to those outlined for emission standard plans. For a state 

measures plan, the ERC issuance and EM&V requirements must be 

adequately described in the submittal’s supporting materials to 

enable the EPA to determine whether the state measures plan 

satisfactorily demonstrates the ability of the affected EGUs to 

meet the applicable CO2 emission performance rate or state goal. 

For an emission standards plan, the ERC issuance and EM&V 

requirements would be submitted as a component for approval as 

part of the federally enforceable state plan. However, if the 

state elects to incorporate demand-side EE and RE policies, 

programs, and projects outside of an ERC trading program, the 

state itself, rather than the project provider, must demonstrate 

how it will quantify and verify the results of its efforts. In 

this case, the state must describe in its state plan submission 

how the criteria described herein will be applied to specific 

programs and projects to demonstrate that reported annual MWh 

savings and generation are properly quantified and verified. 

The following discussion presents EM&V criteria for demandside RE and EE measures implemented through both types of state 

plan approaches, followed by a presentation of some additional 

considerations for states implementing RE and EE measures in the 
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context of a state measures plan without rate-based trading. 

5. EM&V criteria for RE and demand-side EE resources used to 

adjust a CO2 rate 

The proposed rule stated that the EPA would establish EM&V 

criteria to help states, sources, and RE and EE providers 

quantify and verify MWh savings and generation resulting from RE 

and demand-side EE efforts. The proposal and associated “State 

Plans Considerations” TSD726 suggested that the EPA’s EM&V 

criteria would leverage the industry-standard practices, 

protocols, and data-sets currently utilized by the majority of 

states currently implementing demand-side EE and RE programs. 

The EPA further noted that many state regulatory bodies and 

other entities already have significant EM&V infrastructure in 

place and have been applying, refining and enhancing their 

evaluation and associated quality assurance approaches for over 

30 years. The EPA took comment on whether this infrastructure is 

appropriate to use as the basis for establishing minimum EM&V 

criteria for use in rate-based state plans that include RE and 

demand-side EE. The majority of commenters addressing this 

question indicated that existing EM&V infrastructure is 

 

726 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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appropriate to assure quality, credibility, and integrity. Thus, 

the final EM&V criteria reflected herein are intended to be 

consistent with and leverage prevailing industry-standard 

evaluation practices. 

In addition, the EPA’s final criteria reflect several 

overarching objectives and principles offered by states, private 

organizations, and the public during the comment period. One of 

these is the importance of striking a reasonable balance between 

EM&V rigor and credibility on the one hand, and the costs 

associated with performance evaluation on the other. Another 

objective for the EPA’s criteria is to avoid excessive 

interference with EM&V practices that are already robust, 

transparent and working well. Therefore, the minimum criteria 

for EM&V in an approvable state plan establish a floor for EM&V 

practices to ensure credibility and certainty in savings 

estimates across jurisdictions. 

a. Submittals. Applicable submittals include EM&V plans and EM&V 

reports. At the front end of a program or project, EM&V plans 

are required to document how applicable criteria will be 

addressed as EM&V is performed over the program or project 

period. After implementation has occurred, EM&V reports are 

required to document and describe how each of the criteria was 

applied on an ex-post basis. These reports also specify the 
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resulting MWh savings or generation values per RE and EE program 

and project category. 

For demand-side EE, EM&V plans and reports for purposes of 

this final rule are intended to leverage and closely resemble 

EM&V plans that are already in routine use for a wide range of 

publicly or rate-payer funded EE programs and energy service 

company (ESCO) projects. For RE, EM&V plans similarly leverage 

resources and approaches to tracking systems for RE that are 

broadly applied. EM&V reports for RE are simply the existing 

output from these tracking systems. 

For all EM&V submittals addressing demand-side EE, the 

applicable metric is electricity savings, which is defined as a 

reduction in electricity consumption. EE savings must be 

determined and reported in units of MWh. The specific procedures 

and requirements for EM&V submittals in the context of an 

emission standard plan are outlined above in section VIII.G.3. 

EM&V submittals for state measures plans are described below. 

b. EM&V criteria that apply to all demand-side EE used to adjust 

an emission rate. The following EM&V criteria apply to all 

demand-side EE used to adjust an emission rate. They are 

supplemented by the program and project specific provisions 

identified below. 

(1) Baseline definitions. A critical EM&V issue is the 
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assumptions and approach used to determine baseline energy use. 

EM&V plans must describe the baselines to be used with clear 

documentation and discussion of the rationale, applicability, 

and relevant data sources, protocols, and guidance documents 

used for defining the baseline. 

(2) EM&V methods used to quantify the results of EE projects and 

programs. This section establishes criteria for the general 

types of EM&V methods that can EE providers can use to quantify 

savings from demand-side EE programs and projects that are used 

to generate ERCs. Consistent with EM&V practices at the state 

level, where PUCs typically allow utilities and other program 

administrators to use a range of EM&V methods that reflect 

applicable circumstances and on-the-ground conditions (versus 

mandating which methods must be used in a particular situation), 

the EPA is likewise providing flexibility for RE and EE 

providers to select from the following broad categories of EM&V 

methods to determine savings. 

Two broad categories of EM&V methods are non-control group 

approaches such as project-based measurement and verification 
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(M&V),727 and control group approaches728 such as randomized 

control trials (RCT). Regardless of the approach selected, a key 

criterion, supported by commenters and consistent with industrystandard practices, is that annual savings values must be 

determined on a regular basis – at intervals sufficient to 

credibly document annual savings – by application of one or more 

of the above-listed EM&V methods. Factors that should be taken 

into consideration when determining the appropriate interval 

include the characteristics of subject EE programs, projects, or 

measures; variability of the savings; the EM&V method used; and 

the relative scale and magnitude of savings. The EPA expects 

that EM&V using the above methods will occur at a minimum of 

four year intervals for building energy codes and product 

standards; every one, two or three years for different publicly 

or rate-payer funded EE programs; and annually for large 

individual commercial and industrial projects. For all demandside EE used to adjust an emissions rate, the selected method, 

associated assumptions, and data sources must be identified and 

 

727 M&V is the process of using measurements to reliably 

determine energy and/or demand savings created within an 

individual facility. The International Performance Measurement 

and Verification Protocol (IPMVP) defines four M&V options used 

in the efficiency industry: two end-use metering approaches, 

energy use data (billing data) regression analysis, and 

calibrated computer simulation. 

728 Also referred to as large-scale consumption data analysis. 
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described in EM&V plans. 

For control group methods, the key EM&V criteria is to 

follow industry standard protocols and guidelines such as those 

published by the SEE Action Network and the U.S. DOE’s Uniform 

Methods Protocols (UMP) project. Where feasible, the EPA seeks 

to encourage the use of RCT approaches to establishing control 

groups, as they involve random selection of comparison groups 

and are therefore less prone to selection bias. 

For M&V methods, the key criteria is that industry-standard 

protocols and guidelines are followed. These include the IPMVP, 

protocols published by the Federal Energy Management Program 

(FEMP), the American Society of Heating, Refrigeration and AirConditioning Engineers (ASHRAE), and the U.S. DOE’s UMP. 

(3) Key considerations for quantifying savings. Regardless of 

the approach used to quantify and verify MWh savings, EM&V plans 

must describe how they will address the following key 

considerations for quantifying savings: 

 How major changes in independent variable conditions 

(weather, occupancy, production rates, etc.) that affect 

energy consumption and savings estimates will be 

analyzed. The effects of these changes can be calculated 

using either real-time conditions or normalized 

conditions that are reasonably expected to occur 
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throughout the lifetime of the EE project or measure. 

 How the initial installation of EE will be verified for 

EE program categories that involve the installation of 

identifiable measures (e.g., most publicly or rate-payer 

funded EE programs and project-based EE evaluated siteby-site and CHP, but not programs that provide customers 

with information). A key criterion is that verification729

is required within the first year of program 

implementation. All verification activities must be 

performed using industry-standard techniques (e.g., phone 

or mail surveys, document review, site inspections, spot 

or shot-term metering). For projects implemented as part 

of a program, verification can be performed using a 

sample of projects to represent the full program 

population. In these cases, sample sizes should be 

defined per the rigor criteria described herein. 

 How avoided T&D systems losses will be included in EE 

savings values. Demand-side EE programs (other than T&D 

efficiency measures such as CVR and volt/VAR 

 

729 Verification is an independent assessment to ensure that the 

EE measures have been installed correctly and have the potential 

to generate the predicted savings. Verification may also include 

assessment of baseline conditions and confirmation that the EE 

measures are operating correctly per their design intent. 
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optimization730) may adjust reported savings by using a 

T&D adder that is based on the lesser of 6 percent731 of 

the site-level savings or the calculated statewide annual 

average T&D loss rate [estimated losses in MWh/(total 

electric supply – direct electricity use)]732 expressed as 

a percentage and based on values in the most recent year 

and published US EIA State Electricity Profile. Since T&D 

efficiency measures such as CVR and volt/VAR may reduce 

both end-use consumption and line losses, MWh savings 

from T&D measures must be calculated on the basis of 

procedures identified in an EM&V plan. 

 How the duration of EE program or project electricity 

savings will be determined using annual verification 

assessments, industry-standard persistence studies, 

deemed estimates of effective useful life (EUL), or a 

combination of all three. If deemed EUL estimates are 

used for determining the duration of savings, then zero 

 

730 More information about these technologies is in section 

VIII.F.1 above. 

731 6 percent is the national average losses from 1990-2012 (See: 

http://www.eia.gov/tools/faqs/faq.cfm?id=105&t=3). 

732 Estimated losses in MWh, total electric supply, and direct 

electricity use values are available in the U.S. EIA’s State 

Electricity Profiles. See table on Supply and Disposition of 

Electricity (currently Table 10). Direct electricity use refers 

to the electricity generated at facilities that is not put onto 

the electricity grid, and therefore does not contribute to T&D 

losses.
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savings must be assumed at the end of a program, project, 

or measure life. If project or program persistence 

studies are conducted at least every 5 years to determine 

the duration of savings, then savings can be counted as 

long as the verification activities indicate continued 

measure operation and performance. 

 How the rigor733 of quantifying MWh savings values will be 

assessed, and the methods used to control the types of 

bias or error relevant inherent to the applied EM&V 

techniques. Rigor can be quantified using statistical 

indicators such as confidence and precision (for annual 

MWh savings, or for a representative sample of an EE 

program population), together with a written discussion 

of the EM&V approaches used, potential risks and biases, 

and related quality control measures that will be 

utilized. Sampling of populations is appropriate, 

provided that (a) the population estimates derived from 

sampling achieve industry-standard levels of precision 

and confidence (actual, not ex-ante values), and (b) 

applicable protocols and guidance documents are applied 

 

733 Rigor refers to the level of effort expended to minimize 

uncertainty from factors such as sampling error and bias. The 

higher the level of rigor, the more confident one is that the 

results of the EM&V activities are both accurate and precise. 
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and cited. 

 How double counting will be avoided through the use of 

tracking and accounting procedures to ensure that two or 

more programs do not separately claim savings from the 

same EE project or measure (for example, two EGUs 

claiming savings from the same lighting retrofit). Other 

types of double counting must likewise be considered and 

avoided. 

(4) Use of EE EM&V protocols. A separate aspect of industrystandard EM&V practice addressed in the rule proposal is the use 

of one or more EM&V protocols, guidelines, and guidance. These 

resources serve to document the EM&V approaches listed above and 

provide instruction on their application in the field. In public 

comments, the EPA heard overwhelmingly that such protocols, 

guidelines, and guidance documents are currently in wide use, 

and that this use should be continued and encouraged in the 

context of state plans. The agency agrees with this observation 

and therefore supports their application in the context of 

demand-side EE used to adjust an emission rate. The primary 

criteria are that EM&V plans must include a clear description 

and documentation of how the relevant protocols, guidelines, and 

guidance documents will be applied, as well as after-the-fact 

documentation in EM&V reports of how they were actually applied. 
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c. Eligible demand-side EE programs and projects. During the 

comment period, the EPA received many requests from commenters 

for explicit consideration of the broad range of demand-side EE 

programs and projects that are currently being implemented by 

states and other entities across the country. Specifically, 

these commenters expressed interest in counting the resulting 

quantified and verified MWh savings towards the achievement of 

CO2 emission rate goals. Consistent with these perspectives, the 

EPA position is that any demand-side EE program and project that 

results in MWh savings is potentially eligible, provided that it 

meets the criteria for eligibility described in section 

VIII.G.1., and that supporting EM&V is rigorous, complete and 

consistent with the criteria provided in the emission guidelines 

and the state plan. 

Common demand-side EE programs and project types include: 

 Publicly or rate-payer funded customer-funded demand-side 

management programs 

 Project-based EE evaluated site-by-site, for example 

those implemented by ESCOs at commercial buildings and 

industrial facilities 

 State and local government building energy code and 

compliance programs 

 State and local government incremental product energy 
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standards 

A related technology that is eligible to generate MWh that 

can be counted towards a rate-based goal is CHP (more 

information about the eligibility and EM&V criteria for CHP is 

provided in section VIII.G.1.). 

The EPA recognizes that the programs and policies listed 

above will evolve and change over the rule period, as new 

technologies emerge and efficiency improves. The agency also 

expects that new EE program types will emerge and expand 

throughout the rule period, and that MWh savings resulting from 

these programs can similarly be considered if quantified and 

verified according to EM&V criteria specified in industrystandard protocols and guidance documents, and if documentation 

provided in EM&V plans and reports is transparent, credible and 

robust. 

d. Demand-side EE program- and project-specific EM&V provisions. 

In addition to the generally-applicable EM&V criteria specified 

above, EM&V plans and report submittals must include any 

additional EM&V information needed to ensure that savings from 

the previously-listed programs and projects are quantifiable and 

verifiable. This requirement can be fulfilled by documenting in 

EM&V plans how industry-standard protocols, guidelines, and 

guidance documents that are relevant to such programs and 
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projects will be applied on a forward-looking basis, and also by 

confirming in ex-post EM&V reports that they were, in fact, 

applied. The protocols, guidelines, and guidance documents that 

identify these provisions may currently exist, or may be 

developed during the course of the rule period as programmatic 

strategies and EM&V evolves. 

e. EM&V criteria that apply to non-affected CHP. To calculate a 

CHP unit’s creditable MWh, the electrical output is prorated 

based on the “incremental CO2 emission rate” of the CHP unit 

relative to the applicable CO2 emission rate for affected EGUs in 

the state, according to the equation described in section 

VIII.C.1. The EM&V criteria described in this section apply only 

to the MWh-output terms of the equation, consistent with the 

definition of EM&V as applied in this rule. The full set of 

accounting criteria for CHP is provided in VIII.G.1. 

For determining the creditable MWh from CHP, the measured 

output must be derived either from (1) a revenue quality meter 

that meets the applicable ANSI C-12 standard or equivalent, 

which is the typical requirement for settlements with RTO and 

other control-area operators; or (2) for customer-sited CHP that 

is interconnected behind the customer meter, a revenue quality 

meter at the AC output of an inverter, where applicable, that is 

adjusted to reflect the energy delivered into either the 
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transmission or distribution grid at the generator bus bar. 

For small systems, defined as individual CHP units with 

nameplate capacities below 10 kW where metered data are 

unavailable, generation output may be determined using either 

self-reporting of generation values734 or generation-estimating 

software. In the latter case, calculations of system output must 

be based on the CHP unit’s capacity, estimated capacity factors, 

and an assessment of the local conditions that affect generation 

levels. All such input parameters and assumptions must be 

clearly described and documented. Regardless of whether selfreporting or generation-estimating software is used, CHP 

providers can report results without an intermediary provided 

that EM&V plans describe the rigorous quality control and fraud 

prevention measures that will be applied. 

 For small systems, generation output may be determined 

using either estimating software, algorithms, or self-reporting 

of generation values. In the latter case, EM&V plans must 

confirm that rigorous quality control and fraud prevention 

measures are in place. Small systems are defined as individual 

CHP units with nameplate capacities below 10 kW where metered 

 

734 Self-reporting means that the generator-owner can read its 

own meter and report MWh generated directly to a tracking 

system, without relying on an independent third party or other 

representative. 
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data are unavailable. For CHP systems that directly serve onsite end-use electricity loads, avoided T&D system losses can be 

assessed as is commonly practiced with demand-side EE. Such 

calculations must apply the criteria described in section 

VIII.G.4.(b)(3) above. 

f. EM&V criteria that apply to all RE. This section describes 

the EM&V criteria associated with quantifying electricity 

generation from eligible RE, and for documenting these criteria 

in EM&V plans and reports. Consistent with prevailing views 

expressed in public comments, the EPA’s criteria are based on 

the presumption that the quantification of RE generation can 

leverage the infrastructure and documentation associated with 

participation in registries of renewable energy certifications 

(RECs). These registries typically include well-established 

procedures for registry operations, safeguards, and 

documentation, all of which support compliance demonstration 

with state RPS policies. 

The primary metric for all RE is electricity generation, in 

units of MWh. Measured output must be derived either from (1) a 

revenue quality meter that meets the applicable ANSI C-12 

standard or equivalent, which is the typical requirement for 

settlements with RTO and other control-area operators; or (2) 

for customer-sited generators that are interconnected behind the 
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customer meter, a revenue quality meter at the AC output of an 

inverter, adjusted to reflect the energy delivered into either 

the transmission or distribution grid at the generator bus bar. 

For RE units that are managed by regional transmission 

operators or other control area operators, metered generation 

data should be electronically collected by the control area’s 

energy management system, verified through an energy accounting 

or settlements process, and reported by the control area 

operator to the REC registry at least monthly. 

For RE units that do not go through a control area 

settlements process, metered data should be read and transmitted 

to the REC registry by an independent third party on a monthly 

basis, but at a minimum annually. Such data must be verified for 

reasonableness by the state or the REC registry. 

For small systems, defined as individual RE units with 

nameplate capacities below 10 kW where metered data are 

unavailable, generation output may be determined using either 

self-reporting of generation values or generation-estimating 

software. In the latter case, calculations of system output must 

be based on the RE unit’s capacity, estimated capacity factors, 

and an assessment of the local conditions that affect generation 

levels. All such input parameters and assumptions must be 

clearly described and documented. In addition, each RE unit must 
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be uniquely identified and recorded in a registry to avoid 

double counting. Such data must be verified for reasonableness 

by the state or the REC registry. Regardless of whether selfreporting or generation-estimating software is used, RE 

providers can report the result to the tracking system without 

an intermediary provided that EM&V plans describe the rigorous 

quality control and fraud prevention measures that will be 

applied. 

An additional consideration is that RE generation may be 

aggregated from multiple generators into a single MWh value for 

the group, provided the following criteria are met: each RE unit 

is uniquely identified in a tracking system (to ensure that 

double counting is avoided), the nameplate capacity of each RE 

unit is less than 150 kW, the aggregated RE units collectively 

have nameplate generating capacities less than 1.0 MW, the RE 

units being aggregated utilize the same technology/fuel type, 

and the RE unit’s generation data are based on the same metering 

or the same generation estimating software or algorithms. 

An additional criterion that applies to distributed RE 

units that directly serve on-site end-use electricity loads is 

that avoided T&D system losses can be considered, as is commonly 

practiced with demand-side EE. Such calculations must apply the 

criteria specified for demand-side EE, as described in section 
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VIII.G.4.(b)(3) above. 

g. Additional considerations for EM&V of RE and EE included in 

state measures type plans. As discussed in the introduction to 

this section, states implementing state measures type plans may 

use quantified and verified MWh of EE savings and RE generation 

to adjust an emission rate through two pathways. First, if the 

state measures plan enables rate-based trading, the affected 

EGUs may use ERCs to adjust their reported rate as applicable 

under the rate-based emission standard approach. In such cases, 

a state includes EM&V criteria (consistent with those discussed 

above) in its state plan requirements governing ERC issuance, 

trading and retirement. Second, if the state measures plan 

incorporates RE and demand-side EE policies, programs and 

projects outside of an ERC trading program – e.g., through 

adoption of an EERS or a RPS – the state itself, rather than the 

project provider, applies the quantified and verified MWh to 

adjust the reported emission rate used to demonstrate compliance 

with the emission guidelines. 

In the case of a state measures plan relying on stand-alone 

RE and EE measures, a state must submit as part of its state 

plan a description of the RE and EE measures it intends to 

implement, as well as a discussion of how it intends to quantify 

the results of those measures consistent with the EMV criteria 
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described herein. A key component of this discussion is the 

mechanisms and approaches the state intends apply to ensure that 

MWh savings and generation are independently and credibly 

quantified and verified. Such mechanisms and approaches must be 

consistent with industry-standard practices and functionally 

equivalent to the provisions for independent verifiers for ERC 

trading in the context of emission standard plans, as described 

section VIII.G.3. An additional and related component of the 

state plan is a forecast of expected RE generation and annual 

incremental and cumulative EE savings. 

For any state measures plan that incorporates demand-side 

EE and RE outside of an ERC trading program, an additional 

criterion is that states must report annual incremental and 

cumulative EE savings and RE generation to the EPA every year.735

These data should be provided to the EPA in a summary format 

that documents total MWh savings and generation, and that is 

specified at the level of major policies, programs and projects. 

At state plan check-in intervals with the EPA (in 2025, 

2028 and 2030), states must provide the EPA with access to 

applicable program- and project-level EM&V reports used to 

compile total MWh savings and generation. EM&V reports must 

 

735 Per section VIII.D, states that choose a state measures plan 

must submit an annual report no later than July 1 following the 

end of each calendar year in the interim period. 
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document how EM&V criteria were applied to quantify results. 

It should be noted that, in the case of state measures 

plans that utilize a mass-based allowance trading program to 

meet their goal, EM&V plans and reports are not required. This 

is true even if the state is actively implementing RE and 

demand-side EE programs and projects. This is because the 

emission effects of RE and EE are accounted for in measured 

stack emissions. 

h. Skill certification standards. Several commenters pointed out 

that skill certification standards can help to assure quality 

and credibility of demand-side EE and RE projects. The EPA 

agrees that in conjunction with other EM&V measures discussed in 

this section, requiring that workers be certified by either a 

party aligned with the Department of Energy’s (DOE) Better 

Building Workforce Guidelines and validated by a third party 

accrediting body recognized by DOE, or by an apprenticeship 

program that is registered with the federal Department of Labor 

(DOL), Office of Apprenticeship or a state apprenticeship 

program approved by the DOL, or by another skill certification 

validated by a third party accrediting body can help to 

substantiate the authenticity of emission reductions due to 

demand-side EE and RE. The EPA encourages states to ask for a 

demonstration that the work is performed by a proficient 
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workforce. 

H. Additional Considerations for State Plans 

1. Consideration of a facility’s “remaining useful life” and 

“other factors” 

This section discusses the way in which the final emission 

guidelines address the CAA section 111(d)(1) provision requiring 

the Administrator, in promulgating 111(d) regulations, to 

“permit the State in applying a standard of performance to any 

particular source under a [111(d)] plan . . . to take into 

consideration, among other factors, the remaining useful life of 

the existing source to which such standard applies.” 

The final guidelines permit a state, in developing its 

state plan, to fully consider and take into account the 

remaining useful life of an affected EGU and other factors in 

establishing the requirements that apply to that EGU, as 

discussed further below. Therefore, consideration of facilityspecific factors and in particular, remaining useful life, does 

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 
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consider these factors in designing their plans. 

a. Statutory and regulatory backdrop. This section describes the 

statutory and existing regulatory background concerning 

facility-specific considerations in implementation of section 

111(d). 

Section 111(d)(1)(A) requires states to submit a plan that 

“establishes standards of performance” for existing sources. 

Under section 111(d)(1)(B), the plan must also “provide for 

implementation and enforcement of such standards of 

performance.” Finally, the last sentence of section 111(d)(1) 

provides: “Regulations of the Administrator under this paragraph 

shall permit the State in applying a standard of performance to 

any particular source under a plan submitted under this 

paragraph to take into consideration, among other factors, the 

remaining useful life of the existing source to which such 

standard applies.” 

The EPA’s 1975 implementing regulations736 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 

 

736 40 FR 53340 (Nov. 17, 1975). 
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appropriate where the state demonstrates with respect to a 

specific facility (or class of facilities): 

(1) Unreasonable cost of control resulting from plant 

age, location, or basic process design; 

(2) Physical impossibility of installing necessary 

control equipment; or 

(3) Other factors specific to the facility (or class 

of facilities) that make application of a less stringent 

standard or final compliance time significantly more 

reasonable. 

This provision was amended in 1995 (60 FR 65387, December 

19, 1995), and is now prefaced with the language “Unless 

otherwise specified in the applicable subpart on a case-bycase basis for particular designated facilities or classes 

of facilities.” 40 CFR 60.24(f). 

b. Our proposal regarding the implementing regulations. Our 

proposal stated that the reference to “[u]nreasonable cost 

of control resulting from plant age” in 60.24(f) 

“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 
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category and guidelines. We requested comment on our 

analysis of the existing implementing regulations and any 

implications for our regulatory text in respect to how 

these guidelines relate to those regulations. 

 Commenters noted, among other things, that the sentence 

concerning “remaining useful life” was added in the 1977 CAA 

Amendments and that therefore it could not be said that 

provisions from the 1975 implementing regulations “implement” 

the sentence. The EPA does not think as a general matter that it 

is necessarily impossible that a pre-statutory amendment rule 

could continue to serve as a reasonable implementation of a 

post-statutory amendment provision. However, we also think it is 

appropriate, as we suggested in the June 2014 proposal, to 

specify in the applicable subpart for these guidelines that the 

provisions in 60.24(f) should not apply to the class of 

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 
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which such standard applies.” 

c. How these emission guidelines permit states to consider 

remaining useful life and other facility-specific factors. The 

EPA notes that, in general, the implementing regulation 

provisions for remaining useful life and other facility-specific 

factors are relevant for emission guidelines in which the EPA 

specifies a presumptive standard of performance that must be 

fully and directly implemented by each individual existing 

source within a specified source category. Such guidelines are 

similar to a CAA section 111(b) standard in their form. For 

example, the EPA emission guidelines for sulfuric acid plants, 

phosphate fertilizer plants, primary aluminum plants, and Kraft 

pulp plants specify emission limits for sources.737 In the case of 

such emission guidelines, some individual sources, by virtue of 

their age or other unique circumstances, may warrant special 

accommodation. 

 

737 See “Phosphate Fertilizer Plants; Final Guideline Document 

Availability,” 42 Fed. Reg. 12022 (Mar. 1, 1977); “Standards of 

Performance for New Stationary Sources; Emission Guideline for 

Sulfuric Acid Mist,” 42 Fed. Reg. 55796 (Oct. 18, 1977); “Kraft 

Pulp Mills, Notice of Availability of Final Guideline Document,” 

44 Fed. Reg. 29828 (May 22, 1979); “Primary Aluminum Plants; 

Availability of Final Guideline Document,” 45 Fed. Reg. 26,294 

(Apr. 17, 1980); “Standards of Performance for New Stationary 

Sources and Guidelines for Control of Existing Sources: 

Municipal Solid Waste Landfills, Final Rule,” 61 Fed. Reg. 9905 

(Mar. 12, 1996). 

 
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In these final guidelines for state plans to limit CO2 from 

affected EGUs, however, the agency does not specify presumptive 

performance rates for individual EGUs. Instead, these guidelines 

provide collective performance rates for two classes of affected 

EGUs (steam generating units and stationary combustion 

turbines), and give states the alternative of developing plans 

to achieve a state emission goal for the collective group of all 

affected EGUs in a state. Providing states with the ability to 

consider facility-specific factors such as remaining useful life 

in designing their state plans is one of the fundamental reasons 

that the EPA designed the final rule in this way. In addition, 

the significant revisions since proposal to address 

achievability concerns (e.g., moving the start date from 2020 to 

2022, and other changes in interim and final state goals 

summarized in the next section) will help to ensure that states 

in practice can consider remaining useful life and other 

facility-specific factors in setting EGU requirements. Of 

course, EGUs vary considerably in age, so remaining useful life 

is potentially relevant to regulation of some units and not 

others. 

The guidelines capitalize on the inherent flexibility 

offered by aggregate EGU performance rates and by the state 

goals approach, allowing states flexibility on the form of the 
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EGU standards that they include in CAA section 111(d) plans. A 

state could select a form of standards (e.g., marketable credits 

or permits, retirement of certain older facilities after their 

useful life, etc.) that avoids or diminishes concerns about 

facility-specific factors such as remaining useful life. Even if 

a state adopted the CO2 emission performance rates for fossil 

fuel-fired electric utility steam generating units and 

stationary combustion turbines, though, the state could take 

remaining useful life into consideration by allowing affected 

EGUs to comply using ERCs. In effect, under a trading program 

with repeating compliance periods, a facility with a short 

remaining useful life has a total outlay that is proportionately 

smaller than a facility with a long remaining useful life, 

simply because the first facility would need to comply for fewer 

compliance periods and would need proportionately fewer ERCs 

than the second facility. Buying ERCs could avoid excessive upfront capital expenditures that might be unreasonable for a 

facility with a short remaining useful life, and would reduce 

the potential for stranded assets. 

In addition to providing states with flexibility on the 

form of the standards of performance in their plans, the 

guidelines leave to each state the design of the specific 

requirements that fall on each affected EGU in applying those 
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standards. To the extent that an emission standard that a state 

may wish to adopt for affected EGUs raises facility-specific 

issues, the state may make adjustments to a particular 

facility’s requirements on facility-specific grounds, so long as 

any such adjustments are reflected (along with any necessary 

compensating emission reductions to meet the state goal) in the 

state’s CAA section 111(d) plan submission. 

Finally, we note that these guidelines permit states to use 

a rate or mass CO2 emission goal, and that each of these pathways 

allow states multiple design choices. Under either pathway 

states can take into consideration remaining useful life and 

seek to avoid stranded assets. 

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 
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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 

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 
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implementation levels for each building block in order to 

establish overall state goals that are achievable while allowing 

states to take advantage of the flexibility to pursue some 

building blocks more aggressively, and others less aggressively, 

than is reflected in the goal computations, according to each 

state’s needs and preferences. The guidelines provide further 

flexibility by allowing state plans to use emission reduction 

methods not reflected in the BSER. A description of multiple 

emission reduction methods is provided in section VIII.G. 

f. Response to key comments on remaining useful life. In 

response to the proposed rule, some commenters said that 

stringent and binding state goals do not, as a practical matter, 

provide states with the flexibility on EGU requirements that the 

EPA claimed at proposal, and take away states’ ability to 

consider remaining useful life for individual units. Some said 

the EPA’s presumption at proposal that the issue of remaining 

useful life would arise infrequently is inaccurate because the 

EPA focused on capital investments late in a plant’s useful life 

and did not consider stranded assets from retirement of coalfired generation before the end of its useful life, or from 

retirement of EGUs that recently installed pollution controls. 

Commenters provided multiple examples of individual power 

plants, including relatively new plants, which they asserted 
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would be forced to shut down under the proposal. One commenter 

said that the EPA’s Integrated Planning Model outputs for the 

proposal demonstrate that integrated operation of the four 

building blocks would result in retirement of sources before the 

end of their useful life. A number of commenters raised concerns 

that the proposed interim goal would cause plant retirements and 

stranded assets. A number of commenters also asserted that the 

proposal would cause retirement of EGUs that recently invested 

in pollution controls to comply with requirements such as MATS 

or Best Available Retrofit Technology requirements of the 

Regional Haze program. 

The EPA shares the goal of avoiding stranded assets. 

Although nothing in section 111(d) explicitly bars a guideline 

that results in some facilities becoming uneconomic before the 

end of their useful lives, the EPA nonetheless has striven to 

design the guidelines so as to give states flexibility to 

develop plans that allow power companies to recover their 

investments in generation units. 

In addition, the EPA is addressing the key comments above 

by making changes to state goals and its goal-setting 

methodology. These changes include: 

 Starting the interim goal period in 2022 rather than 

2020, allowing more gradual progress toward the final 
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goal 

 Revising the goal-setting formula and the state goals 

themselves 

 Updating analyses of achievable levels of improvement 

through the building blocks that together represent the 

BSER, while keeping them at reasonable, rather than 

maximum, levels 

 Providing an explicit phase-in schedule for meeting the 

revised interim goals, while also allowing a state the 

option of choosing its own emission improvement 

trajectory 

The final guidelines also contain changes to avoid certain 

inconsistencies between the goal-setting methodology and 

accounting of reductions under state plans (e.g., interstate 

effects of RE programs) that could have made state goals less 

achievable for some states. 

Together, these changes help to ensure that the state goals 

established in the final guidelines are achievable considering 

cost, and that states can, as a practical matter, consider the 

toolbox of available emission reduction methods that the final 

guidelines allow and choose the best way to achieve their state 

goals. 

Several commenters said that that the statute does not 
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authorize the EPA to require other facilities to achieve greater 

reductions to compensate for a facility that warrants relief 

based on remaining useful life. One said that consideration of 

remaining useful life and other relevant factors is a one-way 

ratchet that provides relief to sources that cannot achieve the 

BSER, and that the EPA turns that approach on its head by 

prohibiting a state from providing such relief to a specific 

facility unless it can identify another facility to “punish” by 

requiring additional emissions reductions to offset that relief. 

The EPA disagrees with these comments, many of which appear 

to be predicated on an approach not taken in this rule: 

requiring states to set presumptive standards for individual 

affected EGUs. The EPA is not establishing BSER for individual 

facilities, and then requiring better-than-BSER from some 

facilities to make up to worse-than-BSER performance that a 

state authorizes for other facilities because of a short 

remaining useful life. Rather, as previously noted, the 

guidelines set aggregate performance rates and state goals that 

represent the aggregate emission level of affected EGUs in each 

state based on estimates of the aggregate impact of applying the 

BSER. In estimating the amount of improvement achievable through 

each building block e.g., improvement in heat rate or amount of 

generation shift to lower-emitting EGUs), the EPA relies on 
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estimating the average achievable level rather than attempting 

to estimate the level achievable by each and every affected EGU. 

Thus, the fact that an individual facility may be unable, for 

example, to achieve the average level of heat rate improvement 

assumed in goal-setting is consistent with the EPA’s analysis, 

and does not undermine the EPA’s determination of state goals. 

An additional reason that the EPA believes that 

consideration of remaining useful life and other facilityspecific factors does not warrant adjustments to state goals is 

that the design of the guidelines does not mandate that states 

impose requirements that would call for substantial capital 

investments at affected EGUs late in their useful life. Of the 

building blocks considered by the EPA in developing state goals, 

only the first block, heat rate improvements, involves capital 

investments at the affected EGUs. The other building blocks – 

generation shifts among affected EGUs, and addition of new RE 

generating capacity – do not generally involve capital 

investments by the owner/operator at an affected EGU. 

In the case of heat rate improvements at affected EGUs, 

states can choose whether to require a greater or lesser degree 

of heat rate improvement than the percentage improvement assumed 

in the EPA’s BSER determination, either because of the remaining 

useful life of one or more EGUs, other source-specific factors 
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that the state deemed appropriate to consider, or any other 

relevant reasons. The agency also notes that any capital 

expenditures would be much smaller than capital expenditures 

required for example, for purchase and installation of scrubbers 

to remove sulfur dioxide; a fleet-wide average cost for heat 

rate improvements based primarily on best practices at coalfired generating units would not likely exceed $100/kW, compared 

with a typical SO2 wet scrubber cost of $500/kw (costs vary with 

unit size).738 In addition, the proposed guidelines 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 proposed 

approach - establishing state goals and providing states with 

flexibility in plan design – states have flexibility to make 

exactly the kind of judgments necessary to avoid requiring 

capital investments that would result in stranded assets. 

Remaining useful life and other factors, because of their 

facility-specific nature, are potentially relevant as states 

determine requirements that are directly applicable to affected 

 

738 Heat rate improvement methods and related capital costs are 

discussed in the GHG Abatement Measures TSD; SO2 scrubber capital 

costs are from the documentation for the EPA’s IPM Base Case 

v5.13, Chapter 5, Table 5-3, available at 

http://www.epa.gov/airmarkets/documents/ipm/Chapter_5.pdf. 
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EGUs. If relief is due a particular facility, the state has an 

available toolbox of emission reduction methods that it can use 

to develop a section 111(d) plan that will achieve the CO2

emission performance rates or state CO2 emission goals on time. 

The EPA therefore concludes that the remaining useful life of 

affected EGUs, and the other facility-specific factors 

identified in the existing implementing regulations, should not 

be regarded as a basis for adjusting the CO2 emission performance 

rates or a state CO2 emission goal, and should not relieve a 

state of its obligation to develop and submit an approvable plan 

that achieves that goal on time. 

g. Legal issues regarding remaining useful life. Section 

111(d)(1) requires the EPA in promulgating section 111(d) 

regulations to “permit the State in applying a standard of 

performance to any particular source under a plan submitted 

under this paragraph to take into consideration, among other 

factors, the remaining useful life of the existing source to 

which such standard applies.” Here, we discuss the legal basis 

for determining that the emission guidelines are consistent with 

this statutory requirement. 

First, the phrase “remaining useful life” also appears in 

the visibility provisions of section 169A. There, in determining 

best available retrofit technology (BART), the state (or the 
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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. 

 However, section 111(d)(1) is different than section 

169A(g)(2) and need not be interpreted in the same way. The 

requirement in section 169A(g)(2) is a mandatory duty to 

consider remaining useful life in determining BART. Section 

111(d)(1), in contrast, merely requires that EPA emission 

guidelines permit states to take into account remaining useful 

life (among other factors), and section 111(d)(1) does not 

specify how the EPA must permit that. Furthermore, section 

111(d)(1) does not suggest that states must be given carte 

blanche to consider remaining useful life in any way that can be 
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imagined. Thus, there is a gap in the statute (just as there is 

in section 169A(g)(2)) for the EPA to fill by determining how 

states might consider remaining useful life. As detailed in 

section VIII.B.6, these guidelines permit states to take into 

account remaining useful life in a number of reasonable ways and 

thus the guidelines satisfy the statutory obligation. 

 Even if the EPA were to consider the provision in section 

111(d)(1) in the same light as section 169A(g)(2), we would note 

(as discussed in detail in VIII.B.6 above) that (for example) a 

trading program under these section 111(d) guidelines only 

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 
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emission standard for that EGU. Then, the state would be 

compelled to increase the stringency of emission standards at 

other affected EGUs in order to achieve the state performance 

goal. According to these commenters, section 111(d) does not 

allow this outcome. 

 First, the commenters are mistaken in their premise. As 

discussed in section VIII.B.6 and in the example immediately 

above, states can impose the exact same emission standards on 

two affected EGUs and still take into account remaining useful 

life through the availability of trading. In other words, states 

need not relax an emission standard here and strengthen an 

emission standard there in order to take into account remaining 

useful life. Thus, these guidelines permit states to take into 

account remaining useful life without any of the effects 

commenters are concerned about. 

 Second, even if states decide to relax emission standards 

at one EGU, on the basis of remaining useful life or any other 

factor, nothing in the last sentence of section 111(d)(1) 

prohibits these guidelines from requiring the state plan to 

still meet the state performance goal. In fact, that sentence is 

completely silent on the issue. Thus, there is a gap in the 

statute to fill not only with respect to the ways in which 

remaining useful life can be considered, but the concomitant 
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effects if a state chooses to consider remaining useful life in 

a particular way. In this case the concomitant effect of a state 

relaxing one emission standard may be that the state must make 

up for it elsewhere in order to meet the goal, but nothing in 

section 111(d)(1), including the statutory requirement to permit 

consideration of remaining useful life, prohibits that outcome. 

2. Electric reliability

The final rule features overall flexibility, a long 

planning and implementation horizon, and the widest possible 

range of options for states and affected EGUs to achieve the CO2

emissions goal. This design reflects, among other things, the 

EPA’s commitment to ensuring that the final rule does not 

interfere with the reliability of the nation’s electricity 

supply. Comments from state, regional and federal reliability 

entities, power companies and others, as well as consultation 

with the Federal Energy Regulatory Commission (FERC), which 

conducted one national and three regional technical conferences 

on the proposed rule in which the EPA participated, helped 

inform a number of changes made in this final rule to address 

reliability. 

 As discussed throughout the preamble and TSDs, the 

electricity sector is undergoing a period of intense change. 

While the change in the resource mix has accelerated in recent 
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years, wind, solar, other RE, and EE resources have been 

reliably participating in the electric sector for a number of 

years. Many of the potential changes to the electric system that 

the final rule may encourage, such as shifts to cleaner sources 

of power and efforts to reduce electricity demand, are already 

well underway in the electric industry. To the extent that the 

final rule accelerates these changes, there are multiple 

features in the electricity system that ensure that electric 

system reliability will be maintained. Electric system 

reliability is continually being considered and planned for. For 

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 
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local or regional reliability issue. These include transmission 

system upgrades, installation of new generating capacity, 

calling on demand response, and other demand-side actions. 

Additionally, planning authorities and system operators 

constantly consider, plan for, and monitor the reliability of 

the electricity system with both a long-term and short-term 

perspective. Over the last century, the electric industry’s 

efforts regarding electric system reliability have become 

multidimensional, comprehensive, and sophisticated. Under this 

approach, planning authorities plan the system to assure the 

availability of sufficient generation, transmission, and 

distribution capacity to meet system needs in a way that 

minimizes the likelihood of equipment failure.739 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.740 Mandatory reliability standards apply to 

how the bulk electric system is planned and operated. For 

 

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

Systems: An Overview of the Technology, the Marketplace, and 

Government Regulations, IEEE Press, at 160 (2010).

740 Id. 
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example, transmission operators and balancing authorities have 

to develop, maintain, and implement a set of plans to mitigate 

operating emergencies.741 

The EPA’s approach in this final rule is consistent with 

our commitment to ensuring that the final rule does not 

interfere with the reliability of the nation’s electricity 

supply. Starting with the proposal, many aspects of the final 

rule’s design were intended to support system reliability, 

especially the long compliance period and the basic design that 

allows states flexibility to include a large variety of 

approaches and measures to achieve the environmental goals in a 

way that is tailored to each state’s energy resources and 

policies. Indeed, as with numerous prior CAA regulations 

affecting the electric power sector, environmental requirements 

for this industry are accommodated within the existing extensive 

framework established by federal and state law to ensure that 

electricity production and delivery are balanced on an ongoing 

basis and planned sufficiently to ensure reliability and 

affordability into the future. Changes that the EPA is making in 

this final rule respond directly to the comments and the 

suggestions we received on these issues and provide further 

 

741 NERC Reliability Standard EOP-001-2.1b — Emergency Operations 

Planning, available at 

http://www.nerc.net/standardsreports/standardssummary.aspx. 
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assurance that implementation of the final rule will not create 

reliability concerns. 

First, the final rule allows significant flexibility in how 

the applicable CO2 emission performance rates or the statewide 

CO2 goals are met. Given the differing characteristics of the 

electric grid within each state and region, there are many paths 

to meeting the final rule’s requirements that can be taken while 

continuing to maintain a reliable electricity supply. As further 

described elsewhere in Section VIII, states can develop plans to 

meet the CO2 emission performance rates or state CO2 emission 

goals by choosing from a variety of state plan types and 

approaches that afford states and affected EGUs appropriate 

flexibility. EE and other non-BSER approaches can strengthen a 

state’s ability to establish a plan to meet the CO2 emission 

performance rates or state CO2 emission goals by providing a 

considerable amount of headroom above the levels of the rates 

and goals. EE especially, because it reduces load, can provide 

assurance that reliability can and will be maintained. 

Second, the final rule provides sufficient time to ensure 

system reliability. The final rule retains the 2030 date for the 

final period, which commenters largely supported as reasonable 

and not a concern for reliability, and addresses one of the key 

issues that commenters pointed to as a reliability-related 
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concern by both moving the start of the interim period from 2020 

to 2022 and adjusting the interim goals to provide a less 

dramatic initial reduction requirement and a more gradual glide 

path to the final 2030 goals. As a result of these changes, the 

states themselves will have a meaningful opportunity – which 

many commenters suggested the timing and stringency of the 

proposal failed to create despite our intent to do so – to 

determine the timing, cadence and sequence of actions needed for 

states and sources to meet final rule requirements while 

accommodating the ongoing activity needed to ensure system 

reliability. The final rule provides more than six years before 

reductions are required and an eight-year period from 2022 to 

2029 to meet interim goals. 

Third, we are including in the final rule a requirement 

that each state demonstrate in its state plan submittal that it 

has considered reliability issues in developing its plan. This 

was suggested by a number of commenters, and we agree it is an 

essential element. 

Fourth, in response to a variety of comments, we are 

providing a reliability safety mechanism that provides a path 

for a state to come to the EPA during an immediate unforeseen, 

emergency situation that threatens reliability to inform the EPA 

that an affected EGU or EGUs may need to temporarily deviate 
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from specific state plan requirements to respond to this kind of 

reliability concern. 

Finally, the final rule provides a mechanism for a state to 

seek a revision to its plan in order to address changes in 

circumstances that could have reliability impacts if not 

accommodated in the plan. The long compliance timeframe, with 

several interim steps, naturally provides opportunities for 

states, working with their utilities and reliability entities, 

to assess how implementation is proceeding, identify unforeseen 

changes that may warrant plan revisions, and work with the EPA 

to make necessary revisions. 

We provide more details about these various elements of the 

final rule, as well as other features of the rule that support 

system reliability, below. 

a. Summary of key comments. The EPA received a number of 

comments regarding the proposed rule and electric reliability. 

Many commenters provided specific, useful ideas regarding 

changes that could be made to the proposal to specifically 

address their reliability concerns. For example, many commenters 

state that allowing additional time to comply could help in 

meeting the final rule requirements while addressing their 

reliability concerns. Some commenters suggest that additional 

time would allow them to evaluate potential reliability impacts 
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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 

detail with many suggestions for how such a reliability 

mechanism could be designed. The EPA appreciates these and all 

the comments we received regarding the interaction of the 

proposal and electric reliability. We carefully considered all 

comments and incorporated many of the suggested changes in this 

final rule. 

b. Final rule flexibility. In issuing this final rule, the EPA 

considered public comments on the potential interaction between 

the proposal and electric reliability. While we have made every 

effort to develop guidelines that would steer clear of potential 

reliability disruptions, a number of commenters argued that the 
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possibility of an unanticipated reliability event cannot be 

entirely eliminated. Of course, even in the absence of these 

guidelines, the electric system will not completely avoid 

reliability issues. The EPA designed the final rule to ensure to 

the greatest extent possible that actions taken by states and 

affected EGUs to comply with the final rule do not increase 

potential reliability issues or complicate their resolution. In 

fact, to the extent that meeting final rule requirements results 

in the reduction of demand, upgrades in transmission efficiency 

and infrastructure, and investment in new, more efficient 

technologies, the outcome could be that the system is more 

robust and faces fewer risks to electric reliability. 

However many commenters expressed concern that 

notwithstanding these flexibilities, the proposed plan 

development schedule may not leave sufficient time to conduct 

reliability planning between the development of state plans and 

the proposed start of the interim period in 2020. To address 

these concerns and to support a more effective reliability 

planning process, the EPA is moving the start of the interim 

period from 2020 to 2022. The final rule also provides the 

states with up to three years to adopt and submit their final 

state plans. This timing gives system operators the opportunity 

to do what they have already been doing; looking ahead to 
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forecast potential contingencies that pose reliability risks and 

identifying those actions needed to mitigate those risks. The 

final rule allows states to develop a pathway over the interim 

period that reflects their own circumstances, such as reflecting 

planned additions and changes in generation mix. Because 

achievement of the emission rates or goals can be demonstrated 

over several years, state plans can accommodate situations where 

for example, it may take time to develop new generation, 

pipelines, or transmission while still providing many options 

for meeting the final rule requirements and planning for the 

reliability of the system. 

c. Considering reliability during state plan development 

process. Under CAA section 111(d)(1)(B), state plans must 

provide for the implementation and enforcement of standards of 

performance for affected EGUs. The EPA is requiring that each 

state demonstrate as part of its state plan submission that it 

has considered reliability issues while developing its plan in 

order to ensure that standards of performance can be implemented 

and enforced. If system reliability is threatened, the ability 

of affected EGUs to meet the requirements of this final rule 

could be compromised if they are required to operate beyond the 

emission standards set in state plans in order to maintain the 

reliability of the electric grid. The requirement that states 
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consider reliability as part of the development of state plans 

is designed to ensure that state plans are flexible enough to 

avoid this kind of potential conflict between maintaining 

reliability and implementing emission standards for affected 

EGUs. 

A number of commenters, notably ISOs and RTOs, pointed out 

that planning and anticipation of change are among the essential 

ingredients of ensuring the ongoing reliability of the 

electricity system. To that end, they recommended that as states 

are developing state plans, their activity include the 

consideration of the reliability needs of the region in which 

affected EGUs operate and of the potential impact of actions to 

be taken in compliance with state plans. Therefore, we are 

requiring that each state demonstrate in its final state plan 

submittal that it has considered reliability issues in 

developing its plan. One particularly effective way in which a 

state can make this demonstration is by consulting with the 

relevant ISOs/RTOs or other planning authorities as they develop 

their plans and documenting this consultation process in their 

state plan submissions. If a state chooses to consider 

reliability through consultation with the ISO/RTO or other 

planning authority, the state should request that the planning 

authority review the state plan at least once during the plan 
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development stage and provide its assessment of any reliability 

implications of the plan. While following the recommendations of 

the planning authority would not be mandatory, the state should 

document its consultation process, any response and 

recommendations from the planning authority, and the state’s 

response to those recommendations in its state plan submittal to 

the EPA. This consultation is designed to inform how the state 

might adjust its plan for meeting the CO2 reduction goal required 

under this guideline; the consultation is not a basis for 

relaxing that goal. While we consider this process to be an 

effective way for a state to demonstrate that it considered 

reliability in developing its state plan, a state may provide 

other comparable support for a demonstration that it has 

considered reliability during the state plan development 

process.742 The EPA believes that this requirement to demonstrate 

consideration of reliability will provide an essential 

reliability evaluation in the state plan development process. It 

should further help states avoid any conflicts between state 

plans and the maintenance of reliability during implementation 

of the state plan and associated emission standards. 

 

742 While the EPA is requiring that the states demonstrate that 

they have considered reliability in developing their plans, 

state plan submissions will not be evaluated substantively 

regarding reliability impacts. 
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d. State plan modifications. If, during the implementation of a 

state plan, a reliability issue cannot be addressed within the 

range of actions or mechanisms encompassed in an approved state 

plan, the state can submit a plan revision to the EPA to amend 

the timeframe over which reductions must be made in its plan. In 

such a circumstance, the state plan may need to be adjusted to 

enable affected EGUs to continue to meet final rule requirements 

without causing an otherwise unmanageable reliability threat. 

Whether or not these circumstances occur will depend in part 

upon how each state designs its state plan. States that design 

plans with a good deal of flexibility, such as market-based 

plans or multi-state plans, are less likely to face a potential 

conflict between state plan requirements and the maintenance of 

reliability. States that participate in multi-state programs 

will be better able to weather unexpected risks to reliability. 

Events not anticipated at the time of the final plan 

submittal - such as the retirement of a large low or zeroemitting unit - may trigger the request for state plan 

revisions. It may also be the case that facility-specific 

emissions standards in a state plan are proving to be too 

inflexible to allow the plan to accommodate market or other 

changes in the power sector. In such instances, there should be 

a lead time between the announced retirement of the unit and the 
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need to amend the state plan. Therefore, the state should be 

able to utilize the revisions process that the EPA provides. 

The EPA will review a plan revision per the requirements of 

40 CFR part 60. If the state’s request for a state plan revision 

must be addressed promptly to assure a reliable supply of 

electricity, the state must document the risks to reliability 

that would be addressed by the plan revision by providing the 

EPA with a separate analysis of the reliability risk from the 

ISO/RTO or other planning authority. This analysis should be 

accompanied by a statement from the ISO/RTO or other 

planning/reliability authority that there are no practicable 

alternative resolutions to the reliability risk. In this case, 

the EPA will conduct an expedited review of the state plan 

revision. 

e. Reliability safety valve. Many commenters expressed concerns 

that a serious, unforeseen event could occur during the final 

rule implementation period that would require a quick response 

by system operators and affected EGUs in order to maintain 

system reliability. It is highly unlikely that there would be a 

conflict between activities undertaken under an approved state 

plan and the maintenance of electric reliability, except in the 

case of a state plan that puts relatively inflexible 

requirements on specific plants. While some have pointed out 
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severe weather or other short-term events as potentially 

conflicting with state plans, we note that most of those events 

are of short duration and would not require major adjustments to 

emission standards on affected EGUs or state plans. For example, 

during an event like the extreme cold experienced in periods of 

the winter of 2013-2014, affected EGUs may need to briefly run 

at a higher level to accommodate increased demand and/or shortterm unavailability of other generators. However, because 

compliance can be demonstrated over 2-3 years, such a short-term 

event would not cause affected EGUs to be out of compliance with 

their applicable requirements. States can ensure that this is 

true by drafting plans that allow adequate compliance 

flexibility to accommodate such short-term events. 

We recognize, however, that there are potential system 

emergencies that cannot be anticipated that could cause a severe 

stress on the electricity system for a length of time such that 

the multi-year requirements in a state plan may not be 

achievable by certain affected EGUs without posing an otherwise 

unmanageable risk to reliability. There could be extremely 

serious events, outside the control of affected EGUs, that occur 

that require an affected EGU, or EGUs, to temporarily deviate 

from specific state plan requirements to respond to this kind of 

reliability concern. For example, 1) a catastrophic event such 
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as a geomagnetic disturbance caused by solar flares damages 

critical or vulnerable equipment necessary for reliable grid 

operation and a higher emitting resource needs to operate at 

increased levels until an alternative solution can be found; or 

2) a major storm floods and causes severe damage to a large NGCC 

plant in a city with limited access to transmission, 

necessitating that another much higher emitting plant is needed 

to operate until the NGCC plant is repaired; or 3) a serious act 

of sabotage damages an important substation and it will take 

time to work around the problem, and in the meantime a high 

emitting plant will need to run until transmission access is 

restored; or 4) a large nuclear unit must cease generating due 

to a substantial public safety issue and therefore causes other 

affected EGUs to run at higher levels in the short-term until a 

longer-term solution can be found. This is not an all-inclusive 

list, but it is illustrative of the kind of unforeseeable, 

emergency situation, caused by an extraordinary, unanticipated, 

potentially catastrophic event that, in the case of a state plan 

that imposes inflexible, obligations on individual EGUs 

(especially with short averaging times), may trigger the need 

for immediate, short-term relief from those facility-specific 

requirements. In such an instance, the final rule provides a 

process to ensure that system reliability will not be 
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compromised. 

Under such a circumstance, for states using the emissions 

standards plan type, the state must notify the EPA that it is 

necessary to modify the emission standards for an affected EGU 

or EGUs so that for a maximum of 90 days, the EGU or EGUs may 

operate at an emission standard that is above the emission 

standard specified in the relevant state plan but that the CO2

emission performance rates or the state CO2 emission goal will 

still be met. The EPA will consider this reliability safety 

valve to be an approved short–term modification to the state 

plan without needing to go through the full state plan revision 

process if the state provides proper notification to the EPA. 

The notification to the EPA must be in writing and must include 

a full description of the reliability concern and why the 

affected EGU (or EGUs) needs to operate under modified emission 

standards from those originally imposed on it by the state plan. 

The state must also describe in its notification to the EPA how 

it is coordinating or will coordinate, with relevant planning 

authorities to alleviate the problem in an expedited manner. The 

state should also include a written concurrence from the 

relevant planning authority supporting the temporary 

modification request or an explanation of why this kind of 

concurrence cannot be provided. Additionally, if the relevant 
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planning authority has conducted a system-wide or other analysis 

of the reliability concern, the state should include that 

information in its request. 

It is important to note that in such an instance requiring 

a short-term modification to the state plan, the state and 

affected EGUS must continue monitoring and reporting their 

emissions and generation pursuant to requirements in this final 

rule and under the state plan. Additionally, a short-term 

modification to the state plan is specific to the emissions 

standards for the affected EGU(s) needing to operate in a way 

that ensures system reliability, but such a modification may not 

alter or abrogate the overall obligations under approved state 

plans for the requisite state goal or performance rates to be 

met by affected EGUs. 

At the end of this period of 90 days or less, the state 

must notify the EPA as to whether the reliability concern has 

been addressed and that it is requiring the affected EGU, or 

EGUs, to meet the original emissions standards in the state plan 

approved prior to the short-term modification going forward. It 

must also notify the EPA as to how the CO2 emission performance 

rates or state CO2 emission goals will be met going forward and 

enumerate how it will make up for any emission reductions that 

were lost during the safety valve period. If there still is a 
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serious, ongoing reliability issue, the state must provide to 

the EPA a notice that it will be submitting a state plan 

revision. At the end of this period of 90 days or less, the 

emission standards originally approved under the state plan must 

be back in effect for the affected EGUs. 

The EPA intends for this reliability safety valve to be 

used only in exceptional cases and only once by a state. As 

discussed earlier, we are providing states with the flexibility 

to design a program that is appropriate for its electricity 

needs. This flexibility means that a conflict between the 

requirements of the state plan and maintenance of reliability 

should be extremely rare. If, however, the state finds that 

problems remain after imposition of the reliability safety 

valve, the state must submit a revision to its state plan. 

3. Consideration of effects to employment and economic 

development 

Labor markets respond in complex ways to state policies in 

a way that depends a wide range of factors (e.g., available 

local labor supply, broader labor market trends). Employment 

effects in a state will depend upon the particular steps that 

each state takes in their plan, as well as broader trends at the 

regional and national level. For most state plans, the precise 

effects will often be very hard to quantify because they will 
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depend on choices made by utilities and others as the plans are 

implemented. The EPA’s illustrative analysis highlights the 

likelihood for some additional job loss in sectors related to 

coal that are attributable to implementation of this rule. At 

the same time, the EPA’s illustrative analysis highlights that 

there will be new jobs in the utility power sector associated 

with both improving the efficiency of fossil fuel-fired power 

plants and construction of new natural gas-fired and renewable 

power production, and new jobs in the RE and demand-side EE 

sectors. Consideration of these effects in the context of the 

particulars of the state plan can help states craft plans that, 

to the extent possible, meet multiple environmental and economic 

goals. 

The Partnership for Opportunity and Workforce and Economic 

Revitalization (POWER) Initiative is a new interagency effort 

led by the Economic Development Administration in the Department 

of Commerce that specially targets economic development 

assistance to communities affected by changes in the coal 

industry and the utility power sector and may be of assistance 

to communities that experience job losses.743 In addition, the 

Department of Commerce, Department of Labor (DOL), Small 

Business Administration, and the Appalachian Regional Commission 

 

743 http://www.eda.gov/power/. 
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have together created an initiative to issue grants to 

partnerships of regionally-driven economic development and 

workforce development organizations in impacted coal 

communities.744 

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. The EPA agrees and encourages states to ask for a 

demonstration that the work is performed by a proficient 

workforce. A good way to ensure such a workforce is to require 

that workers have been certified by: 1) an 

apprenticeship program that is registered with the U.S. DOL, 

Office of Apprenticeship or a state apprenticeship program 

approved by the DOL; 2) a skill certification aligned with the 

U.S. DOE Better Building Workforce Guidelines and validated by a 

third party accrediting body recognized by DOE; or 3) other 

skill certification validated by a third party accrediting 

body. 

5. Tenth Amendment legal considerations 

 

744 https://www.whitehouse.gov/the-press-office/2015/03/27/factsheet-partnerships-opportunity-and-workforce-and-economicrevitaliz. 
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Some commenters have raised concerns that the emission 

guidelines and requirements for 111(d) state plans violate 

principles of federalism embodied in the U.S. Constitution, 

particularly the Tenth Amendment. These commenters claim that 

states will be unconstitutionally “coerced” or “commandeered” 

into taking certain actions in order to avoid the prospect of 

either a federal 111(d) plan applying to sources in the state, 

or of losing federal funds. 

 We disagree on both fronts. First, the prospect of a 

federal plan applying to sources in a state does not “coerce” or 

“commandeer” that state into submitting its own satisfactory 

plan. Far from violating principles of federalism, this rule 

provides states with the initial opportunity to submit a 

satisfactory state plan, and provides states flexibility in 

developing that plan. If a state declines to take advantage of 

that opportunity, affected EGUs in that state will instead be 

subject to a federal plan that satisfies statutory 

requirements.745 This approach is consistent with ordinary 

 

745 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 
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cooperative federalism regimes that federal courts have 

routinely upheld against Tenth Amendment challenges.746 

 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 

the implementing regulations making explicit that the EPA will 

not withhold federal funds from a state on account of that 

state’s failure to submit or implement an approvable 111(d) 

state plan. 

Some commenters pointed to section 110(m) as a possible 

source of the EPA’s sanction authority.747 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 

 

federal plan, the prospect of any such plan would not commandeer 

states or coerce them into submitting their own state plans. 

746 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”). 

747 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 context of nonattainment SIPs. See 42 U.S.C. § 7509(a). 
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exercising” this discretionary authority, and the only EPA 

regulations implementing section 110(m) apply to SIPs submitted 

under section 110.748

The EPA never intended to even imply that we would 

contemplate using this authority to encourage state 

participation in this rule under section 111. To the contrary, 

we believe that imposition of a federal plan rather than 

sanctions is the appropriate path in the context of this 

program. Accordingly, regardless of whether the EPA could 

theoretically apply discretionary sanctions against states in 

the section 111(d) context, the rule today forbids the agency 

from exercising any such authority. We have included in this 

rule a provision that prohibits the agency from imposing 

sanctions in the event that a state fails to submit or implement 

a satisfactory plan under this rule. As states consider whether 

to take advantage of the opportunity to develop state plans, 

they can be assured that the EPA will not withdraw federal 

funding should they decline to participate. 

I. Resources for States to Consider in Developing Plans

 As part of the stakeholder outreach and comment processes, 

the EPA asked states what the agency could do to facilitate 

state plan development and implementation. In addition, after 

 

748 40 CFR 52.30 (defining “plan or plan item”). 
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the comment period closed, the EPA continued to consult with 

state organizations including the Association of Air Pollution 

Control Agencies (AAPCA), Environmental Council of the States 

(ECOS), National Association of Clean Air Agencies (NACAA), 

National Association of Regulatory Utility Commissioners 

(NARUC), National Association of State Energy Officials (NASEO) 

and the National Governors Association (NGA). 

Some states indicated that they wanted the EPA to create 

resources to assist with state plan development, especially 

resources related to accounting for RE and demand-side EE in 

state plans. They requested clear methodologies for estimating 

emission reductions from RE and demand-side EE policies and 

programs so that these could be included as part of their 

compliance strategies. Stakeholders said that these tools and 

metrics should build upon the EPA’s “Roadmap for Incorporating 

Energy Efficiency/Renewable Energy Policies and Programs into 

State and Tribal Implementation Plans,” as well as the State 

Energy Efficiency Action Network’s “Energy Efficiency Program 

Impact Evaluation Guide.” In addition, stakeholders requested 

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. 
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This guidance should include allowable programs and policies for 

compliance, examples of compliance pathways, clear information 

on multi-state plan development, and identification of tools. 

As a result of this feedback, in consultation with U.S. DOE 

and other federal agencies, the EPA continued to refine its 

toolbox of decision support resources at: http://www2.epa.gov/ 

www2.epa.gov/cleanpowerplantoolbox. The site includes 

information on regulatory requirements, including state plan 

guidance and state plan decision support. The state plan 

guidance section serves as a central repository for the final 

emission guidelines, RIA, guidance documents, TSDs and other 

supporting materials. The state plan decision support section 

includes information to help states evaluate different 

approaches and measures they might consider as they initiate 

plan development. This section includes, for example, a summary 

of existing state climate and RE and demand-side EE policies and 

programs, information on electric utility actions that reduce 

CO2, and tools and information to estimate the emissions impact 

of RE and demand-side EE programs. 

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 
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method for use in a state plan. States will need to demonstrate 

that any measure included in a state plan meets all relevant 

criteria and adequately addresses elements of the plan 

components discussed in section VIII.D of this preamble. 

IX. Community Considerations 

Climate change is an environmental justice issue. Certain 

people and communities are more vulnerable to the health and 

economic impacts of climate change than others, including low 

income communities, communities of color, and indigenous 

communities. Limited resources make some communities less able 

to either adapt to anticipated changes or recover from the 

impacts. Existing health disparities, including an already high 

burden of chronic health conditions, and other inequities in 

these communities contribute to their increased vulnerability. 

Climate change impacts add to the cumulative stresses currently 

faced by these populations.749

The purpose of this rulemaking is to substantially reduce 

emissions of CO2 from fossil-fired power plants in the United 

States. These emissions contribute to climate change, which has 

been documented to cause adverse health and economic impacts to 

 

749 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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communities in the United States, as well as globally (a more 

robust discussion of how the agency satisfied Executive Order 

12898 can be found in section XII.J of this preamble). This rule 

is one significant step that, along with other domestic programs 

(such as the tailpipe standards and fuel efficiency requirements 

for light, medium, and heavy duty motor vehicles) and programs 

that other countries are putting in place, will begin to address 

the global phenomenon of climate change. 

The EPA has received extensive input and has had numerous 

discussions with community members and representatives of 

environmental justice advocacy organizations throughout this 

rulemaking. We have heard that this rule is vitally important to 

residents of vulnerable and overburdened communities as it 

directly addresses climate change, which is an issue of concern 

for communities. Additionally, we have heard concerns that the 

plans that states will develop to implement the emission 

guidelines must be sensitive to and protect against the 

possibility of disproportionate impact on those communities that 

live near power plants. We received feedback that it is critical 

that states provide meaningful opportunities for public 

participation in the development of their plans and that they 

pay attention to how their plans may affect overburdened 

communities. We have also heard concerns about potential co-
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pollutant increases in communities due to operational and 

efficiency changes as a result of some affected EGUs potentially 

being dispatched more intensively in the future than they were 

in the past. We have also heard concerns about the potential for 

this rulemaking to have disproportionate high and adverse human 

health or environmental effects on affected communities. 

Stakeholders have also strongly conveyed to us that low income 

communities represent tremendous opportunities for deployment of 

energy efficiency (EE) and renewable energy (RE) compliance 

options, but that focused strategies are essential to ensure 

robust adoption of these technologies by low income communities. 

As the scientific literature presented in section II.A of 

this preamble and the Executive Order 12898 discussion in 

section XII.J of this preamble outline, low-income communities 

and some communities of color are especially vulnerable to the 

health and other adverse impacts of climate change. The EPA 

believes that all communities, including low-income communities 

and communities of color, will benefit from this final rule 

because this action directly addresses the impacts of climate 

change by limiting GHG emissions through the establishment of CO2 

emission guidelines for existing affected fossil fuel-fired EGUs 

and provides significant co-benefit reductions in conventional 

air pollutants. 
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 This rule can affect vulnerable communities in several 

ways. First, this rule will reduce the adverse impacts of 

climate change that can affect vulnerable communities 

disproportionally. These are impacts at global and national 

scales and reductions of CO2 anywhere will benefit communities 

everywhere. To the extent that this rule is an important step in 

the global effort to address climate change, vulnerable 

communities are important beneficiaries. 

The second way this rule can affect communities is through 

the co-benefit reductions in criteria and hazardous air 

pollutants (PM, NOx, and mercury, for example) that will occur 

as a result of a shift to a cleaner and more efficient power 

sector. Our analysis shows projected reductions of XXX,XXX tons 

in 2030 across the country. Impacts from emissions of these 

pollutants are at local and regional scales, and these 

reductions will lead to improved public health both in the 

communities where the facilities reducing emissions are located 

as well as many miles downwind of those facilities. Therefore, 

low income communities, communities of color, and indigenous 

communities are already more vulnerable to the adverse public 

health impacts of climate change and therefore will especially 

benefit from the reductions in air pollutants as a result of 

this rule. 
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Other impacts that may be anticipated from this rule can 

affect communities in various ways. The electricity sector is, 

and will continue to be, investing more in renewable energy (RE) 

and in energy efficiency (EE). These trends may impact affected 

communities in at least two ways. First, the expansion of RE and 

EE both provide opportunities for job creation and investment in 

communities. Second, shifts in how electricity is produced and 

used may lead to changes in the cost of electricity and 

consequent electricity bills. A significant barrier to the 

adoption of EE and RE by affected communities is the higher 

upfront cost (e.g., of purchasing a more efficient appliance or 

installing rooftop solar panels). It is important that 

communities impacted by state plans are able to access EE and RE 

so that they can take advantage of these opportunities to lower 

their electricity bills. The EPA believes it is important for 

states to consider these potential impacts on affected 

communities as they are developing their plans. 

Environmental justice stakeholders are nonetheless 

concerned about possible local increases in pollution that may 

arise from increased dispatch of certain units. 

In the remainder of this section of the preamble, we 

address these many issues and the results of an analysis we 

conducted to assess the proximity of vulnerable communities to 
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fossil fuel- fired power plants in the United States. 

Additionally, we discuss one of the most important ways to 

minimize potential adverse impacts — of whatever kind − on 

vulnerable communities: a robust public engagement process for 

state plan development that provides meaningful opportunities 

for participation, evaluation of potential impacts, and a 

discussion of ways to address then. Furthermore, we explain 

changes we have made to the rule to address these issues. 

These final emission guidelines will be implemented by each 

state upon the EPA’s approval of a state plan. The EPA has 

included a number of conditions to help ensure that affected 

communities will be able to participate meaningfully in the 

development of state plans and that this action will not have 

potential disproportionately high and adverse human health or 

environmental effects on communities, including low-income 

communities and communities of color. The conditions outlined in 

this section of the preamble were considered as part of the 

EPA’s analysis under Executive Order 12898. 

A. Proximity Analysis 

To further ensure that this rulemaking does not have any 

potential disproportionately high and adverse human health or 

environmental effects on vulnerable communities, the EPA has 

conducted an analysis for this final rulemaking that summarizes 
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demographic data on the communities located near power plants (a 

proximity analysis). The EPA understands that, in order to 

prevent any potential disproportionately high and adverse human 

health or environmental effects on these communities, both 

states and communities must have information on the communities 

living near facilities, including demographic data, and that 

accessing and using census data files requires expertise that 

some community groups may lack. Therefore, the EPA used census 

data from the American Community Survey (ACS) 2008-2012 to 

conduct a proximity analysis for this rulemaking, and 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. 

The proximity analysis provides detailed demographic 

information on the communities located within a 3-mile radius of 

each affected power plant in the United States. Included in the 

analysis is the breakdown by percentage of community 

characteristics such as income and minority status. The analysis 

shows a higher percentage of communities of color and low-income 

communities living near power plants than national averages.

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 
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urban power plants. There are many rural power plants that are 

located near small communities with relatively few persons of 

color but high percentages of low-income populations. In urban 

areas, nearby communities tend to be both low-income communities 

and communities of color. 

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 affected 

communities and their states and will be useful for states as 

they begin developing their plans. 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/. 

B. 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 
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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 implementation plans of the 

Clean Power Plant guidance do not violate any of the federal 

nondiscrimination statutes, including Title VI. 

The EPA’s Office of Civil Rights (OCR) is responsible for 

carrying out compliance with these federal nondiscrimination 

statutes and does so through a variety of means 

including: complaint investigation; agency-initiated compliance 

reviews; pre-grant award assurances and audits; and technical 

assistance and outreach activities. Anyone who believes that any 

of the federal nondiscrimination laws enforced by OCR have been 

violated by a recipient of EPA financial assistance may file an 

administrative complaint with EPA’s OCR. 

C. Community Engagement in State Plan Development 
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Additionally, meaningful public involvement as described in 

EPA’s 2006 Public Involvement Guidance (71 Fed. Reg. 14,207) 

should play a pivotal role to ensure that the state 

implementation plans of the Clean Power Plant guidance do not 

violate any of the federal nondiscrimination statutes. States 

should seek opportunities to enhance public involvement in the 

environmental decision-making process, including providing 

access to limited English proficient individuals, as a means of 

hearing and considering communities’ concerns early in the 

process which may potentially reduce the chances of a Title VI 

complaint being filed about a recipient’s actions. 

As highlighted above the EPA is requiring that states 

engage with all stakeholders throughout the state plan 

development process and that states consider and address all 

feedback received as they create their final plans. In section 

VIII.D of this preamble, the EPA notes that states need to 

ensure that there is meaningful involvement for all members of 

the public during the initial and final plan submittal process. 

This engagement includes providing the opportunity for public 

comment on the state’s draft submittal and responding to 

significant comments received (including comments from 

communities potentially impacted by their plan), as well as 

conducting a public hearing before a final state plan is 
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submitted. Furthermore, as noted in section VIII.E of this 

preamble, in determining if states are eligible for a 2-year 

extension for submission of final plans, the EPA will require 

that states demonstrate that they are actively engaging affected 

communities as part of their public participation process. The 

steps that states could take to demonstrate that they are 

actively engaging the public, including communities affected by 

their plan, are outlined in section VIII.E of this preamble. 

Additionally, as outlined in section VIII.D of this preamble, 

the final plan submitted by states should include an overview of 

the public hearing(s) conducted and information on how the state 

ensured that the hearing(s) were accessible to communities that 

may be potentially impacted by their plan. 

It is important to the EPA that affected communities have 

the information needed to effectively engage with states during 

the state plan development process. At the same time, it is 

important to the EPA that states also have support in engaging 

with affected communities throughout the state plan development 

process. As a result, the EPA will provide training and other 

resources throughout the implementation process that will assist 

affected communities and states as they engage with one another. 

These trainings will be a continuation of those that the EPA has 

already conducted with communities and states both pre- and 
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post-proposal. The EPA will be reaching out to a wide variety of 

community stakeholders, including groups representing low-income 

communities and communities of color, faith-based organizations, 

academic organizations working with communities, and other 

community stakeholders. 

As noted in section VIII.C of this preamble, the EPA will 

encourage multi-state partnerships. Multi-state partnerships, 

like the Regional Greenhouse Gas Initiative (RGGI), have 

demonstrated their ability to invest in EE/RE programs and 

direct energy bill assistance programs in communities.750 For 

example, from 2008-2013, RGGI invested over $1 billion in 

auction proceeds towards various policy priorities.751 Investment 

into energy efficiency programs made up 62% of cumulative RGGI 

investments through 2013.752 These investments are projected to 

earn an expected return of more than $2.3 billion in lifetime 

energy bill savings for 1.2 million households and 17,550 

businesses.753 Additionally, investments in clean and renewable 

energy make up 8% of cumulative investments and these 

investments are expected to yield a return of more than $240 

 

750 Investment of RGGI Proceeds through 2013. 

http://www.rggi.org/docs/ProceedsReport/Investment-RGGIProceeds-Through-2013.pdf 

751 Ibid. 

752 Ibid. 

753 Ibid. 
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million in lifetime energy bill savings to 7,000 participating 

households and 250 businesses.754 Furthermore, direct bill 

assistance makes up 15% of cumulative investments, these 

investments have returned more than $140 million in bill savings 

to more than 2.4 million households, much of which is targeted 

towards low income families.755 

In addition, the EPA encourages states in the writing of 

their plans to use other state models that help low income 

communities access the benefits of energy efficiency, renewable 

energy, and financial assistance programs. One example of such a 

program is The Maryland EmPOWER Low Income Energy Efficiency 

Program (LIEEP).756 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.).757 Funding for 

this program is provided by EmPOWER Maryland partners: Baltimore 

Gas and Electric, Southern Maryland Electric Cooperative, 

 

754 Ibid.

755 Ibid.

756 EmPOWER Maryland Low Income Energy Efficiency Programs 

(LIEEP). 

http://www.mdhousing.org/website/Programs/lieep/Default.aspx.

757 Ibid. 
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Delmarva Power, Allegheny Energy and Pepco.758 This program is 

available to both homeowners and renters.759 Additionally, the 

Maryland Department of Housing provides low income families with 

home heating bill assistance and furnace repairs and 

replacements through the Maryland Energy Assistance Program 

(MEAP).760 Maryland’s Electric Universal Service Program (EUSP) 

helps low-income electric customers with their electric bills.761

In the coming months, the EPA will continue to provide 

information resources for affected communities and states on 

existing federal, state, local, and other financial assistance 

programs to encourage EE/RE that are already available to 

communities. The EPA will also provide a catalog of current or 

recent state and local programs that have successfully helped 

communities adopt EE/RE measures. The goal of these resources is 

to help affected communities gain the benefits of this 

rulemaking by encouraging that states use these types of tools 

in their state plans. 

Additionally, the EPA recognizes the potential impacts that 

this rulemaking could have on jobs in communities. Therefore, in 

section VIII.H of this preamble, the EPA has outlined that 

 

758 Ibid. 

759 Ibid. 

760 Energy Assistance. 

http://www.dhr.state.md.us/blog/?page_id=4326. 

761 Ibid.
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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 manifested. 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 (e.g., with regard to 

installing energy efficiency measures and rooftop solar panels). 

Additionally, as part of the resources that we will be providing 

to states and affected communities, the EPA will provide 

information on the White House’s Partnership for Opportunity and 

Workforce and Economic Revitalization (POWER) Initiative and 

other programs that specially targets economic development 

assistance to communities affected by changes in the coal 

industry and the utility power sector.762 

D. Co-pollutants 

As a result of this rulemaking, and as stated in section 

XI.F of this preamble, the EPA expects that most of America will 

benefit from improved air quality for PM2.5, ozone, and HAP, as 

well as greenhouse gases. Nonetheless, due to operational and 

efficiency changes, some affected EGUs may be dispatched more 

 

762 http://www.eda.gov/power/. 
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intensively in the future than they were in the past. While the 

EPA will approve state plans, it is the states that have the 

ultimate responsibility to implement the guidelines of this 

rulemaking in order to meet their goals; as a result the EPA 

cannot predict localized emission increases or decreases. While 

there may be increases of co-pollutants at some facilities, it 

is important to remember that affected EGUs will still have to 

comply with other CAA rulemakings in addition to the guidelines 

in this final rulemaking. As noted in the NSR discussion in 

section X.A of this preamble, a state’s CAA section 111(d) plan 

may require an affected EGU to undertake physical or operational 

changes to improve its efficiency, which could result in an 

increase in the unit’s dispatch and an increase in the unit’s 

annual emissions of GHGs and/or other regulated pollutants. 

However, a state can take steps to avoid increased utilization 

of particular affected EGUs (i.e., dispatching other units) and 

associated emissions of regulated pollutants whose environmental 

effects would be more localized around the affected EGU. To the 

extent that states take this path, there would be no 

disproportionate impacts in the areas near such affected EGUs. 

For those affected EGUs in a permitting situation for which 

the EPA is the permit reviewing authority, the EPA will consider 
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environmental justice issues, as required by Executive Order 

12898. 

Air quality in a given area, even in locations near 

emission sources, is influenced by emissions from nearby sources 

and in part by emissions that travel hundreds of miles and mix 

with emissions from other sources.763 In the Cross-State Air 

Pollution Rule the EPA used its authority to reduce emissions 

that significantly contribute to downwind exposures. The 

regulatory impact analysis for the final Cross-State Air 

Pollution Rule anticipates substantial health benefits for the 

population across a wide region. Therefore, 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.764

Another effect of the final CO2 emission guidelines for 

affected existing fossil fuel-fired EGUs will 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 will operate more 

hours during the year and could emit pollutants, including 

 

763 76 FR 48348. 

764 76 FR 48347. 
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pollutants whose environmental effects would be localized/and or 

regional rather than global as is the case with GHG emissions. 

Changes in utilization already occur in response to energy 

demands and evolving energy sources, but the final CO2 emission 

guidelines for affected existing fossil fuel-fired EGUs can be 

expected to cause more such changes. Increased utilization 

generally would not increase peak concentrations of PM2.5, NOx, or 

ozone around such EGUs to levels higher than those that are 

already occurring because peak hourly or daily emissions 

generally would not change; however, increased utilization may 

make periods of relatively high concentrations more frequent. It 

should be noted that the gas-fired sources likely to be 

dispatched more frequently have very low emissions of primary 

PM, SO2, and HAP per unit of electrical output; therefore, 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 RTC.”765 Because gas-fired EGUs emit 

essentially no mercury, increased utilization will not increase 

methylmercury concentrations in water bodies near these affected 

 

765 65 FR 79831. 
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EGUs. In studies done by DOE/NETL comparing cost and performance 

of coal- and 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.766 Many, 

although not all, NGCC units are also very well controlled for 

emissions of NOx through the application of after combustion 

controls such as selective catalytic reduction. 

Depending on the design of the state plan, the state may be 

able to predict which affected EGUs may increase generation 

and/or may cause increases in emissions and should address any 

concerns about localized NOx concentrations in the design of the 

CAA section 111(d) program, or separately from the CAA section 

111(d) program planning process but before such program is 

implemented. 

Existing tracking systems will also allow states and the 

EPA to be aware of affected EGUs whose utilization has increased 

most significantly, and to assess whether air quality has 

changed in the communities around such affected EGUs. There are 

multiple mechanisms in the CAA to address situations where there 

 

766 “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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is an existing air quality problem or where one may develop. 

Additionally, states will have to comply with the National 

Ambient Air Quality Standards (NAAQS) and other EPA rulemakings 

that come into effect during this same compliance period to 

protect public health and the environment. 

E. EPA Continued Engagement 

The EPA is committed to helping ensure that this action 

will not have potential disproportionately high and adverse 

human health or environmental effects on vulnerable communities. 

Throughout the implementation process of this rulemaking, the 

agency will continue to provide trainings and resources to 

assist affected communities and states as they engage with one 

another. In addition, the agency, through its outreach efforts 

during the implementation phase of this rulemaking, will 

continue to solicit feedback from affected communities and 

states on topics for which they would like additional trainings 

and resources. 

Additionally, the EPA will provide states with resources 

containing examples of analyses that other states have conducted 

to examine the impacts of their programs on communities. States 

can use this information to conduct analyses of their own if 

they so choose. 
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A more detailed discussion concerning the application of 

Executive Order 12898 in this rulemaking can be found in section 

XI.J of this preamble. A summary of the EPA’s interactions with 

communities is in the EJ Screening Report for the Clean Power 

Plan, available in the docket of this rulemaking. Furthermore, 

the EPA’s responses to public comments, including comments 

received from communities, are provided in the response to 

comments documents located in the docket for this rulemaking. 

F. Summary of Changes Made 

As described above, the EPA made several changes in this 

Final rule that reflect comments from communities and other 

stakeholders. In response to such input, the EPA has conducted a 

proximity analysis for this rulemaking and provided the report 

in the docket. Additionally, the EPA has added a number of 

provisions in the state plan section that address community 

engagement and involvement throughout the implementation 

process. The EPA will continue outreach efforts and will 

continue to reach out to affected communities on topics that 

they are interested in learning more about. 

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 
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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. For GHG emissions, the prevention of 

significant deterioration (PSD) applicability analysis is 

described in the Prevention of Significant Deterioration and 

Title V Greenhouse Gas Tailoring Rule (FR 75 31514, June 3, 

2010). As a general matter, a modifying major stationary source 

would trigger PSD permitting requirements for GHGs if it emits 

GHGs in excess of 100,000 tons per year of carbon dioxide 

equivalents (CO2e), and it undergoes a change or change in the 

method of operation (modification) resulting in an emissions 

increase of 75,000 tons per year CO2e as well as an increase on a 

mass 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 
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located or proposed to be built determine the specific 

permitting requirements. 

As part of its CAA section 111(d) plan, a state may impose 

requirements that require an affected EGU to undertake a 

physical or operational change to improve the unit’s efficiency 

that results in an increase in the unit’s dispatch and an 

increase in the unit’s annual emissions. If the emissions 

increase associated with the unit’s changes exceeds the 

thresholds in the NSR regulations discussed above for one or 

more regulated NSR pollutants, including the netting analysis, 

the changes would trigger NSR. 

While there may be instances in which an NSR permit would 

be required, we expect those situations to be few. As previously 

discussed in this preamble, states have considerable flexibility 

in selecting varied measures as they develop their plans to meet 

the goals of the emissions guidelines. One of these 

flexibilities is the ability of the state to establish the 

standards of performance in their CAA section 111(d) plans in 

such a way so that their affected sources, in complying with 

those standards, in fact would not have emissions increases that 

trigger NSR. To achieve this, the state would need to conduct an 

analysis consistent with the NSR regulatory requirements that 

supports its determination that as long as affected sources 
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comply with the standards of performance in their CAA section 

111(d) plan, the source’s emissions would not increase in a way 

that trigger NSR requirements. 

For example, a state could decide to adjust its demand-side 

measures or increase reliance on renewable energy as a way of 

reducing the future emissions of an affected source initially 

predicted (without such alterations) to increase its emissions 

as a result of a CAA section 111(d) plan requirement. In other 

words, a state plan’s incorporation of expanded use of cleaner 

generation or demand-side measures could yield the result that 

units that would otherwise be projected to trigger NSR through a 

physical change that might result in increased dispatch would 

not, in fact, increase their emissions, due to reduced demand 

for their operation. The state could also, as part of its CAA 

section 111(d) plan, develop conditions for a source expected to 

trigger NSR that would limit the unit’s ability to move up in 

the dispatch enough to result in a significant net emissions 

increase that would trigger NSR (effectively establishing a 

synthetic minor limit). 767

 

767 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 
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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 

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 

 

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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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 

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. 
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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 United States Supreme Court 

issued its opinion in UARG v EPA, 134 S.Ct. 2427 (June 23, 

2014), and in accordance with that decision, the D.C. Circuit 

subsequently issued an amended judgment in Coalition for 

Responsible Regulation, Inc. v. Environmental Protection Agency, 

Nos. 09-1322, 10-073, 10-1092 and 10-1167 (D.C. Cir., April 10, 

2015). Those decisions support the same overall conclusion, as 

the EPA discussed in the proposal, with respect to the effect of 

this final section 111 rule on the applicability thresholds for 

GHGs under the operating permits rules, though for different 

reasons. 
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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. 

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.768 The EPA recognizes the importance of assuring that each 

 

768 We discuss other rulemakings solely for background purposes. 

The effort to coordinate rulemakings is not a defense to a 
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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 

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 

 

violation of the CAA. Sources cannot defer compliance with 

existing requirements because of other upcoming regulations. 
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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 

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 
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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))

(referred to hereinafter as the 316(b) rule.) The rule was 

published on August 15, 2014 (79 FR 48300; August 15, 2014), and 
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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.769 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 

impose a substantial cost burden on affected facilities. With 

respect to entrainment, the rule calls upon the permitting 

 

769 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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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 
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for the steam electric power generating point source category. 

The current regulations, which were last updated in 1982, do not 

adequately address the toxic pollutants discharged from the 

electric power industry, nor have they kept pace with process 

changes that have occurred over the last three decades. Existing 

steam electric power plants currently contribute 50-60 percent 

of all toxic pollutants discharged to surface waters by all 

industrial categories regulated in the United States under the 

CWA. Furthermore, power plant discharges to surface waters are 

expected to increase as pollutants are increasingly captured by 

air pollution controls and transferred to wastewater discharges. 

The proposed regulation, which includes new requirements for 

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, 
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the EPA describes its thinking on how it might effectively 

harmonize the potential requirements of that rule with the 

requirements of the final CCR rule. Because these two rules 

affect similar units and may be met with similar compliance 

strategies, common-sense implementation timeframes were 

established in the CCR final rule so that utilities would not be 

required to make major decisions about CCR units without first 

understanding the implications that such decisions would have 

for meeting the surface water protection requirements of the 

final ELG rule. The EPA is taking into account these new CCR 

requirements for coal ash as it develops the final SE ELG rule. 

The EPA's goal in harmonizing the SE ELG and CCR rules is to 

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 
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nonattainment for the 2008 ozone NAAQS. The final implementation 

rule for the 2008 ozone NAAQS was signed on February 13, 2015, 

and published on March 6, 2015, with an effective date of April 

6, 2015. In general, the 2008 ozone NAAQS implementation rule 

interprets applicable statutory requirements and provides 

flexibility to states to minimize administrative burdens 

associated with developing and implementing plans to meet and 

maintain the NAAQS. The rule establishes due dates for 

attainment plans and clarifies attainment dates for each ozone 

nonattainment area according to its classification based on air 

quality thresholds, with attainment dates starting in July 2015 

through July 2032 depending on an area’s classification. 

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. 
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The proposal also outlined the key implementation 

milestones requiring revised state implementation plans, with 

due dates starting in October 2018 for infrastructure and 

interstate transport SIPs, attainment plans due 2020-21, and 

attainment dates of 2020-37. The EPA is under a court order to 

finalize its review of the ozone NAAQS by October 1, 2015. 

 Some commenters expressed concern with the potential 

impact proposed revisions to the ozone NAAQS could have on state 

planning efforts and affected entities’ ability to comply with 

any potentially new requirements associated with a revised ozone 

NAAQS and those related to the 111(d) emissions 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) 

emissions guidelines proposal, commenters expressed a desire for 

the EPA to coordinate promulgation of the final 111(d) emissions 

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 
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believe the planning and compliance timeframes that would follow 

from a revised ozone NAAQS and the timeframes we are finalizing 

today for submittal of the CAA section 111(d) state plans will 

allow considerable time for coordination by states in the 

development of their respective plans, as needed. As stated in 

the proposal, the EPA is prepared to work with states to assist 

them in coordinating their efforts across these planning 

processes. 

Regarding PM2.5 NAAQS implementation, the proposal stated 

that the EPA was developing a proposed implementation rule to 

provide guidance to states on the development of SIPs for the 

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. 
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There are currently only 9 areas designated nonattainment 

for the 2012 PM2.5 NAAQS, with an effective date of April 15, 

2015. Since the attainment plans for these areas must be 

completed and submitted to the EPA in September 2016, we expect 

that the four states with such areas should have already decided 

on their approach to implementing the 2012 PM2.5 NAAQS when they 

begin to develop their plans for implementing the 111(d) 

guidelines, and will be able to coordinate the two. 

Related to the SO2 NAAQS, and as stated in the proposal, the 

SO2 NAAQS was revised in June 2010 to protect public health from 

the short-term effects of SO2 exposure. In July 2013, the EPA 

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 
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all other areas in three separate actions in the future.770 These 

designations must be completed by no later than July 2, 2016, 

December 31, 2017, and December 31, 2020 with attainment plans 

due between 2018 and 2022. 

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. 

 

770 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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While the EPA is providing considerable flexibility for 

states and sources under the final 111(d) emissions guidelines, 

the EPA acknowledges the possibility that some sources could 

ultimately be faced with the potential for stranded assets as a 

result of state 111(d) plans. For these sources, however, states 

have the option of developing BART alternatives that replace 

control requirements that would otherwise result in stranded 

assets at a particular EGU with the aggregate emission 

reductions that will result from retirements, fuel switching, 

reduced utilization, or lesser controls at multiple EGUs. 

In fact, the EPA already has experience working with states 

to account for these very types of changed circumstances.771 The 

EPA will continue to work with states to explore options for 

integrating compliance requirements across multiple regulatory 

programs, as warranted. 

 

771 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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The EPA believes that CAA section 111(d) efforts and 

actions will tend to contribute to overall air quality 

improvements and thus should be complementary to criteria 

pollutant and regional haze SIP efforts. 

7. Final Rule Flexibilities 

As discussed in Section VIII of this preamble, the EPA is 

providing states flexibility in developing approvable plans 

under CAA section 111(d), including the ability to impose 

source-by-source limitations reflecting the BSER performance 

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, 
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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 

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.772 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 

 

772 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. 
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requirements, while assuring an adequate, affordable, and 

reliable supply of electricity. 

XI. Impacts of the Final Action773 

A. What are the air impacts?

The EPA anticipates significant emission reductions under 

the final guidelines for the utility power sector. When compared 

to 2005, CO2 emissions are projected to be reduced by 

approximately [X] percent in 2020, [X] percent in 2025, and [X] 

percent in 2030. The final guidelines are projected to result in 

substantial co-benefits through reductions of SO2, PM2.5 and NOX

that will have direct public health benefits by lowering ambient 

levels of these pollutants and ozone. Table 11 shows expected CO2 

and other air pollutant emissions in the base case and 

reductions under the final guidelines for 2020, 2025, and 2030. 

Table 11. Summary of CO2 and Other Air Pollutant Emission 

Reductions under Final Guidelines 

 

CO2

(million 

metric 

tons) 

SO2

(thousands 

of tons) 

NOX 

(thousands 

of tons) 

PM2.5 

(thousands 

of tons) 

2020 Final Guidelines 

 

773 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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Base Case [X] [X] [X] [X] 

Final Guidelines [X] [X] [X] [X] 

Emissions 

Reductions [X] [X] [X] [X] 

2025 Final Guidelines 

Base Case [X] [X] [X] [X] 

Final Guidelines [X] [X] [X] [X] 

Emissions 

Reductions [X] [X] [X] [X] 

2030 Final Guidelines 

Base Case [X] [X] [X] [X] 

Final Guidelines [X] [X] [X] [X] 

Emissions 

Reductions [X] [X] [X] [X] 

Source: Integrated Planning Model, 2015. 

The reductions in Table 11 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 
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7(a)(2) would not be triggered by promulgation of the rule, and 

we now finalize that determination in this final rule. 

Section 7(a)(2) of the ESA requires federal agencies, in 

consultation with one or both of the Services (depending on the 

species at issue), to ensure that actions they authorize, fund, 

or carry out are not likely to jeopardize the continued 

existence of federally listed endangered or threatened species 

or result in the destruction or adverse modification of 

designated critical habitat of such species. 16 U.S.C. 

1536(a)(2). Under relevant implementing regulations, section 

7(a)(2) applies only to actions where there is discretionary 

federal involvement or control. 50 CFR 402.03. Further, under 

the regulations consultation is required only for actions that 

“may affect” listed species or designated critical habitat. 50 

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. Indirect 

effects are those that are caused by the action, later in time, 

and are reasonably certain to occur. Id. To trigger a 
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consultation requirement, there must thus be a causal connection 

between the federal action, the effect in question, and the 

listed species, and the effect must be reasonably certain to 

occur. 

The EPA notes that the projected environmental effects of 

this rule are positive: reductions in overall GHG emissions, and 

reductions in PM and ozone-precursor emissions (SO2 and NOX). 

However, the fact that the rule will have overall positive 

effects on the environment does not mean that the rule may 

affect any listed species or designated critical habitat within 

the meaning of ESA section 7(a)(2) or the implementing 

regulations or require ESA consultation. The EPA has considered 

various types of potential effects in reaching the conclusion 

that ESA consultation is not required for this rule. 

With respect to the projected GHG emission reductions, the 

EPA considered in detail in the proposal why such reductions do 

not trigger ESA consultation requirements under section 7(a)(2). 

As explained in the proposal, in reaching this conclusion the 

EPA was mindful of significant legal and technical analysis 

undertaken by FWS and the U.S. Department of the Interior (DOI) 

in the context of listing the polar bear as a threatened species 

under the ESA. In that context, in 2008, FWS and DOI expressed 

the view that the best scientific data available were 
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insufficient to draw a causal connection between GHG emissions 

and effects on the species in its habitat.774 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. 

The EPA has also previously considered issues relating to 

GHG emissions in connection with the requirements of ESA section 

7(a)(2). Although the GHG emission reductions projected for this 

final rule are large (estimated reductions of [X] million metric 

tons of CO2 in 2030 – see Table 11 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 roughly double and four times those projected here 

over the lifetimes of the model years in question775 and, based 

on air quality modeling of potential environmental effects, 

concluded that “EPA knows of no modeling tool which can link 

 

774 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). 

775 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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these small, time-attenuated changes in global metrics to 

particular effects on listed species in particular areas. 

Extrapolating from global metric to local effect with such small 

numbers, and accounting for further links in a causative chain, 

remain beyond current modeling capabilities.” EPA, Light Duty 

Vehicle Greenhouse Gas Standards and Corporate Average Fuel 

Economy Standards, Response to Comment Document for Joint 

Rulemaking at 4-102 (Docket EPA-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, given that the 

projected CO2 emission reductions are less than those projected 

for either of the light duty vehicle rules. See, e.g., Ground 

Zero Center for Non-Violent Action v. U.S. Dept. of Navy, 383 F. 

3d 1082, 1091-92 (9th Cir. 2004) (where the likelihood of 

jeopardy to a species from a federal action is extremely remote, 

ESA does not require consultation). 
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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. 

Consequently, CAA section 111(d) provides no discretion to 

adjust the standard based on potential impacts to endangered 

species of reduced criteria pollutant emissions. Section 7(a)(2) 

consultation thus is not required with respect to the projected 

reductions of criteria pollutant emissions. See 50 CFR 402.03; 

see also, WildEarth Guardians v. U.S. Envt’l Protection Agency, 

759 F.3d 1196, 1207-10 (10th Cir. 2014) (EPA has no duty to 

consult under section 7(a)(2) of the ESA regarding hazardous air 

pollutant controls that it did not require – and likely lacked 

authority to require – in a federal implementation plan for 

regional haze controls under section 169A of the CAA); National 

Lime Ass'n v. EPA, 233 F. 3d 625, 638-39 (D.C. Cir. 2000) 

(although CAA section 112(b)(2) prohibits the EPA from listing 

criteria pollutants as hazardous air pollutants, the EPA may use 

PM as a surrogate for metal hazardous air pollutants and 

reductions in PM do not constitute impermissible regulation of a 

criteria pollutant). 

Finally, the EPA has also considered other potential 

effects of the rule (beyond reductions in air pollutants) and 
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whether any such effects are sufficiently certain to call for 

ESA consultation. As the EPA noted in the proposal, there are 

substantial questions as to whether any potential for relevant 

effects results from any element of the rule or would result 

instead from separate decisions and actions made in connection 

with the development, implementation, and enforcement of a plan 

to implement the standards established in the rule. Cf. American 

Trucking Assn's v. EPA, 175 F. 3d 1027, 1043-45 (D.C. Cir. 

1999), rev'd on different grounds sub nom., Whitman v. American 

Trucking Assn's, 531 U.S. 457 (2000) (National Ambient Air 

Quality Standards have no economic impact, for purposes of 

Regulatory Flexibility Act, because impacts result from the 

actions of states through their development, implementation and 

enforcement of state implementation plans). The EPA recognized, 

for instance, that questions may exist whether decisions such as 

increased utilization of solar or wind power could have effects 

on listed species. The EPA received comments on the proposal 

asserting that because potential increased reliance on wind or 

solar power may be an element of Building Block 3, and because 

wind and solar facilities may in some cases have effects on 

listed species, the EPA must consult under the ESA on this 

aspect of the rule. The EPA is also aware of certain questions 

posed by a Member of the U.S. House of Representatives to FWS 
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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.776 

The EPA does not believe that the effects of potential 

future changes in the energy sector – including increased 

reliance on wind or solar power – or any potential alterations 

in the operations of any particular facility are 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 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 on wind power, as 

 

776 See Letter from Rob Bishop, Chairman, Committee on Natural 

Resources, to Dan Ashe, Director, U.S. Fish and Wildlife 

Service, dated April 2, 2015. 
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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. 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 

made in the planning process, which cannot now be predicted with 

reasonable certainty or required by the rule. The EPA notes that 

many of these decisions will be made by other entities, most 

likely states. The EPA also notes that the plans adopted for 

particular states may themselves provide wide degrees of 

implementation flexibility, thus further increasing the 

uncertainty that any species-impacting activity will occur in 

any particular location, if at all. The Services have explained 

that section 7(a)(2) was not intended to preclude federal 

actions based on potential future speculative effects.777 These 

 

777 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 
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are precisely the types of speculative future activities and 

effects at issue here.778 For this additional reason, the EPA 

concludes that the rule does not have effects on listed species 

that trigger the section 7(a)(2) consultation requirement. 

C. What are the energy impacts? 

 The final guidelines have important energy market 

implications. Under the final guidelines, average nationwide 

retail electricity prices are projected to increase/decrease 

about [X] percent in 2020, increase/decrease [X] percent in 

2025, and increase/decrease [X] percent in 2030 for the 

contiguous U.S., relative to the base case. Average monthly 

electricity bills are anticipated to increase/decrease about [X] 

 

(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). 

778 EPA also notes that some of the future implementing 

activities themselves may require ESA consultation, thus 

providing consideration of any impacts on listed species at the 

appropriate point when particular activities have become 

reasonably certain. Several commenters on the proposal 

specifically noted that such future activities – e.g., 

development of additional renewable energy facilities such as 

wind farms – may call for ESA consultation. Further, EPA notes 

that section 9 of the ESA, which prohibits the take of 

individuals of most listed species, provides an additional 

protection for listed species as future implementing activities 

become reasonably certain. 
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percent in 2020, increase/decrease [X] percent in 2025, and 

increase/decrease [X] percent in 2030, relative to the base 

case. 

 Under the final guidelines, the average delivered coal 

price to the utility power sector is projected to 

increase/decrease about [X] percent in 2020, increase/decrease 

[X] percent in 2025, and increase/decrease [X] percent in 2030, 

relative to the base case. The EPA projects coal use by the 

utility power sector, a large component of total coal use, will 

increase/decrease approximately [X] percent in 2020, 

increase/decrease[X] percent in 2025, and increase/decrease [X] 

percent in 2030 from base case levels. 

The EPA also projects that utility power sector-delivered 

natural gas prices will increase/decrease about [X] percent in 

2020, increase/decrease [X] percent in 2025, and 

increase/decrease [X] percent in 2030. Natural gas use for 

electricity generation will increase/decrease about [X] trillion 

cubic feet (TCF) in 2020, increase/decrease [X] TCF in 2025, and 

increase/decrease [X] TCF in 2030 relative to the base case. 

Renewable energy capacity is anticipated to increase by 

roughly [X] GW in 2025 and [X] GW in 2030 under the final 

guidelines. 
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 These figures reflect the EPA’s illustrative modeling that 

presumes policies that lead to generation shifts and growing use 

of demand-side energy efficiency and renewable electricity 

generation out to 2029. If states make different policy choices, 

impacts could be different. For instance, if states implement 

renewable and/or demand-side energy efficiency policies on a 

more aggressive time-frame, impacts on natural gas and 

electricity prices would likely be less. Implementation of other 

measures not included in the BSER calculation or compliance 

modeling, such as nuclear uprates, transmission system 

improvements, use of energy storage technologies or retrofit 

CCS, could also mitigate gas price and/or electricity price 

impacts. 

 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 demand-
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side energy efficiency. The compliance assumptions – and, 

therefore, the projected compliance costs - set forth in this 

analysis are illustrative in nature and do not represent the 

full suite of compliance flexibilities states may ultimately 

pursue. The illustrative analysis is designed to reflect, to the 

extent possible, the scope and the nature of the final 

guidelines. However, there is considerable uncertainty with 

regards to the precise measures that states will adopt to meet 

the final requirements, because there are considerable 

flexibilities afforded to the states in developing their state 

plans. 

 The incremental cost is the projected additional cost of 

complying with the guidelines in the year analyzed and includes 

the amortized cost of capital investment, needed new capacity, 

shifts between or amongst various fuels, deployment of demandside energy efficiency programs, and other actions associated 

with compliance. These important dynamics are discussed in more 

detail in the RIA in the rulemaking docket. 

The EPA projects that the annual incremental compliance 

cost of the final guidelines is estimated to be $[X] billion in 

2020, about $[X] billion in 2025, and about $[X] billion (2011$) 

in 2030. These estimates also include the costs associated with 

monitoring, reporting, and recordkeeping (MRR). MRR costs are 
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estimated to be approximately $[X] million in 2020, $[X] million 

in 2025, and $[X] million (2011$) in 2030. 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 

standards. Overall, we project generation shifts, changes to 

fossil fuel and retail electricity prices, and some additional 

coal-fired EGU retirements. Average utility power sector 

delivered natural gas prices are projected to increase/decrease 

roughly [X] percent in 2020, increase/decrease [X] percent in 

2025, and increase/decrease [X] percent in 2030 under the final 

guidelines, on a nationwide average basis. The average delivered 

coal price to the utility power sector is projected to 

increase/decrease about [X] percent in 2020, increase/decrease 

[X] percent in 2025, and increase/decrease [X] percent in 2030 

under the final guidelines, on a nationwide average basis. 

Retail electricity prices are projected to increase/decrease [X] 

percent in 2020, increase/decrease [X] percent in 2025, and 

increase/decrease [X] in 2030 on an average basis across the 

contiguous U.S. Under the final guidelines, the EPA projects [X] 
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GW of additional coal-fired generation may be uneconomic to 

maintain and may be removed from operation by 2030. 

 It is important to note that the EPA’s modeling does not 

necessarily account for all of the factors that may influence 

business decisions regarding future coal-fired capacity. By 

2025, the average age of the coal-fired fleet will be 49 years 

old and 20 percent of the fleet will be more than 60 years old 

if they remain in operation at that time. Many power companies 

already factor a potential financial liability associated with 

carbon emissions into their long term capacity planning that 

would further influence business decisions to replace these 

aging assets with modern, and significantly cleaner, generation. 

The compliance modeling done to support the final rule 

assumes that overall electric demand will decrease as states 

ramp up programs that result in lower overall demand. Demandside energy efficiency levels are expected to increase such that 

they achieve about an [X] 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 
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profitability of affected firms. The EPA recognizes that these 

guidelines provide significant flexibilities and states 

implementing the guidelines may choose to mitigate impacts to 

some markets outside the utility power sector. Similarly, demand 

for new generation or demand-side energy efficiency as a result 

of states implementing the guidelines can result in shifts in 

production and profitability for firms that supply those goods 

and services. 

Executive Order 13563 directs federal agencies to consider 

the effect of regulations on job creation and employment. 

According to the Executive Order, “our regulatory system must 

protect public health, welfare, safety, and our environment 

while promoting economic growth, innovation, competitiveness, 

and job creation. It must be based on the best available 

science.” (Executive Order 13563, 2011) Although standard 

benefit-cost analyses have not typically included a separate 

analysis of regulation-induced employment impacts, we typically 

conduct employment analyses. During the current economic 

recovery, 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 
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by the wide range of approaches that states may use. As such, 

the EPA’s employment analysis includes projected employment 

impacts associated with illustrative compliance scenarios for 

these guidelines for the electric power industry, coal and 

natural gas production, and demand-side energy efficiency 

activities. These projections are derived, in part, from a 

detailed model of the utility power sector used for this 

regulatory analysis, and U.S government data on employment and 

labor productivity. In the utility power, coal, and natural gas 

sectors, the EPA estimates that these guidelines could have an 

employment impact of roughly [X] job-years in [20XX], [X] jobyears in [20XX], and [X] job-years in [20XX]. Demand-side energy 

efficiency employment impacts are estimated at approximately an 

increase of [X] jobs in 2020, [X] jobs in 2025, and [X] jobs in 

2030. By its nature, demand-side energy efficiency reduces 

overall demand for electric power. The EPA recognizes as more 

efficiency is built into the U.S. power system over time, lower 

fuel requirements may lead to fewer jobs in the coal and natural 

gas extraction sectors, as well as in fossil-fuel fired EGU 

construction and operation than would otherwise have been 

expected. The EPA also recognizes the fact that, in many cases, 

employment gains and losses that might be attributable to this 

rule would be expected to affect different sets of people. 
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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. 

For this rulemaking, we were only able to quantify the climate 

benefits from reduced emissions of CO2 and the health co-benefits 
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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 to be $[X] to $[X] billion in 2020, $[X] to $[X] 

billion in 2025, and $[X] to $[X] 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 12 through 14 of this preamble. 

Table 12. 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 

CO2 

Reductions 

(million 

metric tons) 

 [X] [X] [X] 

 

5 percent (average 

SC-CO2) $[X] $[X] $[X] 

3 percent (average 

SC-CO2) $[X] $[X] $[X] 

2.5 percent 

(average SC-CO2) $[X] $[X] $[X] 

3 percent (95th

percentile SC-CO2) $[X] $[X] $[X] 

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 
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based on the global social cost of carbon (SC-CO2) estimates for 

the analysis years and are rounded to two significant figures. 

Table 13. Summary of the Monetized Health Co-Benefits in the 

U.S. for the Final Guidelines (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, 2020 

PM2.5 precursors b 

SO2 [X] $[X] to $[X] $[X] to $[X]

Directly emitted PM2.5 

(Elemental Carbon and 

Organic Carbon) 

[X] $[X] $[X] 

Directly emitted PM2.5 

(crustal) [X] $[X] $[X] 

NOX [X] $[X] to $[X] $[X] to $[X]

Ozone precursor c 

NOX (ozone season only) [X] $[X] to $[X] $[X] to $[X]

Total Monetized Health Co-benefits $[X] to $[X] $[X] to $[X]

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$[X] to $[X] $[X] to $[X]

Final Guidelines, 2025 

PM2.5 precursors b 

SO2 [X] $[X] to $[X] $[X] to $[X]

Directly emitted PM2.5 

(Elemental Carbon and 

Organic Carbon) 

[X] $[X] $[X] 

Directly emitted PM2.5 

(crustal) [X] $[X] $[X] 

NOX [X] $[X] to $[X] $[X] to $[X]
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Ozone precursor c 

NOX (ozone season only) [X] $[X] to $[X] $[X] to $[X]

Total Monetized Health Co-benefits $[X] to $[X] $[X] to $[X]

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$[X] to $[X] $[X] to $[X]

Final Guidelines, 2030 

PM2.5 precursors b

SO2 [X] $[X] to $[X] $[X] to $[X]

Directly emitted 

PM2.5 (Elemental Carbon 

and Organic Carbon) 

[X] $[X] $[X] 

Directly emitted 

PM2.5 (crustal) [X] $[X] $[X] 

NOX [X] $[X] to $[X] $[X] to $[X]

Ozone precursor c

NOX (ozone season 

only) [X] $[X] to $[X] $[X] To $[X]

Total Monetized Health Co-benefits $[X] to $[X] $[X] to $[X]

Total Monetized Health Co-benefits 

combined with Monetized Climate 

Benefits d

$[X] to $[X] $[X] to $[X]

a All estimates are rounded to two significant figures, so 

estimates may not sum. It is important to note that the 

monetized co-benefits do not include reduced health effects from 

direct exposure to SO2, direct exposure to NO2, exposure to 

mercury, ecosystem effects or visibility impairment. Air 

pollution health co-benefits are estimated using regional 

benefit-per-ton estimates for the contiguous U.S. 

b The monetized PM2.5 co-benefits reflect the human health 

benefits associated with reducing exposure to PM2.5 through 

reductions of PM2.5 precursors, such as SO2, NOX and directly 

emitted PM2.5. 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 
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chemical composition, are equally potent in causing premature 

mortality because the scientific evidence is not yet sufficient 

to allow differentiation of effect estimates by particle type. 

c The monetized ozone co-benefits reflect the human health 

benefits associated with reducing exposure to ozone through 

reductions of NOX during the ozone season. Ozone co-benefits are 

shown as a range reflecting the use of several different 

concentration-response functions, with the lower end of the 

range based on a function from Bell, et al. (2004) and the upper 

end based on a function from Levy, et al. (2005). Ozone cobenefits occur in the analysis year, so they are the same for 

all discount rates. 

d We estimate climate benefits associated with four different 

values of a one ton CO2 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent). Referred to as the social cost of carbon, each value 

increases over time. For the purposes of this table, we show the 

benefits associated with the model average at 3 percent discount 

rate, however we emphasize the importance and value of 

considering the full range of social cost of carbon values. We 

provide combined climate and health estimates based on 

additional discount rates in the RIA. 

The EPA has used the social cost of carbon (SC-CO2) 

estimates presented in the Technical Support Document: Technical 

Update of the Social Cost of Carbon for Regulatory Impact 

Analysis Under Executive Order 12866 (May 2013, Revised June 

2015) (“current TSD”) to analyze CO2 climate impacts of this 

rulemaking.779 We refer to these estimates, which were developed 

 

779 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, 
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by the U.S. government, as “SC-CO2 estimates.” The SC-CO2 is a 

metric that estimates the monetary value of impacts associated 

with marginal changes in CO2 emissions in a given year. It 

includes a wide range of anticipated climate impacts, such as 

net changes in agricultural productivity and human health, 

property damage from increased flood risk, and changes in energy 

system costs, such as reduced costs for heating and increased 

costs for air conditioning. It is typically used to assess the 

avoided damages as a result of regulatory actions (i.e., 

benefits of rulemakings that lead to an incremental reduction in 

cumulative global CO2 emissions). 

The SC-CO2 estimates used in this analysis were developed 

over many years, using the best science available, and with 

input from the public. Specifically, an interagency working 

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 

 

Office of Management and Budget, Office of Science and 

Technology Policy, and Department of Treasury (May 2013, Revised 

June 2015). Available at: http://[X].
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Support Document (2010 TSD)780 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).781 

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 

 

780 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.

781 The current version of the TSD is available at: http://[X], 

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 

June 2015). 
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supportive of the SC-CO2 and its application to this rulemaking. 

Commenters also provided constructive recommendations for 

potential opportunities to improve the SC-CO2 estimates in future 

updates. Many of these comments were similar to those that OMB’s 

Office of Information and Regulatory Affairs received in 

response to a separate request for public comment on the 

approach used to develop the estimates. After careful evaluation 

of the full range of comments submitted to OMB, the interagency 

working group continues to recommend the use of the SC-CO2

estimates in regulatory impact analysis. With the release of the 

response to comments, the interagency working group announced 

plans to obtain expert independent advice from the National 

Academy of Sciences’ National Research Council (NRC) to ensure 

that the SC-CO2 estimates continue to reflect the best available 

scientific and economic information on climate change. The NRC 

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 NRC process, OMB 
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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. 

The four SC-CO2 estimates are as follows: $13, $45, $66, and 

$130 per metric ton of CO2 emissions in the year 2020 (2011$).782

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 

 

782 The 2010 and 2013 TSDs present SC-CO2 in $2007. The estimates 

were adjusted to 2011$ using the GDP Implicit Price Deflator. 

Also available at: http://www.gpo.gov/fdsys/pkg/ECONI-2013-

02/pdf/ECONI-2013-02-Pg3.pdf. 
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intergenerational context (where costs and benefits are incurred 

by different generations). The fourth value is the 95th

percentile of the SC-CO2 from all three models at a 3 percent 

discount rate. It is included to represent higher-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 
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information about the social benefits of CO2 emission reductions 

to inform the benefit-cost analysis. As previously noted, the 

interagency working group plans to seek independent expert 

advice on technical opportunities to improve the SC-CO2 estimates 

from the NRC. The NRC 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 BenMAP783 to calculate 

average regional benefit-per-ton estimates using the health 

 

783 http://www.epa.gov/airquality/benmap/index.html
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impact assumptions used in the PM NAAQS RIA784 and Ozone NAAQS 

RIAs.785,786 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.787 All benefit-per-ton estimates reflect the 

geographic distribution of the modeled emissions for the 

proposed standards, which may not exactly match the emission 

 

784 U.S. Environmental Protection Agency (U.S. EPA). 2012. 

Regulatory Impact Analysis for the Final Revisions to the 

National Ambient Air Quality Standards for Particulate Matter. 

Research Triangle Park, NC: Office of Air Quality Planning and 

Standards, Health and Environmental Impacts Division. (EPA 

document number EPA-452/R-12-003, December). Available at: 

<http://www.epa.gov/pm/2012/finalria.pdf>. 

785 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>.

786 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>. 

787 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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reductions in this final rulemaking, and thus they may not 

reflect the local variability in population density, 

meteorology, exposure, baseline health incidence rates, or other 

local factors for any specific location. More information 

regarding the derivation of the benefit-per-ton estimates is 

available in the RIA. 

PM benefit-per-ton values are generated using two 

concentration-response functions, Krewski et al. (2009) and 

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. 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 
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on the American Cancer Society cohort study788 and one based on 

the extended Six Cities cohort study.789 We present the PM2.5 cobenefits 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)790 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 

 

788 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. 

789 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. 

790 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. 
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function from Bell et al. (2004)791 and the upper end based on a 

benefit-per-ton estimate using the function from Levy et al. 

(2005).792 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,793 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 

 

791 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. 

792 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. 

793 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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consistently finds that a no-threshold model most adequately 

portrays the PM-mortality concentration-response relationship. 

In general, we are more confident in the magnitude of the 

risks we estimate from simulated PM2.5 concentrations that 

coincide with the bulk of the observed PM concentrations in the 

epidemiological studies that are used to estimate the benefits. 

Likewise, we are less confident in the risk we estimate from 

simulated PM2.5 concentrations that fall below the bulk of the 

observed data in these studies. 

For this analysis, policy-specific air quality data are not 

available,794 and thus, we are unable to estimate the percentage 

of premature mortality associated with this specific rule. As a 

surrogate measure of mortality impacts, we provide the 

percentage of the population exposed above the lowest measured 

PM2.5 level (LML) in each of the studies from which we obtained 

concentration-response functions for PM2.5 mortality, using the 

estimates of baseline projected PM2.5 from the air quality 

modeling for the proposed guidelines used to calculate the 

benefit-per-ton estimates for the EGU sector. Using the Krewski 

et al. (2009) study, 88 percent of the population is exposed to 

annual mean PM2.5 levels at or above the LML of 5.8 micrograms 

 

794 In addition, site-specific emission reductions will depend 

upon how states implement the guidelines. 
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per cubic meter (μg/m3). Using the Lepeule et al. (2012) study, 

46 percent of the population is exposed above the LML of 8 μg/m3. 

It is important to note that baseline exposure is only one 

parameter in the health impact function, along with baseline 

incidence rates, population, and change in air quality. 

Every benefit analysis examining the potential effects of a 

change in environmental protection requirements is limited, to 

some extent, by data gaps, model capabilities (such as 

geographic coverage) and uncertainties in the underlying 

scientific and economic studies used to configure the benefit 

and cost models. Despite these uncertainties, we believe the air 

quality co-benefit analysis for this rule provides a reasonable 

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 
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assumptions. 

We note that the monetized co-benefits estimates shown here 

do not include several important benefit categories, including 

exposure to SO2, NOX, and hazardous air pollutants (e.g., mercury 

and hydrogen chloride), as well as ecosystem effects and 

visibility impairment. Although we do not have sufficient 

information or modeling available to provide monetized estimates 

for this rule, we include a qualitative assessment of these 

unquantified benefits in the RIA for the final standards. 

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 
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June 2015) (“current TSD”) to analyze CO2 climate impacts of 

this rulemaking. We refer to these estimates, which were 

developed by the U.S. government, as “SC-CO2 estimates.” The 

SC-CO2 is an estimate of the monetary value of impacts 

associated with a marginal change in CO2 emissions in a 

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. 

The EPA estimates that, in 2020, the final guidelines 

will yield monetized climate benefits (in 2011$) of 

approximately $[X] billion (3 percent model average). The 

air pollution health co-benefits in 2020 are estimated to 

be $[X] billion to $[X] billion (2011$) for a 3 percent 

discount rate and $[X] billion to $[X] billion (2011$) for 

a 7 percent discount rate. The annual, illustrative 

compliance costs estimated by IPM and inclusive of demandside energy efficiency program and participant costs and 

MRR costs, are approximately $[X] billion (2011$) in 2020. 

The quantified net benefits (the difference between 
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monetized benefits and compliance costs) in 2020 are 

estimated to range from $[X] billion to $[X] billion 

(2011$) using a 3 percent discount rate (model average). 

The EPA estimates that, in 2025, the final guidelines will 

yield monetized climate benefits (in 2011$) of approximately 

$[X] billion (3 percent model average). The air pollution health 

co-benefits in 2025 are estimated to be $[X] billion to $[X] 

billion (2011$) for a 3 percent discount rate and $[X] billion 

to $[X] billion (2011$) for a 7 percent discount rate. The 

annual, illustrative compliance costs estimated by IPM and 

inclusive of demand side energy efficiency program and 

participant costs and MRR costs, are approximately $[X] billion 

(2011$) in 2025. The quantified net benefits (the difference 

between monetized benefits and compliance costs) in 2025 are 

estimated to range from $[X] billion to $[X] billion (2011$) 

using a 3 percent discount rate (model average). 

The EPA estimates that, in 2030, the final guidelines will 

yield monetized climate benefits (in 2011$) of approximately 

$[X] billion (3 percent model average). The air pollution health 

co-benefits in 2030 are estimated to be $[X] billion to $[X] 

billion (2011$) for a 3 percent discount rate and $[X] billion 

to $[X] billion (2011$) for a 7 percent discount rate. The 

annual, illustrative compliance costs estimated by IPM and 
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inclusive of demand side energy efficiency program and 

participant costs and MRR costs, are approximately $[X] billion 

(2011$) in 2030. The quantified net benefits (the difference 

between monetized benefits and compliance costs) in 2030 are 

estimated to range from $[X] billion to $[X] billion (2011$) 

using a 3 percent discount rate (model average). 

Table 14. Summary of the Monetized Benefits, Compliance Costs, 

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

[Billions of 2011$] 

Final Guidelines, 2020 

 3% Discount Rate 7% Discount rate 

Climate benefits b $[X] 

Air pollution health 

co-benefits c $[X] to $[X] $[X] to $[X] 

Total Compliance 

Costs d $[X] $[X] 

Net Monetized 

Benefits e $[X] to $[X] $[X] to $[X] 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and 

SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

Final Guidelines, 2025 

 3% Discount rate 7% Discount rate 

Climate benefits b $[X] 

Air pollution health 

co-benefits c $[X] to $[X] $[X] to $[X] 
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Total Compliance 

Costs d $[X] $[X] 

Net Monetized 

Benefits e $[X] to $[X] $[X] to $[X] 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 and 

SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

Final Guidelines, 2030 

Climate benefits b $[X] 

Air pollution health 

co-benefits c $[X] to $[X] $[X] to $[X] 

Total Compliance 

Costs d $[X] $[X] 

Net Monetized 

Benefits e $[X] to $[X] $[X] to $[X] 

Non-monetized 

Benefits 

Non-monetized climate benefits 

Reductions in exposure to ambient NO2 

and SO2

Reductions in mercury deposition 

Ecosystem benefits associated with 

reductions in emissions of NOX, SO2, PM, 

and mercury 

Visibility impairment 

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. 
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c The air pollution health co-benefits reflect reduced exposure 

to PM2.5 and ozone associated with emission reductions of directly 

emitted PM2.5, SO2 and NOX. The range reflects the use of 

concentration-response functions from different epidemiology 

studies. The reduction in premature fatalities each year 

accounts for over 98 percent of total monetized co-benefits from 

PM2.5 and ozone. These models assume that all fine particles, 

regardless of their chemical composition, are equally potent in 

causing premature mortality because the scientific evidence is 

not yet sufficient to allow differentiation of effect estimates 

by particle type. 

d Total costs are approximated by the illustrative compliance 

costs estimated using the Integrated Planning Model for the 

final guidelines and a discount rate of approximately 5 percent. 

This estimate includes monitoring, recordkeeping, and reporting 

costs and demand-side energy efficiency program and participant 

costs. 

e The estimates of net benefits in this summary table are 

calculated using the global SC-CO2 at a 3 percent discount rate 

(model average). The RIA includes combined climate and health 

estimates based on additional discount rates. 

There are additional important benefits that the EPA 

could not monetize. Due to current data and modeling 

limitations, our estimates of the benefits from reducing CO2

emissions do not include important impacts like ocean 

acidification or potential tipping points in natural or 

managed ecosystems. Unquantified benefits also include 

climate benefits from reducing emissions of non-CO2

greenhouse gases (e.g., nitrous oxide and methane)795 and 

 

795 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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co-benefits from reducing direct exposure to SO2, NOx and 

hazardous air pollutants (e.g., mercury and hydrogen 

chloride), as well as from reducing ecosystem effects and 

visibility impairment. 

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, U.S. territories or areas of Indian 

country. The rule also does not impose specific requirements on 

tribal governments that have affected EGUs located in their area 

of Indian country. For areas of Indian country, the rule 

establishes CO2 emission performance goals that could be 

addressed through either tribal or federal plans. A tribe would 

have the opportunity under the TAR, but not the obligation, to 

apply to the EPA for 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 
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has requested or obtained TAS eligibility for purposes of a CAA 

section 111(d) plan. For areas of Indian country with affected 

EGUs where a tribe has not applied for TAS and submitted any 

needed plan, if the EPA determines that a CAA section 111(d) 

plan is necessary or appropriate, the EPA would have the 

responsibility to establish the plans. Because tribes are not 

required to implement section 111(d) plans and because no tribe 

has yet sought TAS eligibility for this purpose, this action is 

not anticipated to impose any information collection burden on 

tribal governments over the 3-year period covered by this ICR. 

This rule does impose specific requirements on state and 

U.S. territory governments with affected EGUs. The information 

collection requirements are based on the recordkeeping and 

reporting burden associated with developing, implementing, and 

enforcing a plan to limit CO2 emissions from existing sources in 

the utility power sector. These recordkeeping and reporting 

requirements are specifically authorized by CAA section 114 (42 

U.S.C. 7414). All information submitted to the EPA pursuant to 

the recordkeeping and reporting requirements for which a claim 

of confidentiality is made is safeguarded according to agency 

policies set forth in 40 CFR part 2, subpart B. 

The annual burden for this collection of information for 

the states (averaged over the first 3 years following 
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promulgation) is estimated to be a range of 529,000 to 859,000 

hours at a total annual labor cost of $37.4 to $60.8 

million. The lower bound estimate reflects the assumption that 

some states already have energy efficiency and renewable energy 

programs in place. The higher bound estimate reflects the 

overly-conservative assumption that no states have energy 

efficiency and renewable energy programs in place. 

The annual burden for this collection of information for 

the two affected U.S. territories, i.e., Puerto Rico and Guam, 

(averaged over the first 3 years following promulgation of this 

action) is estimated to be 23,700 to 38,200 hours at a total 

annual labor cost of $1.68 to $2.71 million. 

The total annual burden for the federal government 

associated with the state collection of information (averaged 

over the first 3 years following promulgation) is estimated to 

be 54,901 hours at a total annual labor cost of $3.04 million. 

The total annual burden for the federal government associated 

with the territorial collection of information (averaged over 

the first 3 years following promulgation) is estimated to be 

2,600 hours at a total annual labor cost of $145,000. Burden is 

defined at 5 CFR 1320.3(b). 

An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless it 
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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 

CAA section 111(d) do not impose any requirements on regulated 

entities and, thus, will not have a significant economic impact 

upon a substantial number of small entities. After emission 

guidelines are promulgated, states and U.S. territories 

establish emission standards on existing sources, and it is 

those requirements that could potentially impact small entities. 

Our analysis here is consistent with the analysis of the 

analogous situation arising when the EPA establishes NAAQS, 

which do not impose any requirements on regulated entities. As 

here, any impact of a NAAQS on small entities would only arise 

when states take subsequent action to maintain and/or 
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achieve the NAAQS through their state implementation plans. See 

American Trucking Assoc. v. EPA, 175 F.3d 1029, 1043-45 (D.C. 

Cir. 1999) (NAAQS do not have significant impacts upon small 

entities because NAAQS themselves impose no regulations upon 

small entities). 

Nevertheless, the EPA is aware that there is substantial 

interest in the rule among small entities and, as detailed in 

section III.A of the preamble to the proposed carbon pollution 

emission guidelines for existing EGUs (79 FR 34845-34847; June 

18, 2014) and in section II.D of the preamble to the proposed 

carbon pollution emission guidelines for existing EGUs in Indian 

Country and U.S. Territories (79 FR 65489; November 4, 2014), 

has conducted an unprecedented amount of stakeholder outreach. 

As part of that outreach, agency officials participated in many 

meetings with individual utilities and electric utility 

associations, as well as industry leaders and trade association 

representatives from various industries. While formulating the 

provisions of the rule, the EPA considered the input provided 

over the course of the stakeholder outreach as well as the input 

provided in the many public comments. 

D. Unfunded Mandates Reform Act (UMRA)

This action does not contain an unfunded mandate of $100 

million or more as described in UMRA, 2 U.S.C. 1531–1538, and does 
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not significantly or uniquely affect small governments. The 

emission guidelines do not impose any direct compliance 

requirements on EGUs located in states, U.S. territories or areas 

of Indian country. As explained in section XII.B above, the rule 

also does not impose specific requirements on tribal governments 

that have affected EGUs located in their area of Indian country. 

The rule does impose specific requirements on state and U.S. 

territory governments that have affected EGUs. Specifically, 

states and U.S. territories are required to develop plans to 

implement the guidelines under CAA section 111(d) for affected 

EGUs. The burden for states and U.S. territories to develop CAA 

section 111(d) plans in the 3-year period following promulgation 

of the rule was estimated and is listed in section XII.B above, 

but this burden is estimated to be below $100 million in any one 

year. Thus, this rule is not subject to the requirements of 

section 202 or section 205 of the UMRA. 

This rule is also not subject to the requirements of 

section 203 of UMRA because it contains no regulatory 

requirements that might significantly or uniquely affect small 

governments. Specifically, the state and U.S. territory 

governments to which rule requirements apply are not considered 

small governments. 
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In light of the interest among governmental entities, the 

EPA conducted outreach with national organizations representing 

state and local elected officials and U.S. territory and tribal 

governmental entities while formulating the provisions of this 

rule. Sections III.A and XI.F of the preamble to the proposed 

carbon pollution emission guidelines for existing EGUs (79 FR 

34845-34847; June 18, 2014) and sections II.D and VI.F of the 

preamble to the proposed carbon pollution emission guidelines 

for existing EGUs in areas of Indian Country and U.S. 

Territories (79 FR 65489; November 4, 2014) describes the 

extensive stakeholder outreach the EPA has conducted on setting 

emission guidelines for existing EGUs. The EPA considered the 

input provided over the course of the stakeholder outreach as 

well as the input provided in the many public comments when 

developing the provisions of these emission guidelines. 

E. Executive Order 13132: Federalism 

 The EPA has concluded that this action may have federalism 

implications, pursuant to agency policy for implementing the 

Order, because it imposes substantial direct compliance costs on 

state or local governments, and the federal government will not 

provide the funds necessary to pay those costs. As discussed in 

the Supporting Statement found in the docket for this 

rulemaking, the development of state plans will entail many 
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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, 

(7) International City/County Management Association, (8) 

National Association of Towns and Townships, (9) County 

Executives of America, and (10) Environmental Council of States. 
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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 

that comprise the best system of emission reduction (BSER), 

including the stringency of the building blocks, and the timing 
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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 

significant reliability implications. In this final rule, the 
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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). 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 states to 

consult with relevant ISOs/RTOs and/or planning/reliability 

authorities during plan development, and to document 

recommendations in their plans – and is providing the time for 

states to do so. Even with this foundation of flexibility in 

place, these final guidelines further provide states with the 

option of proposing amendments to approved plans in the event 

that unanticipated and significant reliability challenges arise. 

Commenters provided compelling information indicating that 

it will take longer than the agency initially anticipated to 

adjust investments and achieve interim CO2 reductions. 

Recognizing this, as well as the urgent need for actions to 
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reduce GHG emissions, the EPA is requiring states to frame an 

initial plan by August 31, 2016, and is allowing states two 

additional years to submit a final plan, if justified (to be 

submitted by August 31, 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 also expressed interest in the EPA 

ensuring that early actions to reduce CO2 are rewarded. In this 

final rule, states with currently existing programs and 

policies, and states that put in place new programs and policies 

early, will be better positioned to achieve the CO2 goals. 

Measures that a state takes prior to 2022, or programs already 
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in place by 2022, that result in CO2 emission reductions during 

the 2022-2029 period will contribute toward meeting both the 

interim and final CO2 emission performance rates. Thus, states 

with currently existing programs and policies, and states that 

put in place new programs and policies early, will be better 

positioned to achieve the goals. RE generating capacity and 

demand-side EE measures that are installed after 2012 will be 

eligible for use in adjusting a CO2 emission performance rate. 

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 EUGs. In addition, in response to concerns from 

states and power companies that the need for up-front interstate 

cooperation in developing mulit-state plans could inhibit the 

development of interstate programs that could lower cost, the 
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final rule provides additional options to allow individual EGUs 

to use creditable out-of-state reductions to achieve required CO2

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

The EPA is committed to working with states to provide support 

for tracking of emissions and allowances or credits, to help 

implement multi-state trading or averaging approaches. 

In their comments, many states identified the need for the 

EPA to provide guidance, including guidance on RE and EE 

emission measurement and verification (EM&V), and to maintain 

regular contact/forums with states throughout the implementation 

process. To provide state and local governments and other 

stakeholders with an understanding of the rule requirements, and 

to provide efficiencies where possible and reduce the cost and 

administrative burden, the EPA will continue outreach throughout 

the plan development and submittal process. Outreach will 

include opportunities for states to participate in briefings, 

teleconferences, and meetings about the final rule. The EPA’s 10 

regional offices will continue to be the entry point for states, 

tribes and territories to ask technical and policy questions. 

The agency will host (or partner with appropriate groups to cohost) 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 
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inform the training and other tools that will be of most use to 

the states, tribes, and territories that are implementing the 

final rule. The EPA expects to issue guidance on specific 

topics, including evaluation, measurement and verification 

(EM&V) for RE and demand-side EE, state-community engagement, 

and resources and financial assistance for RE and demand-side 

EE. As guidance documents, tools, templates and other resources 

become available, the EPA, in consultation with the U.S. 

Department of Energy and other federal agencies, will continue 

to make these resources available via a dedicated website. 

A list of the state and local government commenters has 

been provided to OMB and has been placed in the docket for this 

rulemaking. In addition, the detailed response to comments from 

these entities is contained in the EPA’s response to comments 

document on this final rulemaking, which has also been placed in 

the docket for this rulemaking. 

 As required by section 8(a) of Executive Order 13132, the 

EPA included a certification from its Federalism Official 

stating that the EPA had met the Executive Order’s requirements 

in a meaningful and timely manner when it sent the draft of this 

final action to OMB for review pursuant to Executive Order 

12866. A copy of the certification is included in the public 

version of the official record for this final action. 
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F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments 

This action has tribal implications. However, it will 

neither impose substantial direct compliance costs on federally 

recognized tribal governments, nor preempt tribal law. Tribes 

are not required to develop or adopt CAA programs, but they may 

apply to the EPA for treatment in a manner similar to states 

(TAS) and, if approved, do so. As a result, tribes are not 

required to develop plans to implement the guidelines under CAA 

section 111(d) for affected EGUs in their areas of Indian 

country. To the extent that a tribal government seeks and 

attains TAS status for that purpose, these emission guidelines 

would require that planning requirements be met and emission 

management implementation plans be executed by the tribes. The 

EPA notes that this rule does not directly impose specific 

requirements on affected EGUs, including those located in areas 

of Indian country, but provides guidance to any tribe approved 

by the EPA to address CO2 emissions from EGUs subject to section 

111(d) of the CAA. The EPA also notes that none of the affected 

EGUs are owned or operated by tribal governments. 

 As described in sections III.A and XI.F of the preamble to 

the proposed carbon pollution emission guidelines for existing 

EGUs (79 FR 34845-34847; June 18, 2014) and sections II.D and 
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VI.F of the preamble to the proposed carbon pollution emission 

guidelines for existing EGUs in Indian Country and U.S. 

Territories (79 FR 65489; November 4, 2014), the rule was 

developed after extensive and vigorous outreach to tribal 

governments. These tribes expressed varied points of view. Some 

tribes raised concerns about the impacts of the regulations on 

EGUs located in their areas of Indian country and the subsequent 

impact on jobs and revenue for their tribes. Other tribes 

expressed concern about the impact the regulations would have on 

the cost of water covered under treaty to their communities as a 

result of increased costs to the EGU that provide energy to 

transport the water to the tribes. Other tribes raised concerns 

about the impacts of climate change on their communities, 

resources, ways of life and hunting and treaty rights. The 

tribes were also interested in the scope of the guidelines being 

considered by the agency (e.g., over what time period, 

relationship to state and multi-state plans) and how tribes will 

participate in these planning activities. 

The EPA consulted with tribal officials under the EPA 

Policy on Consultation and Coordination with Indian Tribes early 

in the process of developing this action to permit them to have 

meaningful and timely input into its development. A summary of 

that consultation follows. 
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Prior to issuing the supplemental proposal on November 4, 

2014, the EPA consulted with tribes as follows. The EPA held a 

consultation with the Ute Tribe, the Crow Nation, and the 

Mandan, Hidatsa, Arikara (MHA) Nation on July 18, 2014. On 

August 22, 2014, the EPA held a consultation with the Fort 

Mojave Tribe. On September 15, 2014, the EPA held a consultation 

with the Navajo Nation. The Navajo Nation sent a letter to the 

EPA on September 18, 2014, summarizing the information presented 

at the consultation and the Navajo Nation’s position on the 

supplemental proposal. One issue raised by tribal officials was 

the potential impacts of the June 18, 2014 proposal and the 

supplemental proposal on tribes with budgets that are dependent 

on revenue from coal mines and power plants, as well as 

employment at the mines and power plants. The tribes noted the 

high unemployment rates and lack of access to basic services on 

their lands. Tribal officials also asked whether the rules will 

have any impact on a tribe’s ability to seek TAS. Tribal 

officials also expressed interest in agency actions with regard 

to facilitating power plant compliance with regulatory 

requirements. The Navajo Nation made the following 

recommendations in their letter of September 18, 2014: the 

Navajo Nation supports a mass-based CO2 emission standard based 

on the highest historical CO2 emissions since 1996; the Navajo 
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Nation requests that the EPA grant the Navajo Nation carbon 

credits and that the Navajo Nation retains ownership and control 

of such credits; building block 2 is not appropriate for the 

Navajo Nation because there are no NGCC plants located on the 

Navajo Nation; building block 3 is not appropriate for the 

Navajo Nation because the Navajo people already receive 

virtually all of their electricity from carbon-free sources 

(mostly hydroelectric power) and their use of electricity is 

negligible compared to the generation at the power plants; 

building block 4 is not appropriate for the Navajo Nation 

because of the inadequate access to electricity, and the goal 

should allow for an increase in energy consumption on the Navajo 

Nation; the supplemental proposal should consider the useful 

life of the power plants located on the Navajo Nation; and the 

supplemental proposal should clarify that RE projects located 

within the Navajo Nation that provide electricity outside the 

Navajo Nation should be counted toward meeting the relevant 

state’s RE goals under the Clean Power Plan. 

After issuing the supplemental proposal, the EPA held 

additional consultation with tribes. On November 18, 2014, the 

EPA held consultations with the following tribes: Fort McDowell 

Yavapai Nation, Fort Mojave Tribe, Hopi Tribe, Navajo Nation, 

and Ak-Chin Indian Community. A consultation with the Ute Indian 
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Tribe of the Uintah and Ouray Reservation was held on December 

16, 2014 and with the Gila River Indian Community on January 15, 

2015. The Navajo Nation reiterated the concerns raised during 

the previous consultation. Several tribes also again indicated 

that they wanted to ensure they would be included in the 

development of any tribal or federal plans for areas of Indian 

country. The Fort Mojave Tribe and the Navajo Nation expressed 

concern with using data from 2012 as the basis for the goal for 

their areas of Indian country; in their view, that year was not 

representative for the affected EGU. On April 28, 2015, the EPA 

held an additional consultation with the Navajo Nation. The 

issues raised by the Navajo Nation during the consultation 

included whether the EPA has the authority to set less stringent 

standards on a case-by-case basis, and a suggested “parity glide 

path” that would account and adjust for the very low electricity 

usage by the Navajo Nation and promote Navajo Nation economic 

growth and demand. 

As required by section 7(a), the EPA’s Tribal Consultation 

Official has certified that the requirements of the executive 

order have been met in a meaningful and timely manner. A copy of 

the certification is included in the docket for this action. 

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks 
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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 greenhouse gas that contributes to climate 

change and is emitted in significant quantities by fossil fuelfired power plants. The EPA believes that the CO2 emission 

reductions resulting from implementation of these final 

guidelines, as well as substantial ozone and PM2.5 emission 

reductions as a co-benefit, will further improve children’s 

health. 

The assessment literature cited in the EPA’s 2009 

Endangerment Finding concluded that certain populations and 

lifestages, including children, the elderly, and the poor, are 

most vulnerable to climate-related health effects. The 

assessment literature since 2009 strengthens these conclusions 

by providing more detailed findings regarding these groups’ 

vulnerabilities and the projected impacts they may experience. 
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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 [X] 

to [X] percent change in retail electricity prices on average 

across the contiguous U.S. in [20XX], and a [X] to [X] percent 
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reduction in coal-fired electricity generation as a result of 

this rule. The EPA projects that utility power sector delivered 

natural gas prices will increase/decrease by about [X] to [X] 

percent in [20XX]. 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 

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, 
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implementation, and enforcement of environmental laws, 

regulations, and policies. The EPA has this goal for all 

communities and persons across this Nation. It will be achieved 

when everyone enjoys the same degree of protection from 

environmental and health hazards and equal access to the 

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).796 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 

 

796 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases Under Section 202(a) of the Clean Air Act,” 74 Fed. Reg. 

66,496 (Dec. 15, 2009) (“Endangerment Finding”). 
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resources. See sections XII.F and XII.G, above, where the EPA 

discusses Consultation and Coordination with Tribal Governments 

and Protection of Children. The Administrator placed weight on 

the fact that certain groups, including children, the elderly, 

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 
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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 

Alaskan communities are already experiencing disruptive impacts, 

including coastal erosion and shifts in the range or abundance 

of wild species crucial to their livelihoods and well-being. 

The most recent assessments continue to strengthen 

scientific understanding of climate change risks to minority 

populations and low-income populations in the United States.797

The new assessment literature provides more detailed findings 

 

797 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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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 may be uniquely vulnerable to climate 

change health impacts in the United States. These reports find 

that certain climate change related impacts—including heat 

waves, degraded air quality, and extreme weather events—have 

disproportionate effects on low-income populations and some 

communities of color, raising environmental justice concerns. 

Existing health disparities and other inequities in these 

communities increase their vulnerability to the health effects 

of climate change. In addition, assessment reports also find 

that climate change poses particular threats to health, wellbeing, and ways of life of indigenous peoples in the United 

States. 

As the scientific literature presented above and as the 

2009 Endangerment Finding illustrates, low income populations 

and some communities of color are especially vulnerable to the 

health and other adverse impacts of climate change. The EPA 

believes that communities will benefit from this final 

rulemaking because this action directly addresses the impacts of 

climate change by limiting GHG emissions through the 
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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 

energy efficiency and renewable energy. These emission 

reductions will include SO2 and NOx, which form ambient PM2.5 and 

ozone in the atmosphere, and hazardous air pollutants (HAP), 

such as mercury and hydrochloric acid. In the final rule 

revising the annual PM2.5 NAAQS,798 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 risk to PM-related and ozone-related 

effects.799 Therefore, in areas where this rulemaking reduces 

exposure to PM2.5, ozone, and methylmercury, low-income 

populations will also benefit from such emissions reductions. 

 

798 “National Ambient Air Quality Standards for Particulate 

Matter, Final Rule,” 78 FR 3086 (Jan. 15, 2013). 

799 U.S. Environmental Protection Agency (U.S. EPA). 2009. 

Integrated Science Assessment for Particulate Matter (Final 

Report). EPA-600-R-08-139F. National Center for Environmental 

Assessment – RTP Division. December. Available on the Internet 

at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.
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The 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 considerations 

section IX of this preamble, the EPA has put a number of 

conditions in place to help ensure that this action will not 

have potential disproportionately high and adverse human health 

or environmental effects on all communities (low income, 

communities of color). As described in the community 

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. 

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 

(42 U.S.C. 7411, 7601, 7602, 7607(d)(1)(C)). This action is also 

subject to section 307(d) of the CAA (42 U.S.C. 7607(d)).
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Carbon Pollution 

Emission Guidelines for Existing Stationary Sources: Electric 

Utility Generating Units 

Page 1181 of 1275

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 What 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? 

State and Multi-state Plan Requirements 

60.5740 What must I include in my 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? 

60.5755 Can I include existing requirements, programs, and 

measures in my plan? 

60.5760 What are the timing requirements for submitting my 

plan? 
Page 1184 of 1275

60.5765 What must I include in an initial plan submittal in 

lieu of 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 include 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 

60.5791 What Emission Rate Credits qualify for use in my state 

plan? 

60.5792 How can an affected EGU use an ERC for demonstrating 

compliance? 

60.5793 What is a qualified state ERC tracking system? 

60.5795 What are the requirements for EM&V plans? 

60.5796 What are the requirements for a post-project ERC 

verification assurance plan? 

60.5797 What standards must the independent third party 

verifier meet? 

Applicability of Plans to Affected EGUs

60.5800 Does this subpart directly affect EGU owners and 

operators in my state? 

60.5805 What affected EGUs must I address in my state plan? 

60.5810 What affected EGUs are exempt from my state plan? 

60.5815 What are the CO2 emission performance rates for 

affected EGUs? 

60.5820 What applicable monitoring, recordkeeping, and 

reporting requirements do I need to include in my 

state plan for affected EGUs? 

Recordkeeping and Reporting Requirements 

60.5825 What are my state recordkeeping requirements? 

60.5830 What are my state reporting requirements? 

60.5835 How do I submit information required by these Emission 

Guidelines to the EPA? 

Definitions 

60.5840 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) 
Page 1185 of 1275

Table 3 to Subpart UUUU of Part 60—Statewide Mass-based CO2

Emission Goals (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 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. 

§ 60.5705 What pollutants are regulated by this subpart? 

 (a) The pollutants regulated by this subpart are greenhouse 

gases. 

(b) The greenhouse gas regulated by this subpart is carbon 

dioxide (CO2). 

§ 60.5710 Am I affected by this subpart? 
Page 1186 of 1275

 If you are the Governor of a state 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. You must submit a 

negative declaration letter in place of the state plan if there 

are no affected EGUs for which construction commenced on or 

before January 8, 2014 in your state. 

§ 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 twelve months 

after the date the final plan or plan revision (as allowed under 

§ 60.5795) is submitted, to approve or disapprove such plan or 

revision or each portion thereof. If you submit an initial plan 

submittal under § 60.5765(a) in lieu of a final plan submittal 

the EPA will follow the procedure in § 60.5765(b). 

§ 60.5720 What if I do not submit a plan or my plan is not 

approvable? 

(a) If you do not submit an approvable plan the EPA will 

develop a Federal plan for your 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 
Page 1187 of 1275

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 prior to the beginning of the interim 

period on January 1, 2022. If a federal plan is in place during 

the interim period or final period and a state submits and EPA 

approves a plan, the federal plan will not be withdrawn until 

the end of the performance period that is at that time in place 

(e.g., at the end of an interim step so that the state plan goes 

into effect at the beginning of a new interim step). 

§ 60.5725 In lieu of a state plan submittal, are there other 

acceptable option(s) for a state to meet its CAA section 111(d) 

obligations? 

 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, 
Page 1188 of 1275

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 

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 paragraph (a) of this 

section. 

(a) Approval of alternatives, not already approved by this 

subpart, to the CO2 emissions performance rates in Table 1 to 

this subpart established under § 60.5815. 

(b) Approval of alternatives, not already approved by this 

subpart, to the CO2 emissions goals in Tables 2 and 3 to this 

subpart established under § 60.5815. 

§ 60.5736 Will the EPA impose any sanctions? 

The EPA will not exercise any authority it may have to 

impose sanctions under the Clean Air Act, 42 U.S.C. §§ 7410(m), 

7509, on states for failing to submit, implement, or enforce any 

requirements under this subpart. 

State and Multi-state Plan Requirements 

§ 60.5740 What must my state or multi state plan include? 
Page 1189 of 1275

(a) You must include the components described in paragraphs 

(a)(1) through (10) of this section in your plan submittal. 

These components of your plan submittal will be codified as part 

of the federally enforceable plan upon approval by EPA. The 

final plan submittal must meet the requirements and include the 

information required under § 60.5745. 

(1) 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 § 60.5805. 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) You must include an identification of all emission 

standards for each affected EGU, compliance periods for each 

emission standard according to § 60.5770, and a demonstration 

that the emission standards are, when taken together, 

sufficiently protective to meet the applicable CO2 emission 

performance rates described in § 60.5815. 

(i) If your plan includes only requirements of emission 

standards on your affected EGUs to meet either the CO2 emission 

performance rates or CO2 emission goals, you must include in your 

plan the requirement for corrective measures to be put in place 

if there is an exceedance of an interim step or final period CO2

emission performance rate or CO2 emission goal by 10 percent or 
Page 1190 of 1275

greater, either on average or cumulatively as applicable. These 

corrective measures must ensure that the interim period and 

final period CO2 emission performance rates or CO2 emission goals 

are achieved by your affected EGUs. 

(ii) If your plan includes state measures, in addition to 

or in lieu of emission standards, then the final state plan must 

include the information in paragraph (a)(3) and the submittal 

must include the information listed in § 60.5745(a)(6). 

(3) If your plan includes state measures, you must submit a 

federally enforceable backstop that identifies emission 

standards for affected EGUs that will be put into place if there 

is an exceedance of 10 percent or greater of any interim step 

goal or final goal period. The emission standards in the 

backstop must be able to meet either the CO2 emission performance 

rates or CO2 emission goal required by your plan for both the 

interim period and final periods, as well as any shortfall 

identified from the prior compliance period. The backstop must 

also address the following: 

(i) You must include a trigger for the backstop to go into 

effect upon either a failure to meet a programmatic milestone or 

an exceedance of 10 percent or greater of any interim step goal 

or final goal period. You may include in your plan any 

additional triggers so long as they do not affect the stringency 

of the two triggers required under this paragraph. 
Page 1191 of 1275

(ii) You must include a schedule for implementation of the 

backstop once triggered, and you must identify all necessary 

state administrative and technical procedures for implementing 

the backstop. 

 (4) Identification of applicable monitoring, reporting, 

and recordkeeping requirements for each affected EGU. These 

requirements must be consistent with or no less stringent than 

the requirements specified in § 60.5820.

(5) Description of the process, contents, and schedule for 

state reporting to the EPA about plan implementation and 

progress including information required under § 60.5830. 

(6) A requirement for a report to be submitted by July 1, 

2021, that demonstrates that the state has met the programmatic 

milestone steps that the state indicated it would take from the 

submittal of the final plan through the end of 2020, and that 

the state is on track to implement the plan as of January 1, 

2022. 

(b) You must follow the requirements of subpart B of this 

part (Adoption and Submittal of state plans for Designated 

Facilities) and demonstrate that they were met in your 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 
Page 1192 of 1275

information in paragraphs (a)(1) through (10) of this section. 

This information must be submitted to the EPA 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 emission goals that your affected EGUs will 

achieve through the implementation of your plan. If the 

geography scope of your plan is a single-state then you must 

include CO2 emission performance rates or emission goals 

according to § 60.5815. If your plan includes multiple states 

and you elect to set CO2 emission performance goals, you must 

include CO2 emission goals calculated according to § 60.5750. 

(i) You must specify in the plan the CO2 emission 

performance rates or emission goals that affected EGUs will meet 

for the interim period, interim steps 1, 2 and 3 and final 

period described in § 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 § 60.5815. 
Page 1193 of 1275

(4) You must include a demonstration that each affected 

EGU’s emission standard is quantifiable, non-duplicative, 

permanent, verifiable, and enforceable according to section 

60.5775. 

(5) If your plan includes only emission standards on your 

affected EGUs to meet either the CO2 emission performance rates 

or CO2 emision goals you must include in your plan submittal the 

information in paragraphs (a)(5)(i) through (iii) as applicable. 

(i) If the emission standards in your plan applies separate 

rate-based CO2 emission standards for affected EGUs (in lbs 

CO2/MWh) that are equal to or lower than the CO2 emission 

performance rates listed in table 1 then no additional 

demonstration is required beyond inclusion of the emission 

standards in the plan. Under this approach, compliance by 

affected EGUs with the emission standards will ensure that the 

CO2 emission performance rates or the state rate-based CO2

emission goal is achieved. 

(ii) If a plan applies rate-based emission standards to 

individual affected EGUs at a lb 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 
Page 1194 of 1275

demonstrate through a projection that the weighted average CO2

emission rate of affected EGUs, when weighted by generation (in 

MWh), will be equal to or less than the CO2 emission performance 

rates or the rate-based CO2 emission goal. This projection must 

address both the interim period (including interim step periods 

1-3, for 2022-2024, 2025-2027, and 2028-2029), and the final 

period (2030-2031, and subsequent two-year periods). The 

projection in the plan submittal must include the following: 

(A) A summary of each affected EGU’s anticipated future 

operation characteristics, including annual generation, CO2

emissions, capacity and capacity factors; 

(B) Planned affected EGU retirements; 

(C) Anticipated use of ERCs to adjust the reported CO2 

emission rate of affected EGUs, including but not limited to, 

anticipated use (in MWh) by technology-type (e.g., wind, solar, 

demand-side EE), the physical location of the resources 

providing ERCs, and any other relevant information (e.g., power 

purchase agreements (PPAs) and other long-term power contracts); 

and an explanation, with calculation, of how these measures are 

being used in the projection to adjust the CO2 emission rate of 

affected EGUs; 

(D) Expected electricity demand growth at the state or 

regional level, including the source and basis for these 

estimates; 
Page 1195 of 1275

(E) Expected fuel switching at affected EGUs; 

(F) Heat rate improvements at affected EGUs; and 

(G) Any other applicable assumptions used in the 

projection. 

(iii) If a plan applies mass-based emission standards to 

individual affected EGUs 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 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 table 3 of this subpart. 

Compliance periods for affected EGUs must aligned with each of 

the interim steps and final plan periods. 

(6) If your plan includes state measures, in addition to or 

in lieu of the emission standards required by paragraph (a)(2) 

of § 60.5740, the final state plan submittal must include the 

information under paragraphs (a)(6)(i) through (vi): 

(i) You must include a description of all the state 

measures the state will rely upon to achieve the applicable CO2

emission performance rates or CO2 emission goal, the applicable 

state laws or regulations related to such measures, and 

identification of parties or entities implementing such state 

measures. 
Page 1196 of 1275

(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 renewable energy (RE) or demandside energy efficiency (EE) programs and projects you must also 

demonstrate the minimum emission, monitoring and verification 

(EM&V) requirements listed under § 60.5795 that apply to those 

programs and projects. 

(iii) You must demonstrate that the federally enforceable 

emission standards for affected EGUs, if included, and state 

measures, are sufficient to attain the CO2 emission performance 

rates or CO2 emission goal for the interim period of 2022-2029 

and the final period of 2030 and beyond. This includes the 

interim period of 2022-2029, including interim step 1 2022-2024 

period, interim step 2 2025-2027 period, and interim step 3 

2028-2029 period (or alternative CO2 emission performance step 

levels adopted by the state, provided they result in achievement 

of the CO2 emission performance rates or state CO2 emission goal 

during the 2022-2029 interim period), as well as the final 

period of 2030 and beyond. Your demonstration must use 

technically sound quantification methods that are reliable and 

replicable. The demonstration must be supported by the methods 

and measurement procedures by which the federally enforceable CO2

emission standards for affected EGUs are reliably measured, if 
Page 1197 of 1275

these standards are incorporated into the state measures state 

plan. 

(iv) You must include a CO2 performance projection of your 

state measure 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 and final 

periods: 

(A) A baseline demand and supply forecast as well as the 

underlying assumptions and data sources of each forecast; 

(B) The magnitude of energy and emission impacts from all 

measures included in the plan and applicable assumptions; 

(C) An explanation of the tools and emission quantification 

approaches used in the projection; and 

(D) Underlying emission quantification assumptions. 

(v) If the state measures in your plan submittal are 

designed to meet either a CO2 emission performance rate or ratebased CO2 emission goal, MWh from state measures may be used to 

adjust the denominator of the CO2 emission rate of affected EGUs 

when demonstrating achievement of the CO2 emission performance 

rates or the rate-based CO2 emission goal. In this case your plan 

submittal must include the following information, at a minimum, 

to demonstrate state measures will require affected EGUs to meet 

the CO2 emission performance rates or the rate-based CO2 emission 

goal: 
Page 1198 of 1275

(A) A summary of each affected EGU’s anticipated future 

operation characteristics, including annual generation, CO2

emissions, capacity and capacity factors; 

(B) Planned retirements; 

(C) A detailed description of the zero CO2 emitting demandside energy efficiency (EE) savings and renewable energy (RE) 

generation (and any other qualifying MWh) from state measures 

that will be available for use in adjusting the reported CO2

emission rates of affected EGUs, including, but not limited to, 

the amount of generation or savings by technology-type (e.g., 

wind, solar, EE), the physical location of the measures or 

generation, and any other relevant information (e.g., power 

purchase agreements (PPAs) and other long-term power contracts); 

and an explanation, with calculation, of how these measures are 

being used in the projection to adjust the CO2 emission rate of 

affected EGUs; 

(D) Expected electricity demand growth at the state or 

regional level, including the source and basis for these 

estimates; 

(E) Expected fuel switching at affected EGUs; 

(F) Heat rate improvements at affected EGUs; and 

(G) Any other applicable assumptions used in the 

projection. 
Page 1199 of 1275

(vi) If the state measures in your plan submittal are 

designed to meet mass-based CO2 emission goals, a state must 

demonstrate that the combined state-enforceable measures, along 

with any federally enforceable CO2 emission standards for 

affected EGUs, if included, will achieve the state mass-based CO2

emission goal. You must demonstrate and document how the 

combined state measures are impacting CO2 emissions at affected 

EGUs so that the sum of emissions at all affected EGUs will be 

lower than or achieve the state’s CO2 emission goal for each of 

the interim steps and final period. 

(7) Your plan must demonstrate any regional information 

considered in developing the assumptions. Multi-state plans or 

plans sharing common elements should use regional assumptions or 

demonstrate reconciliation of any inconsistencies between statelevel assumptions. 

(8) Your plan submittal must include a demonstration that 

the reliability of the electrical grid has been thoroughly 

considered. 

(9) 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. 

(10) Supporting material for your plan including: 
Page 1200 of 1275

(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 

under the plan, according to paragraph (a)(3) of this section; 

(iii) Materials supporting any calculations for CO2 emission 

goals calculated according to § 60.5815, if applicable; and 

(iv) Materials necessary to support evaluation of the plan 

by the EPA. 

(v) Materials supporting each hearing held including the 

list of witnesses and their organizational affiliations, if any, 

appearing at the hearing, and a brief written summary of each 

presentation or written submission pursuant to the requirements 

of 40 CFR 60.23(f) 

 (b) You must submit your final plan according to § 

60.5835. 

§ 60.5750 Can I work with other states to develop a multi-state 

plan? 

 A multi-state plan may be submitted on behalf of multiple 

states, provided it is formally signed by the Governor or the 

Governor’s designee for each of the states participating in the 

multi-state plan. In this instance, the joint submittal will 

have the same legal effect as an individual submittal for each 
Page 1201 of 1275

participating state. A multi-state plan must include all the 

required elements for a plan specified in § 60.5740(a). A multistate 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 states participating in the multi-state plan will 

meet the CO2 emission performance rates listed in table 1 or an 

equivalent CO2 emission goal according to paragraphs (a)(1) or 

(2) of this section. 

(1) For states electing to demonstrate performance with a 

CO2 emission rate-based goal, the CO2 emission goals identified 

in the plan according to § 60.5815 will be a weighted (by net 

energy output) average lb 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 § 60.5815 will be total CO2

emissions by all affected EGUs in the multi-state area during 

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 
Page 1202 of 1275

states. The joint submittal must be signed by authorized 

officials for each of the states participating in the multistate plan. 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. 

(2) States participating in a multi-state plan may submit a 

single plan submittal, signed by authorized officials from each 

participating state, that addresses common plan elements and 

each individual participating states must, in addition, provide 

individual plan submittals that provide state-specific elements 

of the multi-state 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 

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. 

§ 60.5755 Can I include existing requirements, programs, and 

measures in my plan? 
Page 1203 of 1275

 (a) Yes, existing state programs, requirements, and 

measures, meeting the requirements in paragraph (b) of this 

section may qualify for use in projecting and demonstrating that 

a plan achieves the CO2 emission performance rates or emission 

goals specified in a plan, according to § 60.5815. 

 (b) Emission impacts of existing programs, requirements, 

and measures that occur during a plan performance period must 

meet the following requirements to qualify for use in projecting 

and demonstrating that a plan achieves the CO2 emission 

performance rates or emission goals specified in a plan, 

according to § 60.5815: 

 (1) Actions taken pursuant to an existing state program, 

requirement, or measure, such as compliance with a regulatory 

obligation or initiation of an action related to a program or 

measure, must occur after December 31, 2012; and 

(2) The existing state program, requirement, or measure, 

and any related actions taken pursuant to such program, 

requirement, or measure, meet the applicable requirements 

pursuant to § 60.5740(a), § 60.5780 and § 60.5785. 

§ 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 August 31, 2016 unless you are 

submitting an initial plan submittal, allowed under § 60.5765, 
Page 1204 of 1275

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 plan submittal by August 31, 2016 to receive an 

extension to submit your final state plan submittal by August 

31, 2018. 

(c) You must submit all information required under 

paragraphs (a) and (b) of this section according to the 

electronic reporting requirements in § 60.5835. 

§ 60.5765 What must I include in an initial plan submittal if 

requesting an extension for a final state plan submittal? 

(a) You must include the following required elements in an 

initial plan submittal if requesting an extension for a final 

plan submittal: 

(1) A description of the plan approach and progress made to 

date in developing each of the plan elements in § 60.5740; 

(2) An initial projection of the level of emission 

performance that will be achieved under the final plan; 

(3) A commitment by the state or states to maintain 

existing state measures that limit or avoid CO2 emissions from 

affected EGUs (e.g., renewable energy standards, unit-specific 

limits on operation or fuel utilization); 
Page 1205 of 1275

(4) Justification of why additional time is needed to 

submit a final plan (e.g., a state’s required schedule for 

legislative approval and administrative rulemaking, the need for 

multi-state coordination in the development of an individual 

state plan, or the process and coordination necessary to develop 

a multi-state plan); 

(5) A comprehensive roadmap describing in detail the action 

you intend to take to submit all required elements of a final 

plan submittal as specified in § 60.5740 by no later than August 

31, 2017, including process, analytical methods and schedule 

(including milestones) specifying when all necessary plan 

components will be complete (e.g., projection of emission 

performance; implementing legislation, regulations and 

agreements; necessary approvals); 

(6) Identification of existing and future programs, 

requirements, and measures the state or states intend to include 

in the plan and supporting materials as appropriate; 

(7) If a multi-state plan is being developed, an executed 

agreement(s) with other states (e.g., memorandum of 

understanding) participating in the development of the multistate plan; 

(8) A description of all steps the state or states have 

already taken in furtherance of actions needed to finalize a 

final plan submittal; and 
Page 1206 of 1275

(10) Evidence of an opportunity for public comment and a 

response to any significant comments received on issues relating 

to the approvability of the initial plan. 

(b) You must submit an initial plan submittal allowed in 

paragraph (a) of this section, information required under 

paragraph (c) of this section (only if a state elects to submit 

an initial submittal to request an extension for a final plan 

submittal), and a final state plan submittal according to § 

60.5830. If a state submits an initial plan 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 plan submittal that the EPA finds the 

initial plan submittal does not meet the requirements listed in 

paragraph (a) of this section. 

(c) If an extension for submission of a final plan has been 

granted, you must submit a progress report by August 31, 2017. 

The 2017 report must include the following: 

(1) A summary of the status of each component of the final 

plan, including an update from the 2016 initial plan submittal 

and a list of which components are not complete. 

(2) 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. 
Page 1207 of 1275

(3) 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. 

(d) If you do not submit an acceptable update by August 31, 

2017, you will have failed to meet the conditions for the 2-year 

extension and EPA will develop a federal plan unless you submit 

a final plan during this time. 

§ 60.5770 What schedules, performance periods, and compliance 

periods must I include in my state plan? 

(a) You must meet the emission reduction requirements for 

the affected EGUs for the interim period, interim steps 1, 2 and 

3 and final period according to paragraph (b) of this section. 

You must also include in your plan schedules of compliance for 

each affected EGU regulated under the plan according to 

paragraphs (c) and (d) of this section. 

(b) Your plan must achieve each state emission performance 

rate required under § 60.5815 over its applicable time periods 

according to paragraphs (b)(1) through (3) of this section: 

(1) The interim period must cover the eight calendar years 

2022-2029 starting January 1, 2022 and ending December 31, 2029. 

(2) The interim steps are increments of plan performance 

within the interim period. Interim step 1 must cover the three 

calendar years 2022-2024, interim step 2 must cover the three 
Page 1208 of 1275

calendar years 2025-2027 and interim step 3 must cover the two 

calendar years 2028-2029. 

(3) The final period must cover the years 2030 and 

thereafter and with increments of plan performance for every two 

calendar years (i.e., 2030-2031, 2032-2033, 2034-2035, etc.). 

(c) If your state adopts emission standards for affected 

EGUs regulated under the plan, the emission standards for 

affected EGUs must include the following compliance periods for 

the emission standards: 

(1) For the interim period, affected EGUs must have 

emission standards that have schedules of compliance for each 

interim step 1, 2 and 3 for the calendar years January 1, 2022 

to December 31, 2024, January 1, 2025 to December 31, 2027, and 

January 1, 2028 to December 31, 2029, respectively. 

(2) For the final period, EGUs must have emission standards 

that have schedules of compliance for each two calendar years 

starting in 2030 (i.e., January 1, 2030 to December 31, 2031, 

January 1, 2032 to December 31, 2033, January 1, 2034 to 

December 31, 2035, etc.). 

(3) Schedules of compliance for interim step 1, 2, 3 and 

the final period may take forms shorter than the applicable 3 or 

2 calendar years specified in paragraphs (1) or (2) as long as 

those schedules of compliance collectively end on the same 

schedule as the interim steps and final periods. 
Page 1209 of 1275

(d) If your plan includes state measures in lieu of or in 

addition to emission standards for affected EGUs regulated under 

the plan then the state measures must include the compliance 

periods for affected EGUs listed in (c)(1) through (3). 

§ 60.5775 What emission standards must I include in my plan? 

(a) Emission standard(s) for affected EGUs under your state 

plan must be quantifiable, verifiable, non-duplicative, 

permanent, and enforceable with respect to each affected EGU. 

The plan shall 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 
Page 1210 of 1275

unless it is replaced by another emission standard in an 

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 is 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 and the state maintain the ability to 

enforce violations and secure appropriate corrective actions 

pursuant to sections 113(a) through (h) of the Act, 42 U.S.C. §§ 

7413(a)-(h), and states and other third parties maintain the 

ability to enforce against violations and secure appropriate 

corrective actions pursuant to section 304 of the Act, 42 U.S.C. 

§ 7604. 

(g) Your plan must ensure that if an affected EGU does not 

meet its emission standard because it did not meet the emissions 

standard based on its stack emissions and generation alone and 

it did not obtain sufficient qualifying ERCs to meet its 
Page 1211 of 1275

emission standard by July 1 following the relevant compliance 

period, it may be subject to federal enforcement pursuant to 

Sections 113(a) – (h), 42 U.S.C. §§ 7413(a)-(h), and Section 304 

of the Clean Air Act, 42 U.S.C. § 7604, and the United States, 

states, and other persons have the ability to enforce violations 

and secure corrective actions. 

(i) In addition to any other recourse provided in Sections 

113 (a) – (h) or Section 304 of the Clean Air Act, 42 U.S.C. §§ 

7413(a)-(h), 7604, for each compliance period in which an 

affected EGU does not meet its CO2 emission standard, it will be 

required to retire 2 times the number of ERCs that would have 

brought it into compliance with its CO2 emission standard, and it 

must retire them by the end of the compliance period immediately 

following the compliance period in which it did not meet its CO2 

emission standard. 

(ii) Failure to retire these replacement ERCs is an 

additional violation that may be subject to federal enforcement. 

(h) If an affected EGU obtained sufficient facially valid 

ERCs to meet its emission standard as specified in (a), but 

those ERCs were found to be invalid, it may be subject to 

federal enforcement as specified in (g). 

(i) For purposes of determining the number of days of 

violation for calculation of civil penalties and other relief, 

if an affected EGU does not meet its emission standard for a 
Page 1212 of 1275

compliance period, each day in the compliance period constitutes 

a day in violation. For a two calendar year compliance period, 

the number of days in violation is 730 or 731 days. For a three 

calendar year compliance period, the number of days in violation 

is 1,095 or 1,096 days 

§ 60.5780 What state measures may I include in support of my 

plan? 

 (a) You may include state measures in support of your plan 

that are not emission standard(s) on affected EGU’s, provided 

those state measures meet the following requirements:

(1) Each state measure is quantifiable, verifiable, nonduplicative, permanent, and enforceable with respect to each 

affected entity (which may be, but is not limited to, an 

affected EGU), and your plan supporting materials includes the 

methods by which each state measure meets each of the following 

requirements in paragraphs (i) through (v) of this subpart. 

(i) A state measure is quantifiable with respect to an 

affected entity if it can be reliably measured, in a manner that 

can be replicated. 

(ii) 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. 
Page 1213 of 1275

(iii) 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. 

(iv) 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 their CO2 emission performance 

rates. 

(v) A state measure is enforceable against an affected 

entity if: 

(A) A technically accurate limitation or requirement and 

the time period for the limitation or requirement is specified; 

(B) Compliance requirements are clearly defined; 

(C) The affected entities responsible for compliance and 

liable for violations can be identified; 

(D) Each compliance activity or measure is enforceable as a 

practical matter; and 

(E) The state maintains the ability to enforce violations 

and secure appropriate corrective actions. 
Page 1214 of 1275

(b) If you include a rate-based ERC trading program as part 

of your state measures, the documentation supporting your 

submittal must show that your state regulations include all of 

the same requirements as those specified in § 60.5791 through § 

60.5797 and any other applicable requirements that a state would 

need to include in a rate-based ERC trading program approvable 

as part of a plan. 

§ 60.5785 What is the procedure for revising my plan? 

(a) Plans can only be revised with approval by the 

Administrator. The Administrator will approve a plan revision if 

it is satisfactory with respect to the applicable requirements 

of this subpart and any applicable requirements of subpart B of 

this part, including the requirement in § 60.5745(a)(3) to 

demonstrate achievement of the CO2 emission performance rates in 

§ 60.5815. 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 § 60.5815, 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: 
Page 1215 of 1275

(1) Addressing data corrections to state goal, which result 

in no more than a 2 percent change in the state goal; and 

(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 submits a notification according to 

section § 60.5830(d) indicating an exceedance of 10 percent or 

greater of a CO2 emission performance rate or CO2 emission goal 

you must revise your state plan to include corrective measures 

to be implemented. The corrective measures must ensure future 

achievement of the CO2 emission performance rates or state CO2

emission goal and achieve additional emission reductions to 

offset any emission performance deficiency that occurred during 

an exceeded interim step(s) or final period(s). The state must 

submit the revised plan to the EPA within 24 months after 

submitting the state report required in section § 60.5830(a) 

indicating the exceedance in lieu of the requirements of § 60.28 

(a). 

(d) You may apply to have a short–term modification to a 

plan to respond to any instances that can be characterized as a 

reliability safety valve issue without needing to go through the 

full state plan revision process if the state provides proper 

notification to the EPA. The short term modification, if 

approved allows modification to emission standards for an 
Page 1216 of 1275

affected EGU or EGUs so that for a maximum of 90 days, the EGU 

or EGUs may operate at an emission standard that is above the 

emission standard specified in the relevant plan. However, you 

must ensure in your submittal that the CO2 emission performance 

rates or the state CO2 emission goal will still be achieved. 

(1) To request this short-term modification you must submit 

a notification to the EPA including: 

(i) A full description of the reliability concern and why 

the affected EGU (or EGUs) needs to operate under modified 

emission standards from those originally required in the plan; 

(ii) A description of how it is coordinating or will 

coordinate, with relevant planning authorities to alleviate the 

problem in an expedited manner; 

(iii) A written concurrence from the relevant planning 

authority supporting the temporary modification request or an 

explanation of why this kind of concurrence cannot be provided; 

and 

(iv) Additional information with respect to whether or not 

the relevant planning authority has conducted a system-wide or 

other analysis of the reliability safety valve concern. 

(2) If the short term modification is approved then at the 

end of modification period, of 90 days or less, you must submit 

a notification to the EPA including: 

(i) Whether the reliability concern has been addressed; 
Page 1217 of 1275

(ii) Whether you are requiring the affected EGU, or EGUs, 

to meet the original emissions standards in the state plan 

approved prior to the short-term modification going forward; 

(iii) How the CO2 emission performance rates or state CO2 

emission goals will be met going forward and enumerate how it 

will make up for any emission reductions that were lost during 

the safety valve period; and 

(iv) If there still is a serious, ongoing reliability 

issue, then you must provide to the EPA a notice that you will 

be submitting a state plan revision according to paragraph (a) 

of this section. 

§ 60.5790 What must I do to meet my plan obligations? 

(a) To meet your plan obligations by requiring either 

emission standards or state specific measures on your affected 

EGUs as specified in § 60.5740, you must demonstrate your 

affected EGUs are complying with their CO2 emission performance 

rates or state specific CO2 emission goals using the procedures 

in paragraphs (b), (c) and (d) of this section. If your plan 

requires the use of Emission Rate Credits (ERCs) for your 

affected EGUs to comply with their emission standards you must 

follow the requirements under paragraph (e). 

(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 
Page 1218 of 1275

emission budget and related compliance requirements and 

mechanisms. These requirements must include: 

(1) CO2 emission monitoring, reporting, and recordkeeping 

requirements for affected EGUs; 

(2) Provisions for state allocation of allowances; 

(3) Provisions for tracking of allowances, from issuance 

through submission for compliance; and 

(4) The process for affected EGUs to demonstrate compliance 

(allowance “true-up” with reported CO2 emissions). 

(c) If you submit a plan that sets rate-based emission 

standards on your affected EGUs, to meet the requirements of § 

60.5775, you shall require the affected EGUs covered by your 

plan to demonstrate compliance with its emission standard by 

factoring stack emissions and any qualifying ERCs into the 

following equations: 

ைଶ஼ܯ ∑ 	 ൌ ݁ݐܽݎ	݊݋݅ݏݏ݁݉݅	݈݅ܽ݊ܿ݁݌݉݋ܿଶܱܥ	

஼ாோ	ܹ݄ܯ	 ∑ ൅	 ௣௢ܹ݄ܯ ∑

Where: 

MCO2 = Measured CO2 mass in units or pounds (lbs) summed 

over the compliance period for an affected EGU. 

MWhop = Total source operation over the compliance period 

for an affected EGU in units of MWh. 

MWhERC = ERC replacement generation for an affected EGU in 

units of MWh. 
Page 1219 of 1275

(d) If you submit a plan that sets rate-based emission 

standards and/or state specific measures on affected EGUs, to 

meet the requirements of § 60.5780, you shall require the 

affected EGUs covered by your plan to demonstrate compliance 

with its emission standard by factoring stack emissions and any 

qualifying Emission Reduction Credits (ERCs) into the equation 

listed in paragraph (c) of this section.

(e) If you want an affected EGU subject to a rate-based 

emission standard (whether under an emission standard 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 § 60.5791 and § 60.5792. 

(f) States may submit a rate-based emission trading program 

with alternative components other than those described in § 

60.5791 through § 60.5797 so long as the submittal 

satisfactorily demonstrates that the trading system and its 

alternative components are at least as stringent in all respects 

as those in § 60.5791 through § 60.5797.

Emission Rate Credit Requirements 

§60.5791 What Emission Rate Credits qualify for use in my state 

plan? 

 (a) An ERC qualifies for the compliance demonstration 
Page 1220 of 1275

specified in §60.5785, and will be considered a valid qualifying 

ERC for the purpose of inclusion in a plan if it meets each of 

the following requirements: 

 (1) It was issued based on energy generated or saved after 

January 1, 2022, from a qualifying ERC generating resource, by a 

state (or it’s state agent) with a qualified state ERC tracking 

system that meets the requirements of section 60.5792 and was 

approved by EPA in its plan; 

 (2) It represents one MWh of energy generated or saved 

(each one MWh can only generate one ERC) from a qualifying ERC 

generating resource with zero associated CO2 emissions (in the 

case of a qualifying ERC generating resource that emits a 

fractional MWh, aggregation to one MWh is required); 

 (3) It has a unique serial number, where the serial number 

must begin with the two digit postal abbreviation of the state 

in which it was issued and be followed by an identification 

number issued by the state that identifies the location where 

the ERC was generated; 

 (4) Its CO2 emissions have not been transferred outside the 

ERC; 

 (5) It is and has been owned by only one person at one 

time; 

 (6) It exists in only one account on a qualified state or 

EPA ERC tracking system; and 
Page 1221 of 1275

 (7) It was issued to a qualifying ERC generating resource 

that is located in a state whose affected EGUs are subject to 

rate-based emission standards or state measures pursuant to this 

regulation, unless the qualifying ERC generating resource is 

located in a state with mass-based emission standards and the 

qualifying ERC generating resource has a power purchase 

agreement or contract for delivery of its generation into a 

state whose affected EGUs are subject to rate-based emission 

standards or state measures pursuant to this regulation. 

 (b) Nothing in paragraph (a) of this section precludes an 

ERC from representing other environmental attributes, in 

addition to its CO2 emission. 

 (c) An ERC may be transferred bundled together with an 

underlying MWh of energy generated that it was based on or 

unbundled from it; however, only the ERC and not the underlying 

MWh of energy (whether bundled or unbundled) may be used for 

purpose of compliance with this regulation. 

 (d) Any ERC that does not meet the requirements of this 

subpart cannot be used in the compliance demonstration required 

under section 60.5785 and is consequently an invalid ERC. 

§ 60.5792 How can an affected EGU use an ERC for demonstrating 

compliance? 

 (a) An ERC may be used in the compliance demonstration 

specified in § 60.5785 if: 
Page 1222 of 1275

 (1) It meets the requirements of § 60.5791 and this 

subpart; 

 (2) It is surrendered only once by one affected EGU for 

purpose of compliance with this regulation in accordance with § 

60.5793 (e); and 

 (3) It is retired through a qualified state ERC tracking 

system that meets the requirements of § 60.5793, or through an 

EPA ERC tracking system. 

 (b) An ERC may not be used in the compliance demonstration 

specified in § 60.5785 if any state has used that same ERC for 

purposes of demonstrating achievement of its state measures. 

 (c) An affected EGU subject to an emission standard is 

prohibited from including ERCs that were generated from an 

activity, project or program in a state with affected EGUs 

subject to mass-based emission standards in its compliance 

demonstration required under § 60.5785, unless the requirements 

of § 60.5791(a)(7) are met. 

 (d) Provided it only surrenders an ERC for retirement once, 

an affected EGU can retire the same ERC for compliance with this 

regulation and for compliance with other state and local 

requirements. An affected EGU cannot retire an ERC for its 

compliance with this regulation and transfer the ERC to another 

entity for compliance with a state or local requirement. 

§ 60.5793 What is a qualified state ERC tracking system? 
Page 1223 of 1275

 (a) A qualified state ERC tracking system must meet each of 

the requirements of paragraphs (b) through (n). 

 (b) Basic Functions. A qualified state ERC tracking system 

is a system that electronically issues and/or accepts, tracks, 

transfers, and retires ERCs that meet the requirements of § 

60.5791 and the remainder of this subpart. 

 (c) Account structure. A qualified state ERC tracking 

system must include accounts for the types of uses listed in 

paragraphs (c)(1) through (3) of this section. 

 (1) A general use account, which affected EGUs, qualifying 

ERC generating resources, and any other person may establish an 

account for holding and trading ERCs. 

 (2) A surrender account, into which affected EGUs will 

place ERCs intended for use in compliance with an emission 

standard or state measure, and from which the ERCs will be 

retired for purpose of compliance with a plan. 

 (3) A retirement account, into which the qualified state 

ERC tracking system will place all ERCs retired for purpose of 

compliance with this regulation. 

 (d) ERC eligibility, generation and issuance. A qualified 

state ERC tracking system must meet the requirements in 

paragraphs (d)(1) through (6) for ERC issuance. 

 (1) Registration. A qualifying ERC generating resource 

registers with the qualified state ERC tracking system pursuant 
Page 1224 of 1275

to the requirements of paragraph (l) of this section, and an 

independent third party verifier registers with the qualified 

ERC tracking system pursuant to the requirements of paragraph 

(m) of this section. 

 (2) Eligibility approval. A qualifying ERC generating 

resource submits to the qualified ERC tracking system an EM&V 

eligibility application that is consistent with EPA’s minimum 

criteria set forth in § 60.5795. An independent third party 

verifier that meets the requirements of § 60.5797 reviews the 

EM&V eligibility application and certifies, in a verification 

assurance plan that meets the requirements of §60.5796 that the 

particular activity, project, or program covered by the EM&V 

eligibility application that is consistent with EPA’s minimum 

criteria set forth in § 60.5795. The state or its state agent 

approves the eligibility of the particular activity, project, or 

program covered by the EM&V eligibility application to generate 

ERCs for use in compliance with this regulation. 

 (3) Registration and eligibility approval may occur at the 

same time as submission of the first post-project EM&V report or 

in advance of it. 

 (4) ERC issuance. 

 (i) Following implementation of the particular activity, 

project or program specified in paragraph (d)(1) of this 

section, an affected EGU or qualifying ERC generating resource 
Page 1225 of 1275

submits to the qualified state ERC tracking system a postproject EM&V report that is consistent with EPA’s minimum 

criteria set forth in § 60.5795 and reports the MWh of energy 

generation or energy savings attributable to the activity, 

project or program over the specific period and as covered by 

the EM&V plan. Such EM&V plans must be submitted no less 

frequently than annually for a particular activity, project or 

program. 

 (ii) An independent third party verifier that meets the 

requirements of § 60.5797 reviews the post-project EM&V report 

and provides a verification assurance plan that meets the 

requirements of § 60.5796. Such verification assurance plans 

shall be submitted on the same periods as the EM&V reports that 

they verify, which according to paragraph (d)(4)(i) must be no 

less frequently than annually for a particular activity, project 

or program. 

 (iii) The state or its state agent reviews the post-project 

EM&V report and verification assurance plan and any other 

credible evidence, ensures that the EM&V report and verification 

assurance plan meet the requirements of § 60.5795 and § 60.5796, 

determines the number of ERCs that were generated (if any) 

during the specific period covered by the EM&V plan, and issues 

a corresponding amount of ERCs into the generation account of 

the affected EGU or qualifying ERC generating resource. 
Page 1226 of 1275

 (5) Frequency of ERC issuance. A qualified state ERC 

tracking system shall issue ERCs no less frequently than on an 

annual basis (i.e., issuance on a shorter basis, such as 

quarterly or biannual issuance is permissible). 

 (6) Each EM&V report and verification assurance plan shall 

be submitted on forms and using procedures specified by the 

plan. 

 (e) Surrender of ERCs. A qualified ERC tracking system must 

ensure that an affected EGU will place ERCs intended for use in 

compliance with a plan and sufficient for its compliance 

demonstration in § 60.5785 in its surrender account prior to the 

applicable compliance date, and once an ERC is placed in a 

surrender account, the affected EGU will not be able to remove 

the ERC from the account. 

 (f) Retirement of ERCs. A qualified ERC tracking system 

must retire any ERCs placed in surrender accounts by the 

compliance date for the affected EGUs pursuant to its plan and 

ensure that, once an ERC is retired, the ERC shall no longer be 

transferable to another account on that tracking system or any 

other tracking system. 

 (g) ERC Transfers. 

 (1) Transfers to/from other qualified ERC tracking systems. 

A qualified ERC tracking system may accept into its tracking 

system ERCs from another qualified ERC tracking system and may 
Page 1227 of 1275

preclude such transfers. 

 (2) Transfers to/from an EPA ERC tracking system. To 

transfer ERCs to/from an EPA CPP ERC tracking system, the 

qualified state ERC tracking system must be registered for such 

use by the EPA. 

 (h) ERC Adjustment. A qualified ERC tracking system has at 

least the following mechanisms in place to make adjustments to 

the number of qualifying ERCs issued, after generation or 

savings data is reported to it, and after the ERCs were issued, 

as data from the prior period are finalized: 

 (1) Any prior period adjustments must be reported to the 

qualified ERC tracking system by the appropriate reporting 

entity as soon as possible, with the reason for the adjustment 

specified and data in support of the adjustment provided. 

 (2) If qualifying ERCs have not yet been created for the 

original generation amount to which the adjustment applies, the 

credit or debit adjustment will be reflected in the number of 

qualifying ERCs issued in the current period. 

 (3) If qualifying ERCs have been created, the credit or 

debit adjustment will be treated as an adjustment to the number 

of qualifying ERCs issued to the qualifying affected EGU or ERC 

generating resource in the prior period. 

 (i) Mechanism to halt issuance. A qualified ERC tracking 

system has mechanisms in place to temporarily or permanently 
Page 1228 of 1275

halt issuance of specific ERCs, to remove specific ERC 

generating resources from its tracking system, and/or to reject 

the transfer of ERCs that do not meet the requirements of § 

60.5791. 

 (j) ERC Information. A qualified ERC tracking system must 

track, at a minimum, the information in paragraphs (j)(1) 

through (14) of this section. 

 (1) The ERC tracking system from which the ERC is issued. 

 (2) Account holder name and identification number of ERCs. 

 (3) Qualifying ERC generating resource facility 

identification number, name, state, and contact information 

including street address, mailing address, phone number, and 

email. 

 (4) Type of qualifying ERC generating resource according to 

the definition in section § 60.5840. 

 (5) Date the affected EGU or qualifying ERC generating 

resource commenced generation or saving of energy. 

 (6) Eligibility of ERCs from qualifying ERC generating 

resource for compliance with this regulation 

 (7) Quantity of ERCs and fractional roll over ERCs for use 

in subsequent compliance periods. 

 (8) Unique ERC serial numbers. 

 (9) Vintage of ERCs, with last quarter and year of 

generation contributing to an accumulated MWh recorded. 
Page 1229 of 1275

 (10) Parties to each ERC trade, and dates of each ERC 

trade. 

 (11) Date an ERC was surrendered. 

 (12) Date an ERC was retired. 

 (13) In the case of a qualifying ERC generator that is 

producing electrical output for use on a utility grid, the 

following must be included: 

 (i) The qualifying ERC generating resource generation 

classification according to the following (if applicable): 

 (A) Generation reported by a control area operator on a 

unit-specific basis; 

 (B) Small wholesale generation; 

 (C) Wholesale generation also serving on-site loads; or 

 (D) Customer-sited distributed generation. 

 (ii) The data reporting entity type and identity of 

specific entity (e.g., control area operator, self-reporting). 

 (iii) The maximum electrical generator nameplate capacity 

in MW; 

 (iv) Information on whether multiple qualifying ERC 

generating resource generating units are aggregated under one 

meter 

 (14) In the case of a qualifying energy saving activity, 

you must have sufficient tracking requirements for 

quantification of the MWh of energy saved. 
Page 1230 of 1275

 (k) Reports. A qualified ERC tracking system provides at 

least the following reports: 

 (1) EGU Reports. A qualified ERC tracking system commits to 

provide the ability for each ERC holder to obtain reports of 

their account activity that includes the information specified 

in paragraph (e) of this section on at least an annual basis, 

and provides the ability for each ERC holder to obtain such 

reports for a period of at least 5 years from the date of ERC 

retirement. 

 (2) Public Reports. A qualified ERC tracking system shall 

provide electronic, internet-based access to the following 

reports to the public: all registered account holders on the 

qualified state ERC tracking system, all registered generators 

on the qualified state ERC tracking system, all qualifying ERC 

generating resource EM&V plans, all independent third party 

verifiers, all verification assurance plans, all ERC issuances, 

all annual aggregate ERC activity statistics on at least an 

annual basis (issuance of ERCs, trades within the qualified 

state ERC tracking system, transfers in or out of the qualified 

state ERC tracking system, and retirements for purpose of this 

regulation on the qualified state ERC tracking system). The 

qualified state ERC tracking system shall provide this 

functionality for as long as this regulation is effective. 

 (3) EPA and state regulator reports. A qualified state ERC 
Page 1231 of 1275

tracking system shall provide the ability for the EPA and state 

regulators to obtain electronically a report that contains 

comprehensive information regarding all ERCs issued, traded or 

retired by the qualified state ERC tracking system for purpose 

of compliance with this regulation, sortable by each of the 

fields listed paragraph (j) of this section. The qualified state 

ERC tracking system shall provide this functionality for as long 

as this regulation is effective. 

 (l) Qualifying ERC generating resource registration 

requirements. Prior to issuing ERCs from an affected EGU or 

qualifying ERC generating resource for purpose of compliance 

with this regulation, a qualified state ERC tracking system 

shall enter an agreement with the owner or operator of that 

qualifying ERC generating resource that provides for each of the 

following: 

 (1) Reporting of 100 percent of the qualifying ERC 

generating resource’s electrical generation or energy savings to 

that qualified state ERC tracking system; 

 (2) Annual certification by the owner or operator of the 

qualifying ERC generating resource that it is registered with 

only one tracking system for issuance of ERCs, and is eligible 

to generate ERCs in compliance with § 60.5791; 

 (3) In the case of a qualifying energy ERC generator annual 

submission of a copy of the qualifying ERC generating resource’s 
Page 1232 of 1275

U.S. Energy Information Agency’s Annual Electric Generator 

Report Form EIA-860 to the qualified state ERC tracking system, 

or, if the qualifying ERC generating resource generates less 

than 1 MW/year, annual submission of registration data that 

would be included on a Form EIA-860 if that entity was required 

to submit Form EIA-860, 

 (4) Collection of data in accordance with any approved EM&V 

plan. 

 (5) In the case of a qualifying energy ERC generator, 

regular inspection of any meters according to appropriate 

industry protocols to ensure proper operation of the meter, 

 (6) Random inspections and audits of the qualifying ERC 

generating resource by an independent third party verifier that 

meets the requirements of § 60.5797, 

 (7) Notification of the qualified state ERC tracking system 

by the owner or operator of the qualifying ERC generating 

resource of any change in qualifying ERC generating resource 

ownership, and the date on which the change occurred, no later 

than 30 days after the sale closes. 

 (m) Independent third party verifier registration 

requirements. Prior to issuing ERCs based on a verification 

assurance plan by an independent third party verifier for 

purpose of compliance with this regulation, a qualified state 

ERC tracking system shall enter an agreement with the 
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independent third party verifier that requires the verifier to 

register with the qualified state ERC tracking system, and meet 

the requirements of § 60.5797 and § 60.5796 of this subpart. 

 (n) Periodic audits of independent third party verification 

assurance plans. You must audit the qualified ERC tracking 

system no less frequently than annually of the content of a 50 % 

of the verification assurance plans and of at least 50 % of its 

independent third party verifiers]. Each independent third party 

verifier registered with its qualified state ERC tracking system 

shall be audited at least once every 3 years. 

 (1) You, the state must maintain the power to disaccredit 

or prohibit the use of any specific independent third party 

verifier in verification work pursuant to this regulation. 

§ 60.5795 What are the requirements for EM&V plans?

 (a) General EM&V plan and report criteria. A qualifying ERC 

must be quantified based on energy generation or energy savings 

from a specific activity, project or program by a qualifying ERC 

generating resource that is quantified and verified as described 

in an EM&V plan or report that meets the requirements for that 

activity, project or program category set forth in § 60.5791, 

meets credible and appropriate industry-standard practices and 

guidance documents, and that meets the requirements of this 

section. 

 (b) Each EM&V plan or report must describe the specific 
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activity, project or program and identify its location(s) and 

year(s) of installation and subsequently provide notice of any 

of the following: 

(1) A change in energy generation or savings capability of 

the qualifying ERC generating resource, and the date on which 

the change occurred, no later than 30 days from when the change 

is implemented, 

(2) A change to any of the essential generating or savings 

characteristics of the qualifying ERC generating resource, where 

essential generating characteristics shall mean any 

characteristics that affect the eligibility of the qualifying 

ERC generating resource for purpose of compliance with this 

regulation, including the type of qualifying ERC generating 

resource, and the date of the change. 

(c) Each EM&V plan or report must describe how the MWh 

associated with each ERC addressed in that plan or report will 

be quantified and verified, and each ERC must be quantified and 

verified based on ex-post energy generation or energy savings. 

(d) Criteria for a qualifying energy generating resource 

with a nameplate capacity of 10 kW or more and for a qualifying 

energy generating resource with a nameplate capacity of less 

than 10 kW for which metered data are available. For a 

qualifying energy generating resource with a nameplate capacity 

of 10 kW or more, or for a qualifying energy generating resource 
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with a nameplate capacity of less than 10 kW for which metered 

data are available, to generate ERCs, its EM&V plan and EM&V 

reports must demonstrate that the requirements in paragraphs 

(d)(1) through (6) are met. 

(1) The generation data was physically measured using a 

revenue-quality meter, which shall mean a meter used by a 

control area operator for financial settlements, or a meter that 

meets the American National Standards Institute No. C12.20., 

Code for Electricity Metering, metering accuracy standards, or a 

meter that meets an alternative equivalent standard that has 

been approved in advance of its use to measure generation for 

purpose of compliance with this regulation by EPA. 

(2) The generating data was measured at the generator’s 

bus bar. 

(3) Data from only one qualifying energy generating 

resource generating unit may be associated with each meter, and 

generation data may not be aggregated, unless the following 

provisions are met: 

(i) All of the generating units have the same essential 

generation characteristics 

(ii) The nameplate capacity of the individual units being 

aggregated is each less than 150 kW, and units collectively do 

not exceed a total nameplate capacity of 1 MW when aggregated, 

and 
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(iii) The generation data are measured by the same type of 

meter. 

(4) The generation data was collected electronically by 

either a MV-90 meter data acquisition system or by pulse 

accumulator readings collected by the control area’s Energy 

Management System and telemetered from the generator to the 

control area operator, and the data was verified through a 

control area energy accounting or settlements process which 

occurs at least monthly. 

(5) The generation data was transmitted by a control area 

operator, and if the control area operator is affiliated with 

the owner or operator of the qualifying energy generating 

resource, a person at the control area operator who is precluded 

from the ability to transfer or retire ERCs issued to that 

generator. 

(6) The generation data serves a load that otherwise would 

have been served by the grid if not for the generator. 

(i) ERCs shall not be issued for energy generation used to 

supply the ancillary equipment used to operate a generating 

station or substation (“station service”) or parasitic load on 

the generator’s side of the point of interconnection. 

(ii) For generators interconnected to transmission systems 

and with on-site loads other than station service drawing 

generation before the metering point, ERCs may be issued for on-
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site load, if the owner or operator of the qualifying energy 

generating resource can demonstrate that the metering used is 

capable of distinguishing between on-site load and station 

service. 

(e) Criteria for a qualifying energy generating resource 

with a nameplate capacity of less than 10 kW. For a qualifying 

energy generating resource with a nameplate capacity of less 

than 10 kW to generate ERCs, its EM&V plan and EM&V reports must 

demonstrate that the following requirements in paragraphs (e)(1) 

though (6) are met. 

(1) Metered data are unavailable. 

(2) At least 1 MW direct current is generated to the 

distribution or transmission system over a continuous 365 day 

period. 

(3) Generation data may not be aggregated, unless the 

following provisions are met: 

(i) The nameplate capacity of the individual units being 

aggregated is each less than 150 kW, 

(ii) The units collectively do not exceed a total nameplate 

capacity of 1 MW when aggregated, 

(iii) All of the generating units have the same essential 

generation characteristics, and 

(iv) The generation data are measured by the same 

generation estimating software or algorithms. 
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(4) Generation data is measured on at least a monthly basis 

using generation estimating software or algorithms that are 

based on an on-site inspection prior to interconnection and a 

resource study (wind, shading, solar irradiance, depending on 

the resource), or engineering information that takes into 

account the size, age, and type of qualifying energy generating 

resource. 

(5) The generation data was self-reported by the qualifying 

energy resource to its distribution utility and to its 

distribution utility through an electronic internet-based portal 

with software that reports total and hourly generation. 

(6) The generation data serves a load that otherwise would 

have been served by the grid if not for the generator. The ERC 

is only based on generation transferred from the qualifying 

energy generating resource to the transmission or distribution 

grid, and is not based on the generation used on-site by the 

customer. 

(f) Criteria for a qualifying demand-side EE. In the case 

of qualifying demand-side EE, the following minimum components 

must be addressed in the EM&V plan or report for the specific 

activity, project or program (depending on the scope covered by 

the EM&V plan or report): 

(1) All demand-side EE savings used to adjust a CO2 

emissions rate must be quantified and verified using applicable, 
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credible, and rigorous industry-standard practices and guidance 

documents. 

(2) All savings values must be which determined and 

reported in units of gross MWh relative to a specified baseline; 

in cases where gross savings values are not available (e.g., 

randomized control trials), net savings can be reported. 

(3) All savings values determined must be determined on a 

regular basis – at intervals sufficient to credibly document 

annual savings – by application of one or more non-control group 

approaches and/or control group approaches. 

 (4) All savings values assessed using deemed savings must 

be documented in a publicly available database and be reviewed 

and updated at least every 3 years. The database must indicate, 

for each value, the conditions for which the value can be 

applied (i.e., climate, building type, and implementation 

mechanism). 

(5) For EE program categories that involve the installation 

of identifiable measures, verification using industry-standard 

techniques is required within the first year of program 

implementation. 

(6) If transmission and distribution losses are quantified, 

the adjustment must be based on the lesser of 6 percent of the 

site-level savings or the calculated statewide annual average 

transmission and distribution loss rate expressed as a 
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percentage and based on values in the most recent year that is 

published in the US EIA State Electricity Profile. For 

transmission and distribution efficiency measures, MWh savings 

from voltage optimization must be calculated on the basis of 

industry-standard protocols and procedures identified in an EM&V 

plan. 

(7) The duration of EE program or project electricity 

savings must be determined using periodic verification 

assessments, industry-standard persistence studies, deemed 

estimates of effective useful life (EUL), or a combination of 

all three. 

(8) If deemed EUL estimates are used for determining the 

duration of savings, then zero savings must be assumed at the 

end of a program, project, or measure life; if project or 

program persistence studies are conducted at least every 5 years 

to determine the duration of savings, then savings can be 

counted as long as the verification activities indicate 

continued measure operation and performance. 

(9) All types of double counting must be considered and 

avoided; documentation of steps taken to avoid double counting 

must be provided in EM&V plans and EM&V reports. 

(g) EM&V plans for demand-side EE must describe and 

document the following: 

(1) The baseline energy usage conditions, with clear 
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documentation and discussion of the rationale, applicability, 

and relevant data sources, protocols, and guidance documents 

used for defining the common practice baseline (CPB). 

(2) The selected EM&V method, associated assumptions, and 

data sources used to quantify savings from demand-side EE. 

(3) How major changes in independent variable conditions 

that affect energy consumption and savings estimates will be 

analyzed. 

(4) How the initial installation of EE will be verified 

within the first year of implementation for EE program 

categories that involve the installation of identifiable 

measures. 

(5) How avoided transmission and distribution system losses 

will be included in EE savings values. 

(6) How the duration of EE program or project electricity 

savings will be determined. 

(7) How the rigor of quantifying MWh savings values will be 

assessed, and the methods used to control the types of bias or 

error relevant inherent to the applied EM&V techniques. 

(8) How double counting will be avoided through the use of 

tracking and accounting procedures to ensure that two or more 

programs do not separately claim savings from the same EE 

project or measure. 

(9) How the relevant protocols, guidelines, and guidance 
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documents will be applied. 

(10) Any additional EM&V information needed to ensure that 

savings from EE programs and projects are credibly quantifiable 

and verifiable 

 (h) EM&V reports for demand-side EE must describe and 

document the following: 

(1) All demand-side EE savings used to adjust a CO2 

emissions rate must be quantified and verified using credible 

and appropriate industry-standard practices and guidance 

documents. 

(2) EM&V reports must document how applicable EM&V criteria 

were applied to quantify results. 

(3) EM&V reports must include after-the-fact documentation 

of how relevant protocols, guidelines, and guidance documents 

were actually applied. 

(4) EM&V report submittals must include any additional EM&V 

information needed to ensure that savings from EE programs and 

projects were quantified and verified. 

(5) At applicable state plan check-in intervals with the 

EPA (in 2025, 2028, and 2030), states applying conventional EM&V 

must provide the EPA with access to applicable program- and 

project-level EM&V reports used to compile total MWh savings and 

generation. 

 (b) In each EM&V plan, the owner or operator of the 
Page 1243 of 1275

affected EGU or qualifying ERC generating resource shall certify 

the following: 

 (1) I certify under penalty of law that I have personally 

examined, and am familiar with, the statements and information 

submitted in this document and all its attachments. Based on my 

inquiry of those individuals with primary responsibility for 

obtaining the information, I certify that the statements and 

information are to the best of my knowledge and belief true, 

accurate, and complete. I am aware that there are significant 

penalties for submitting false statements and information or 

omitting required statements and information, including the 

possibility of fine or imprisonment. 

§ 60.5796 What are the requirements for a post-project ERC 

verification assurance plan? 

 (a) Your plan must ensure that all verification assurance 

plans that verify ERCs shall meet each of the requirements of 

paragraphs (a)(1) through (8) 

 (1) Verify the eligibility of the specific activity, 

project or program described in the particular EM&V plan or 

report for generating ERCs pursuant to this regulation. 

 (2) Verify that the EM&V plan or report meets the 

requirements of § 60.5795. 

 (3) Verify that the activity, project, or program is in 

place and has been implemented in accordance with each specific 
Page 1244 of 1275

element in the EM&V plan or report (e.g., that the installation 

rate is met, that the installation meets quality standards, that 

the measures are operating correctly and have the potential to 

generate anticipated savings) 

 (4) Review any documents required in the EM&V plan or 

report and any documents necessary to verify the MWh generated 

by the qualifying ERC generating resource. 

 (5) Verify any calculations, and the appropriateness of the 

calculation methodology, used to generate credits. 

 (6) For a qualifying ERC energy resource, verify the 

metered data specified in of § 60.5795. 

 (7) For a qualifying ERC energy saving activity, verify 

electricity savings metrics (incremental and cumulative 

savings). 

 (8) Employ an automatic data validity check to ensure that 

all generation or savings data from a qualified ERC generating 

resource is within an acceptable range for that specific 

generator and that erroneous and technically infeasible data is 

not entered. 

 (i) For metered generation, the data validity check shall 

compare reported electricity generation to an engineering 

estimate of the maximum generation potential of the qualified 

renewable energy resource, based on, at a minimum, its maximum 

nameplate capacity in MW and the number of days since the prior 
Page 1245 of 1275

cumulative meter reading was entered in the qualified state ERC 

tracking system. If the data entered exceeds the estimated 

technically feasible generation, the generation will be 

designated “pending” until the reported data and the estimate 

are reconciled. 

 (b) Your plan must ensure that the subject of any 

verification assurance plans, shall not have the opportunity to 

review or influence any draft or final verification assurance 

plans before its submittal to the relevant oversight entity, and 

the independent third party verifier must share any drafts of 

its reports with the relevant oversight entity at the same time 

as it shares them with the subject of the report. 

 (c) Your plan must ensure that in each verification 

assurance plan drafted by an independent third party verifier, 

the verifier shall certify the following: 

 (1) I certify under penalty of law that I have personally 

examined, and am familiar with, the statements and information 

submitted in this document and all its attachments. Based on my 

inquiry of those individuals with primary responsibility for 

obtaining the information, I certify that the statements and 

information are to the best of my knowledge and belief true, 

accurate, and complete. I am aware that there are significant 

penalties for submitting false statements and information or 

omitting required statements and information, including the 
Page 1246 of 1275

possibility of fine or imprisonment. 

§ 60.5797 What standards must the independent third party 

verifier meet? 

 (a) Your plan must ensure that any verification assurance 

plan must be drafted by a person (including any corporate parent 

or subsidiary, any contractors or subcontractors, and the actual 

person) who meets the following: 

 (1) Is a professional engineer or has other appropriate 

technical qualification; 

 (2) Is not an, and is not employed by or receiving payment 

(directly or indirectly) from any, owner or operator of an 

qualifying ERC generating resource (e.g., a renewable energy 

resource, an energy efficiency project, etc.) or an affected 

EGU; 

 (3) Is free from any interest or the appearance of any 

interest in any qualifying ERC generating resource (including 

any role in implementation) or any affected EGU; 

 (4) Has not worked on the development or operation of the 

subject of the verification; 

 (5) Shall not own, buy, sell, or otherwise trade ERCs used 

for compliance with a plan or any other credit reflecting any 

environmental attribute related to the use, generation or saving 

of electricity; 

 (6) Attests, in its verification report, to compliance with 
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the American Evaluation Association requirements for 

verification; and 

 (7) Has not been debarred, suspended, or proposed for 

debarment pursuant to the Government-wide Debarment and 

Suspension regulations, 40 CFR part 32, or the Debarment, 

Suspension and Ineligibility provisions of the Federal 

Acquisition Regulations, 48 CFR part 9, subpart 9.4. 

 (b) Your plan must ensure that any qualified state ERC 

tracking system and any independent third party verifier must 

maintain, for its employees, and must ensure the maintenance of, 

for any parties that it employs, professional liability 

insurance, as defined in 31 C.F.R. 50.5(q), through an insurance 

provider that possess a financial strength rating in the top 

four categories from either Standard & Poor’s or Moody’s, 

specifically, AAA, AA, A or BBB for Standard & Poor’s, and Aaa, 

Aa, A, or Baa for Moody’s. Any entity covered by this paragraph 

shall disclose the level of professional liability insurance 

they possess when entering into contracts to provide 

verification services pursuant to this regulation. 

Applicability of Plans to Affected EGUs

§ 60.5800 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 plan submittal to implement and enforce the 

emission guidelines contained in this subpart by August 31, 

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. 

§ 60.5805 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 commences construction on or before January 8, 

2014. 

(b) An affected EGU is a steam generating unit, integrated 

gasification combined cycle (IGCC), or stationary combustion 

turbine that meets the relevant applicability conditions 

specified in paragraph (b)(1) through (3) of this section. 

(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 20 MW of 

electricity); 
Page 1249 of 1275

(2) Has a base load rating (i.e., design heat input 

capacity) greater than 260 GJ/hr (250 MMBtu/hr) heat input of 

fossil fuel (either alone or in combination with any other 

fuel); and 

(3) Stationary combustion turbines that meet the definition 

of either a combined cycle or combined heat and power combustion 

turbine. 

§ 60.5810 What affected EGUs are exempt from my state plan? 

 (a) Affected EGUs that are exempt from your plan include: 

(1) EGUs that are subject to subpart TTTT as a result of 

commencing construction after the subpart TTTT applicability 

date; and those subject to subpart TTTT as a result of 

commencing modification or reconstruction; 

 (2) Steam generating units and IGCC units that are 

currently and always have been subject to a federally 

enforceable permit limiting annual net-electric sales to onethird or less of its potential electric output or 219,000 MWh or 

less; 

 (3) Stationary combustion turbines not capable of 

combusting natural gas (e.g., not connected to a natural gas 

pipeline) 

(4) Your EGU is capable of combusting 50 percent or more 

non-fossil fuel and subject to a federally enforceable permit 
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limiting, or has historically limited, fossil fuel use to 10% or 

less of the annual capacity factor; 

(5) EGUs that are a combined heat and power unit that is 

subject to a federally enforceable permit limiting, or has 

historically limited, 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. 

§ 60.5815 What are the CO2 emissions performance rates for 

affected EGUs? 

(a) You must require, in your plan, affected EGUs to meet 

CO2 emission performance rates listed in table 1 of this subpart 

except as provided in paragraph (b) of this section. 

(b) You may elect to demonstrate that affected EGUs are 

meeting their CO2 emission performance rate by achieving 

statewide emission goals which are equivalent and no less 
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stringent than the CO2 emission performance rates listed in table 

1. Your equivalent statewide CO2 emission goals may take the 

following forms: 

(1) Average statewide rate-based CO2 emission goals listed 

in table 2 of this subpart, except as provided in paragraph (c) 

and (d); or 

(2) Cumulative statewide mass-based CO2 emission goals 

listed in table 3 of this subpart, except as provided in 

paragraph (c) and (d). 

(c) If your plan incorporates CO2 emission goals listed in 

paragraphs (b)(1) or (2) of this section you may elect to 

develop your own interim step goals if you do not wish to adopt 

the interim step goals provided in paragraph (b)(1) or (b)(2). 

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. 

 (3) The initial and final CO2 emission goals that you elect 

to achieve in your plan may take different forms between the 

interim period and final period (e.g., a rate-based goal for the 
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interim period and a mass-based goal for the final period), 

however, the form of a state CO2 emission goal in your plan may 

not be changed once a relevant period has begun. 

 (d) Your plans interim period and final period CO2 emission 

goals included in a plan that your state or states elects to 

achieve may be changed in the plan only according to situations 

listed in paragraphs (d)(1) and (2) of this section. If a 

situation requires a plan revision you must follow the 

procedures in § 60.5785 to submit a plan revision. 

(1) If your plan implements CO2 emission goals for your 

affected EGUs to meet, you may submit state plan revisions to 

make corrections to your state goal, which result in no more 

than a 2 percent change in the state goal; 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. 

§ 60.5820 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 that what is described in (a)(1) 

through (6) of this section. 

(1) The owner of operator of an affected EGU required to 

meet a rate based emission standard they must prepare a 
Page 1253 of 1275

monitoring plan in accordance with the applicable provisions in 

§ 75.53(g) and (h) of this chapter. 

(2) The owner or operator of an affected EGU must measure 

the hourly CO2 mass emissions from each affected unit using the 

procedures in paragraphs (a)(2)(i) through (v) of this section, 

except as provided in paragraph (a)(3) of this section. 

(i) The owner or operator of an affected EGU must install, 

certify, operate, maintain, and calibrate a CO2 continuous 

emissions monitoring system (CEMS) to directly measure and 

record CO2 concentrations in the affected EGU exhaust gases 

emitted to the atmosphere and an exhaust gas flow rate 

monitoring system according to § 75.10(a)(3)(i) of this chapter. 

If the owner or operator of an affected EGU measures CO2

concentration on a dry basis, they must also install, certify, 

operate, maintain, and calibrate a continuous moisture 

monitoring system, according to § 75.11(b) of this chapter. 

(ii) For each monitoring system the owner or operator uses 

to determine the CO2 mass emissions from an affected EGU uses, 

the monitoring system must meet the applicable certification and 

quality assurance procedures in § 75.20 of this chapter and 

Appendices B and D to part 75 of this chapter. 

(iii) The owner operator of an affected EGU must use only 

unadjusted exhaust gas volumetric flow rates to determine the 

hourly CO2 mass emissions from the affected facility; the owner 
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or operator of an affected EGU must not apply the bias 

adjustment factors described in section 7.6.5 of Appendix A to 

part 75 of this chapter to the exhaust gas flow rate data. 

(3) The owner or operator of an affected EGU may determine 

site-specific carbon-based F-factors (Fc) using Equation F-7b in 

section 3.3.6 of appendix F to part 75 of this chapter, and may 

use these Fc values in the emissions calculations instead of 

using the default Fc values in the Equation G-4 nomenclature. 

(4) 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. 

(5) In accordance with § 60.13(g), if two or more affected 

EGUs implementing the continuous emissions monitoring provisions 

in paragraph (a)(2) of this section share a common exhaust gas 

stack and are subject to the same emissions standard, the owner 
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or operator may monitor the hourly CO2 mass emissions at the 

common stack in lieu of monitoring each EGU separately. If an 

owner or operator of an affected EGU chooses this option, the 

hourly net electric output for the common stack must be the sum 

of the hourly net electric output of the individual affected 

facility and the operating time must be expressed as “stack 

operating hours” (as defined in § 72.2 of this chapter). 

(6) In accordance with § 60.13(g), if the exhaust gases 

from an affected EGU implementing the continuous emissions 

monitoring provisions in paragraph (a)(2) of this section are 

emitted to the atmosphere through multiple stacks (or if the 

exhaust gases are routed to a common stack through multiple 

ducts and you elect to monitor in the ducts), the hourly CO2 mass 

emissions and the “stack operating time” (as defined in § 72.2 

of this chapter) at each stack or duct must be monitored 

separately. In this case, the owner or operator of an affected 

EGU must determine compliance with an applicable emissions 

standard by summing the CO2 mass emissions measured at the 

individual stacks or ducts and dividing by the net energy output 

for the affected EGU. 

(b) The owner or operator of an affected EGU must maintain 

records, as required by a plan, for at least 5 years following 

the date of each compliance period, occurrence, measurement, 

maintenance, corrective action, report, or record. 
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(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, occurrence, measurement, maintenance, 

corrective action, report, or record, 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 § 60.5790. 

(ii) Copies of all reports submitted to the state under 

paragraph (c) of this section. 

(iii) Data that is required to be recorded by 40 CFR Part 

75 Subpart F. 

(iv) Data with respect to any ERCs (if applicable) 

including the information in paragraphs (b)(2)(iv)(A) through 

(C) of this section. 

(A) All correspondence and other commercial documents 

related to any ERC transactions that involved qualifying ERCs 

and any EM&V plans related to those ERCs. 

(B) All independent third party verifier verification 

assurance plans. 
Page 1257 of 1275

(C) All records and reports relating to the surrender and 

retirement of ERCs for compliance with this regulation, and all 

information specified in § 60.5793(j). 

(c) The owner or operator of an affected EGU must include 

in a report required by the plan covering each compliance period 

all hourly CO2 emissions, all hourly net electric output and all 

hourly net energy output measurements for a CHP facility 

calculated from data monitored according to paragraph (a) of 

this section according to the procedures in 40 CFR Part 75 

Subpart G. In addition a plan must require reports to be 

submitted from the EGUs that include the information in 

paragraphs (c)(1) and (2) of this section. 

(1) For each affected EGU’s compliance period, owners and 

operators of affected EGUs must include in their report their 

applicable emission standard calculated as a CO2 emission rate or 

cumulative mass in units of the standard required in § 60.5790. 

(2) If the owner or operator of an affected EGU is 

complying with an emission standard by using ERCs they must 

include in their report a list of all ERC serial numbers retired 

for the compliance period that an affected EGU used to comply 

with an emission standard, and all other information specified 

in § 60.5793(e) of this section. 

(d) The owner or operator of an affected EGU must follow 

any additional requirements for monitoring, recordkeeping and 
Page 1258 of 1275

reporting in a plan that are required under § 60.5785, if 

applicable. 

Recordkeeping and Reporting Requirements 

§ 60.5825 What are my state recordkeeping requirements? 

(a) States must keep records of all plan components, plan 

requirements, supporting documentation, and the status of 

meeting the plan requirements defined in the plan for the 

interim steps 1, 2 and 3 and the interim plan period from 2022-

2029. After 2029 states must keep records of all information 

relied upon in support of any continued demonstration that the 

final emissions goals are being achieved. 

(b) States 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 state 

requirement. 

(c) If a state has a requirement for hourly CO2 emissions 

and net generation information to be used to calculate 

compliance with an annual emissions standard for affected EGUs, 

any information that is submitted by the owners or operators of 

affected EGUs to the EPA electronically pursuant to requirements 

in Part 75 meets the recordkeeping requirement of this section 

and a state is not required to keep records of information that 

would be in duplicate of paragraph (b) of this section. 
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(d) A state must keep records at a minimum for 10 years, 

for the interim period, and 5 years, for the final period, from 

the date the record is used to determine compliance with an 

emissions standard, plan requirement or goal in the interim 

period. 

§ 60.5830 What are my state reporting requirements? 

(a) In lieu of the annual report required under § 60.25 (e) 

and (f) you must report the information in paragraphs (b) 

through (e) 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 (2022-2024) due no later than 

July 1, 2025. The final period reports start with a 2030-2031 

bi-annual report (which is due by July 1, 2032), a 2-calendar 

year average of emissions or cumulative sum of emissions used to 

determine compliance with the final CO2 emission performance rate 

or CO2 emission goal (as applicable). The report must include the 

following: 

(1) 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 

affected EGUs are on schedule to meet the applicable CO2 emission 
Page 1260 of 1275

performance rate or emission goal during the performance periods 

and compliance periods, as specified in the plan. 

(2) 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 or cumulative CO2

emission performance (as applicable) achieved by all affected 

EGUs. 

 (3) All other required information, as specified in your 

state plan according to §60.5740(a)(5). 

(c) If your plan includes state measures, in lieu of or in 

addition to emission standards, than you must submit an annual 

report to the EPA in addition to the reports required under 

paragraph (b) for the interim period. In the final periods you 

must submit bi-annual reports consistent with those required 

under paragraph (b). The annual reports in the interim period 

must be submitted no later than July 1 following the end of each 

calendar year starting with the annual year 2022 (January 1, 

2022 to December 31, 2022). The annual and bi-annual 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 
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(2) You must include information regrinding 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 than you must submit a 

notification in the report required under paragraph (b) of this 

section to the EPA if your affected EGUs exceed a CO2 emission 

performance rate or CO2 emission goal (on average for rate or 

cumulatively for mass) by 10 percent or greater thus triggering 

corrective measures required under your plan. If corrective 

measures are required you must follow the requirements in 

60.5785 for revising your plan to implement the corrective 

measures. 

(e) If your plan includes 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) or this 

section. 

(1) You must submit a notification in the report required 

under paragraph (c) of this section to the EPA if at the end of 

the calendar year your state did not meet a programmatic 

milestone included in your plan submittal. This notification 

must detail the implementation of the backstop required in your 
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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 that the backstop has been 

triggered. 

(2) You must submit a notification in the report required 

under paragraph (b) of this section to the EPA if your affected 

EGUs, at the end of any interim performance step or final 

period, exceed a CO2 emission performance rate or CO2 emission 

goal (on average for rate or cumulatively for mass) by 10 

percent or greater thus triggering the implementation of the 

backstop required in your plan. This notification must detail 

the implementation of the backstop 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 that 

the backstop has been triggered. 

 (f) You must include in your 2029 report (which is due by 

July 1, 2030) the calculation of average emissions or cumulative 

sum of emissions over the 2022-2029 interim period used to 

determine compliance with your interim CO2 emission performance 

rate or emission goal. The calculated value must be in units 

consistent with the approach you set in your plan for the 

interim period. 
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§ 60.5835 How do I submit information required by these Emission 

Guidelines to the EPA?

(a) You must submit to the EPA the information required by 

these emission guidelines following the procedures in paragraphs 

(b) through (e) of this section. 

(b) All negative declarations, state plan submittals, 

supporting materials that are part of a state plan submittal and 

any state reports must be reported through EPA’s State Plan 

Electronic Collection System (SPeCS). Confidential business 

information that is part of an official submittal to EPA must 

also be submitted electronically into the SPeCS. 

(c) Only a submittal by the Governor’s 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 August 31, 2016, 

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 
Page 1264 of 1275

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 shall 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 

components, using a mechanism such as redline/strikethrough. 

These changes are not part of the state plan until formal 

approval by EPA. 

(e) You shall provide the EPA with 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 
Page 1265 of 1275

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 

§ 60.5840 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. 

Annual capacity factor means the ratio between the actual 

heat input to an EGU during a calendar year and the potential 

heat input to the EGU had it been operated for 8,760 hours 

during a calendar year at the base load rating. 

Affected electric generating unit or Affected EGU means a 

steam generating unit, an IGCC facility, or a stationary 

combustion turbine that meets the applicability conditions in 

section § 60.5800. 

Base load rating means the maximum amount of heat input 

(fuel) that an EGU can combust on a steady 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. 

CO2 emission goal means a statewide rate-based CO2 emission 
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goal or mass-based CO2 emission goal specified in § 60.5815. 

Coal means all solid fuels classified as anthracite, 

bituminous, subbituminous, or lignite by the American Society of 

Testing and Materials in ASTM D388 (incorporated by reference, 

see § 60.17), coal refuse, and petroleum coke. Synthetic fuels 

derived from coal for the purpose of creating useful heat, 

including but not limited to solvent-refined coal, gasified coal 

(not meeting the definition of natural gas), coal-oil mixtures, 

and coal-water mixtures are included in this definition for the 

purposes of this subpart. 

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 use a 

steam-generating unit or stationary combustion turbine to 

simultaneously produce both electric (or mechanical) and useful 

thermal output from the same primary energy source. 

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.
Page 1267 of 1275

Design efficiency means the rated overall net efficiency 

(e.g., electric plus thermal output) on a higher heating value 

basis of the EGU at the base load rating and ISO conditions. 

Distillate oil means fuel oils that comply with the 

specifications for fuel oil numbers 1 and 2, as defined by the 

American Society of Testing and Materials in ASTM D396 

(incorporated by reference, see § 60.17); diesel fuel oil 

numbers 1 and 2, as defined by the American Society for Testing 

and Materials in ASTM D975 (incorporated by reference, see § 

60.17); kerosene, as defined by the American Society of Testing 

and Materials in ASTM D3699 (incorporated by reference, see § 

60.17); biodiesel as defined by the American Society of Testing 

and Materials in ASTM D6751 (incorporated by reference, see § 

60.17); or biodiesel blends as defined by the American Society 

of Testing and Materials in ASTM D7467 (incorporated by 

reference, see § 60.17). 

Essential generating characteristics means any 

characteristic that affects the eligibility of the qualifying 

energy generating 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. This may include a regulation or 
Page 1268 of 1275

other legal requirement that includes past, current, and future 

obligations, or current programs and measures that are in place 

and are anticipated to be continued or expanded in the future, 

in accordance with established plans. An existing state program, 

requirement, or measure may have past, current, and future 

impacts on EGU CO2 emissions. 

Fossil fuel means natural gas, petroleum, coal, and any 

form of solid, liquid, or gaseous fuel derived from such 

material for the purpose of creating useful heat. 

Gaseous fuel means any fuel that is present as a gas at ISO 

conditions and includes, but is not limited to, natural gas, 

refinery fuel gas, process gas, coke-oven gas, synthetic gas, 

and gasified coal. 

 Heat recovery steam generating unit (HRSG) means a unit in 

which hot exhaust gases from the combustion turbine engine are 

routed in order to extract heat from the gases and generate 

useful output. Heat recovery steam generating units can be used 

with or without duct burners. 

 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. 
Page 1269 of 1275

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. 

ISO conditions means 288 Kelvin (15o C), 60 percent relative 

humidity and 101.3 kilopascals pressure. 

Liquid fuel means any fuel that is present as a liquid at 

ISO conditions and includes, but is not limited to, distillate 

oil and residual oil. 

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 should be converted into MWh by multiplying it 

by 745.7 then dividing by 1,000,000. 

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 
Page 1270 of 1275

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-electric output means the amount of gross generation 

the generator(s) produce (including, but not limited to, output 

from steam turbine(s), combustion turbine(s), and gas 

expander(s)), as measured at the generator terminals, less the 

electricity used to operate the plant (i.e., auxiliary loads); 

such uses include fuel handling equipment, pumps, fans, 

pollution control equipment, other electricity needs, and 

transformer losses as measured at the transmission side of the 

step up transformer (e.g., the point of sale). 

Net energy output means: 

(1) The net electric or mechanical output from the affected 

facility, plus 100 percent of the useful thermal output measured 

relative to SATP conditions that is not used to generate 

additional electric or mechanical output or to enhance the 

performance of the unit (e.g., steam delivered to an industrial 

process for a heating application). 

(2) For combined heat and power facilities where at least 

20.0 percent of the total gross or net energy output consists of 

electric or direct mechanical output and at least 20.0 percent 

of the total gross or net energy output consists of useful 

thermal output on a 12-operating month rolling average basis, 
Page 1271 of 1275

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). 

Petroleum means crude oil or a fuel derived from crude oil, 

including, but not limited to, distillate and residual oil. 

Qualifying energy generating resource means: 

(1) An affected EGU, 

(2) Electric generating technologies using renewable 

energy resources, such as wind, solar, geothermal, 

hydro, wave, and tidal power, 

(3) Biomass co-firing or repowering, 

(4) Nuclear power, and 

(5) Waste heat power. 

Qualifying energy savings measure means a demand-side 

energy efficiency or demand-side management measure that saves 

electricity and is calculated on the basis of ex poste savings, 

not “projected” or “claimed” savings. 

Qualifying ERC generating resource means a resource or 

measure that may generate ERCs that (a) began generating 

electricity or had a capacity uprate no earlier than January 1, 

2013 (in the case of a qualifying energy generating resource) or 

began saving energy no earlier than January 1, 2013 (in case of 

a qualifying energy saving measure), and (b) is connected to, 
Page 1272 of 1275

and delivers energy to or saves electricity, on the continental 

electric grid in the United States.

Solid fuel means any fuel that has a definite shape and 

volume, has no tendency to flow or disperse under moderate 

stress, and is not liquid or gaseous at ISO conditions. This 

includes, but is not limited to, coal, biomass, and pulverized 

solid fuels. 

Standard ambient temperature and pressure (SATP) 

conditions means 298.15 Kelvin (25o C, 77 oF)) and 100.0 

kilopascals (14.504 psi, 0.987 atm) pressure. The enthalpy 

of water at SATP conditions is 50 Btu/lb. 

State agent means an entity acting on behalf of the state, 

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 
Page 1273 of 1275

turbine, any combined cycle combustion turbine, and any combined 

heat and power combustion turbine based system plus any 

integrated equipment that provides electricity or useful thermal 

output to the combustion turbine engine, heat recovery system or 

auxiliary equipment. Stationary means that the combustion 

turbine is not self-propelled or intended to be propelled while 

performing its function. It may, however, be mounted on a 

vehicle for portability. If a stationary combustion turbine 

burns any solid fuel directly it is considered a steam 

generating unit. 

Steam generating unit means any furnace, boiler, or other 

device used for combusting fuel and producing steam (nuclear 

steam generators are not included) plus any integrated equipment 

that provides electricity or useful thermal output to the 

affected facility or auxiliary equipment. 

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 
Page 1274 of 1275

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. 

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) 

[X] 1290 

Stationary 

combustion turbine 

[X] 780 

Table 2 to Subpart UUUU of Part 60—Statewide Rate-based CO2

Emission Goals (Pounds of CO2 Per Net MWh) 

[Placeholder for table] 
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Table 3 to Subpart UUUU of Part 60—Statewide Mass-based CO2

Emission Goals (Short Tons of CO2) 

[Placeholder for table]